10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2025
	OR
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
	THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from  to

Commission File No. 001-03262

COMSTOCK RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Nevada	94-1667468
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034

(Address of principal executive offices including zip code)

972 668-8800

(Registrant's telephone number and area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, par value $0.50 (per share)	CRK	New York Stock Exchange
		New York Stock Exchange Texas

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes þ No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes ¨ No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer a smaller reporting company or an emerging growth company. See the definitions of "large accelerated filer", "accelerated filer", "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer	þ	Accelerated filer	¨	Non-accelerated filer	¨	Smaller reporting company	¨
Emerging growth company	¨

If an emerging growth company, indicate by check mark if registrant has elected to not use the extended transition period for complying with any new or revised final accounting standards provided pursuant to Section 13(a) of the Exchange Act. Emerging growth company ¨

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. þ

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ¨

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to § 240.10D-1(b). ¨

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).

Yes ¨ No þ

The aggregate market value of the common stock held by non-affiliates of the registrant, based on the closing price of common stock on the New York Stock Exchange on June 30, 2025 (the last business day of the registrant's most recently completed second fiscal quarter), was $2.2 billion. As of February 18, 2026 there were 294,021,740 shares of common stock of the registrant outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Definitive Proxy Statement for the 2026 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission not later than 120 days after

December 31, 2025 are incorporated by reference into Part III of this report.

COMSTOCK RESOURCES, INC.

ANNUAL REPORT ON FORM 10-K

For the Fiscal Year Ended December 31, 2025

CONTENTS

Item		Page
	Cautionary Note Regarding Forward-Looking Statements	2
	Definitions	3
Part I
1.	Business	6
1A.	Risk Factors	23
1B.	Unresolved Staff Comments	30
1C.	Cybersecurity	30
2.	Properties	31
3.	Legal Proceedings	31
4.	Mine Safety Disclosures	31
Part II
5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
6.	[Reserved]	32
7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	33
7A.	Quantitative and Qualitative Disclosures About Market Risk	40
8.	Financial Statements and Supplementary Data	40
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	41
9A.	Controls and Procedures	41
9B.	Other Information	43
9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	43
Part III
10.	Directors, Executive Officers and Corporate Governance	43
11.	Executive Compensation	43
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	43
13.	Certain Relationships and Related Transactions, and Director Independence	43
14.	Principal Accountant Fees and Services	43
Part IV
15.	Exhibits and Financial Statement Schedules	44
16.	Form 10-K Summary	45

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COMSTOCK RESOURCES, INC.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward-looking statements can in some instances be identified by their use of terms such as "expect," "estimate," "anticipate," "project," "plan," "intend," "believe" and similar terms. All statements, other than statements of historical facts, included in this report, are forward-looking statements, including all statements regarding:

•amount and timing of future production of natural gas and oil;

•amount, nature and timing of expected capital expenditures;

•the number of anticipated wells to be drilled after the date hereof;

•the availability of exploration and development opportunities;

•our future financial or operating results;

•our future cash flow and anticipated liquidity;

•future operating costs including lease operating expenses, administrative costs and other expenses;

•finding and development costs;

•our business strategy; and

•other plans and objectives for future operations.

All forward-looking statements are subject to risks and uncertainties that may cause actual results to differ materially from those that are expected and, therefore, you should not unduly rely on such statements. The risks and uncertainties that could cause actual results to differ materially from those expressed or implied by these forward-looking statements include, but are not limited to:

•the risks described in "Risk Factors" and elsewhere in this report;

•the volatility of prices and supply of, and demand for, natural gas and oil;

•the timing and success of our drilling activities;

•the numerous uncertainties inherent in estimating quantities of natural gas and oil reserves and actual future production rates and associated costs;

•our ability to successfully identify; execute or effectively integrate future acquisitions;

•the usual hazards associated with the natural gas and oil industry, including fires, well blowouts, pipe failure, spills, explosions and other unforeseen hazards;

•our ability to effectively market our natural gas and oil;

•the availability of rigs, equipment, supplies and personnel;

•our ability to discover or acquire additional reserves;

•our ability to satisfy future capital requirements;

•changes in regulatory requirements;

•general economic conditions, status of the financial markets and competitive conditions; and

•our ability to retain key members of our senior management and key employees.

These forward-looking statements are made based upon detailed assumptions and reflect management's current expectations and beliefs. While we believe that these assumptions underlying the forward-looking statements are reasonable, we caution that it is very difficult to predict the impact of known factors, and it is impossible for us to anticipate all factors that could affect actual results.

The forward-looking statements included herein are made only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statement as a result of new information, future events, or otherwise, except as required by law.

WEBSITE REFERENCES

In this Annual Report on Form 10-K, we make references to our website at www.comstockresources.com. References to our website through this Form 10-K are provided for convenience only and the content on our website does not constitute a part of, and shall not be deemed incorporated by reference into, this Annual Report on Form 10-K.

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COMSTOCK RESOURCES, INC.

DEFINITIONS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report. Natural gas equivalents and crude oil equivalents are determined using the ratio of six Mcf to one barrel. All references to "us", "our", "we" , the "Company" or "Comstock" mean the registrant, Comstock Resources, Inc. and where applicable, its consolidated subsidiaries.

"Bbl" means a barrel of U.S. 42 gallons of oil.

"Bcf" means one billion cubic feet of natural gas.

"Bcfe" means one billion cubic feet of natural gas equivalent.

"BOE" means one barrel of oil equivalent.

"Btu" means British thermal unit, which is the quantity of heat required to raise the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit.

"Completion" means the installation of permanent equipment for the production of oil or gas.

"Condensate" means a hydrocarbon mixture that becomes liquid and separates from natural gas when the gas is produced and is similar to crude oil.

"Development well" means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

"Dry hole" means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

"Exploratory well" means a well drilled to find a new field or to find a new productive reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

"Gross" when used with respect to acres or wells, production or reserves refers to the total acres or wells in which we or another specified person has a working interest.

"LNG" refers to liquefied natural gas, which is a composition of methane and some mixture of ethane that has been cooled to liquid form for ease and safety of non-pressurized storage or transport.

"MBbls" means one thousand barrels of oil.

"MBbls/d" means one thousand barrels of oil per day.

"Mcf" means one thousand cubic feet of natural gas.

"Mcfe" means one thousand cubic feet of natural gas equivalent.

"MMBbls" means one million barrels of oil.

"MMBOE" means one million barrels of oil equivalent.

"MMBtu" means one million British thermal units.

"MMcf" means one million cubic feet of natural gas.

"MMcf/d" means one million cubic feet of natural gas per day.

"MMcfe/d" means one million cubic feet of natural gas equivalent per day.

"MMcfe" means one million cubic feet of natural gas equivalent.

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COMSTOCK RESOURCES, INC.

"Net" when used with respect to acres or wells, refers to gross acres of wells multiplied, in each case, by the percentage of working interest owned by us.

"Net production" means production we own less royalties and production due others.

"NGL" refers to natural gas liquids, which is composed exclusively of carbon and hydrogen.

"Oil" means crude oil or condensate.

"Operator" means the individual or company responsible for the exploration, development, and production of an oil or gas well or lease.

"Proved developed reserves" means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

"Proved developed non-producing" means reserves (i) expected to be recovered from zones capable of producing but which are shut-in because no market outlet exists at the present time or whose date of connection to a pipeline is uncertain or (ii) currently behind the pipe in existing wells, which are considered proved by virtue of successful testing or production of offsetting wells.

"Proved developed producing" means reserves expected to be recovered from currently producing zones under continuation of present operating methods. This category includes recently completed shut-in gas wells scheduled for connection to a pipeline in the near future.

"Proved reserves" means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided by contractual arrangements.

"Proved undeveloped reserves" means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling locations offsetting productive wells that are reasonably certain of production when drilled or where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

"PV 10 Value" means the present value of estimated future revenues to be generated from the production of proved reserves calculated, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expense and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. This amount is the same as the standardized measure of discounted future net cash flows related to proved natural gas and oil reserves except that it is determined without deducting future income taxes. Although PV 10 Value is not a financial measure calculated in accordance with GAAP, management believes that the presentation of PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our oil and gas properties. Because many factors that are unique to any given company affect the amount of estimated future income taxes, we believe the use of a pre-tax measure is helpful to investors when comparing companies in our industry.

"Recompletion" means the completion for production of an existing well bore in another formation from which the well has been previously completed.

"Reserve life" means the calculation derived by dividing year-end reserves by total production in that year.

"Royalty" means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

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COMSTOCK RESOURCES, INC.

"3-D seismic" means an advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

"SEC" means the United States Securities and Exchange Commission.

"Tcf" means one trillion cubic feet of natural gas.

"Tcfe" means one trillion cubic feet of natural gas equivalent.

"Working interest" means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100% working interest in a lease burdened only by a landowner's royalty of 12.5% would be required to pay 100% of the costs of a well but would be entitled to retain 87.5% of the production.

"Workover" means operations on a producing well to restore or increase production.

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COMSTOCK RESOURCES, INC.

PART I

ITEM 1. BUSINESS

We are a leading independent natural gas producer operating primarily in the Haynesville shale, a premier natural gas basin located in North Louisiana and East Texas with superior economics given its geographical proximity to the Gulf Coast natural gas markets. As of December 31, 2025, substantially all of our proved natural gas and oil reserves were in the Haynesville and Bossier shale plays. We are focused on creating value through the development of our substantial inventory of highly economic drilling opportunities in the Haynesville and Bossier shales and through our exploration activities in our Western Haynesville play. Our common stock is listed and traded on the New York Stock Exchange and New York Stock Exchange Texas under the symbol "CRK".

Our operations are concentrated in Louisiana and Texas. Our natural gas and oil properties are estimated to have proved reserves of 7.0 Tcfe with a PV 10 Value of $4.5 billion as of December 31, 2025 based on SEC prices. Our proved reserves are principally natural gas, which were 41% developed as of December 31, 2025 with an average reserve life of approximately 16 years. Using NYMEX futures market natural gas and oil prices as of December 31, 2025, proved reserves are estimated at 7.2 Tcfe with a PV 10 Value of $5.2 billion. Using these prices, our proved reserves were 40% developed as of December 31, 2025, with an average reserve life of approximately 16 years.

Strengths

High Quality Properties. As of December 31, 2025, we have 1,069,991 acres (802,769 net) prospective for the Haynesville and Bossier shale plays, located in North Louisiana and East Texas, including our extension of the plays in our Western Haynesville area. Our Haynesville/Bossier shale properties have extensive development and exploration potential. Advances in drilling and completion technology have allowed us to increase the reserves recovered through drilling longer horizontal lateral lengths, drilling horseshoe wells and applying substantially improved well stimulations, as well as successfully drilling horizontal wells in our deeper Western Haynesville extension of the Haynesville and Bossier Shale plays. As a result of the improved economic returns, we have focused our development activities primarily on drilling Haynesville and Bossier horizontal wells since 2015.

Our Haynesville and Bossier shale acreage is located in one of the premier North American natural gas basins and has access to the growing natural gas demand in the Gulf Coast markets related to LNG exports, expansion of power generation for data centers and the petrochemical industry due to its geographic proximity. We believe we are well positioned for future growth due to the following:

•Premier natural gas resource. The Haynesville and Bossier shales in our legacy area have been substantially delineated since commercial operations started in 2008 and the consistent and successful results of our first 30 wells in our Western Haynesville area indicate substantial upside to our extension of the Haynesville and Bossier shale plays. We believe that these shale plays represent some of the most economic natural gas drilling opportunities in North America.

•Management and operating team with extensive experience in developing the Haynesville and Bossier shales. We were among the first exploration and production companies to effectively apply horizontal drilling techniques in the Haynesville and Bossier shales beginning in 2007. In 2015, we restarted a drilling program in the Haynesville and Bossier shales utilizing enhanced completion well designs that have significantly improved the economics of these wells. In 2022, we started exploratory drilling in the Western Haynesville area and now have 30 successful wells turned to sales through the end of 2025. We have also drilled some of the longest lateral wells in the basin. We successfully drilled 41 wells with laterals of 15,000 feet or greater from 2021 through 2025. We were one of the first operators in the Haynesville shale to drill a horseshoe lateral well, which allows us to replace two short lateral wells with one drilling location with a longer lateral length resulting in a higher economic return.

•Attractive economic returns. The Haynesville and Bossier shales offer highly economic drilling opportunities through application of advanced drilling and completion technologies, including the use of longer laterals, horseshoe laterals and high intensity fracture stimulation using tighter frac stages and higher proppant loading. Our Western Haynesville wells are some of the deepest horizontal wells in a high pressure and high temperature shale in the industry. Our management and operating teams are instrumental in developing and optimizing some of the most effective completion techniques in the Haynesville and Bossier shales and such completion techniques have resulted in a substantial improvement in initial production rates and recoverable reserves, which has resulted in some of the highest single well rates of return when compared to results from other natural gas basins in North America.

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COMSTOCK RESOURCES, INC.

•Proximity to premium natural gas markets. Our natural gas production benefits from the strong regional Gulf Coast demand growth driven by a substantial increase in LNG exports, exports to Mexico and new or expanded petrochemical facilities. Producers, such as us, with access to the Gulf Coast natural gas markets are receiving higher net realized prices than most producers in other regions. We are also able to realize higher margins due to our ability to access an extensive midstream infrastructure with lower cost, flexible gas marketing arrangements. In addition, our access to natural gas storage allows for greater operational flexibility as well as the ability to take advantage of seasonal pricing during winter months when natural gas demand has been historically higher.

•Company-owned Midstream. In 2023, we formed Pinnacle Gas Services LLC to provide gathering and treating services for our emerging Western Haynesville. At December 31, 2025, the Pinnacle system included gas treating plants in Bethel and Marquez, Texas and 246 miles of high-pressure pipelines, which allows us to keep pace with volume growth while maintaining access to strong markets at favorable transportation rates.

•Organic Drilling Inventory Growth. We focus on growing our inventory of drilling locations organically by acquiring undeveloped leasehold through direct leasing or acquisitions of undeveloped acreage in contrast to many of our peers who have focused on mergers or acquisitions of producing properties to replenish drilling inventory. Over the last six years we have acquired a total of approximately 535,480 net undeveloped acres prospective for the Haynesville and Bossier shales.

•Successful Drilling Program. We spent $1.05 billion on exploration and development activities in 2025, almost exclusively in the Haynesville and Bossier shale. We spent $1.01 billion on drilling and completion activities and an additional $47.1 million on other development costs. We drilled 52 (44.2 net) wells in 2025, which had an average lateral length of approximately 11,187 feet. Our drilling program in 2025 replaced 830% of our 2025 production based on proved reserves added in our SEC price case and 229% based on proved reserves added in our alternative price case.

•Efficient Operator. We operated 99% of our proved reserve base as of December 31, 2025. As the operator, we are better able to control operating costs, the timing and plans for future development, the level of drilling and lifting costs, and the marketing of production. As an operator, we receive reimbursements for overhead from other working interest owners, which reduces our general and administrative expenses.

•Data Center Opportunity. We are partnering with NextEra Energy Resources, LLC ("NextEra") to provide natural gas for new power generation in Western Haynesville to support hyperscaler data center development with initial capacity of 2 gigawatts and potential expansion to 8 gigawatts.

Business Strategy

Our strategy consists of the following principal elements:

•Prudently grow cash flow, production and reserves through development of our high-quality inventory of drilling locations. We have an extensive inventory of de-risked, high-return drilling locations prospective for the Haynesville and Bossier shales. As of December 31, 2025, we have identified 1,848 drilling locations (886 net to us) in our legacy Haynesville and Bossier shale area and 3,343 drilling locations (2,561 net to us) in our Western Haynesville area, which gives us decades of drilling activity. We have optimized the economics of our drilling location inventory by extending the lateral lengths. In 2024, we successfully drilled our first "horseshoe" well, which allowed us to convert two 4,500-foot lateral locations to one 9,382 horizontal well. Our drilling inventory now includes 115 horseshoe locations with superior economics compared to the short lateral locations they replaced. The average lateral length of our drilling location inventory in our legacy Haynesville and Bossier shale area and Western Haynesville area is 10,077 feet and 8,873 feet, respectively.

•Grow reserve base through active exploration program. We are investing a substantial portion of our annual capital budget to delineate our emerging Western Haynesville and Bossier shale plays in East Texas. Through December 31, 2025, we have turned 30 wells to sales in this emerging play. In 2026, we currently intend to drill an additional 19 Haynesville and Bossier shale wells in this play.

•Evaluate and pursue strategic acquisition opportunities and conduct an active leasing program to grow our reserves, production, and drilling location inventory. We intend to leverage our management and operating team's significant technical expertise and experience in the Haynesville and Bossier shale plays to continue to pursue acquisition opportunities in that region and to successfully execute and integrate acreage acquisitions that will add to our drilling inventory. We also plan to continue to acquire prospective acreage with an active leasing program.

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COMSTOCK RESOURCES, INC.

•Maintain disciplined financial strategy. We intend to maintain an operating plan in 2026 that will allow us to continue to delineate the Western Haynesville play while protecting our balance sheet. Our current plan is to fund our exploration and development activity primarily with operating cash flow and we believe our low operating cost structure combined with maximizing the capital efficiency of our drilling program and maintaining financial discipline will allow us to achieve this goal.

•Focus on environmental stewardship. We achieved independent, third-party audited certification of our natural gas operations under the MiQ standard for methane emissions. We became one of the first operators to certify all operated natural gas production. The certification allows us to document to both domestic and international customers that we provide responsibly sourced ‎natural gas. We utilize cleaner burning natural gas rather than diesel fuel when possible to reduce emissions in our drilling and completion operations and design our wells to drill longer laterals and utilize multi-well pad locations to minimize our above-ground footprint.

•Manage commodity price exposure. We maintain an active natural gas price hedging program designed to mitigate volatility in natural gas prices and to protect a portion of our expected future cash flows to insure that we have adequate cash flow to meet our financial obligations. We also have access to gas storage in the Western Haynesville area that will allow us greater operational flexibility and take advantage of seasonal natural gas pricing.

Property Acquisitions

In 2025, we added 17,856 net Haynesville and Bossier shale acres in the Western Haynesville area through an active leasing program at a cost of $54.7 million. In 2024, we added 265,290 net acres to our Western Haynesville area through acquisitions and a leasing program at a cost of $106.4 million. In 2023, we added 79,741 net Haynesville and Bossier shale acres in Western Haynesville for $98.6 million.

Western Haynesville Midstream Venture

To support the continued development of the Western Haynesville and Bossier shale, we entered into a partnership with Quantum Capital Solutions ("Quantum") in 2023 to finance the buildout of natural gas gathering and treating facilities required to handle the expected growth in our natural gas production from wells we plan to drill in this area. Pinnacle Gas Services LLC ("Pinnacle") was formed by the contribution of a high pressure pipeline and natural gas treating plant which we acquired in 2022. We invested $30.0 million in these midstream assets including the initial acquisition costs. Quantum agreed to fund up to $300 million for the future build out of the gathering and gas treating system. We manage the operations of Pinnacle under a management contract and appoint the majority of Pinnacle's board of directors. Quantum is entitled to a 12% dividend on its invested capital and 80% of any distributions from Pinnacle until certain return hurdles are met. After the return hurdles are met, Quantum's ownership reduces to 30%. In 2025, 2024 and 2023, Quantum contributed $215.5 million, $60.5 million and $24.0 million, respectively, to fund Pinnacle's capital expansion. In January 2026, Pinnacle entered into an agreement with Quantum to redeem all of Quantum's outstanding Class B Units in exchange for cash consideration of $440 million plus any accrued but unpaid distributions. The redemption is expected to be completed in the first half of 2026.

Property Dispositions

In 2025, we sold our Shelby Trough assets in Nacogdoches, San Augustine and Sabine counties of Texas and our Cotton Valley assets in East Texas and North Louisiana for aggregate net proceeds after selling expenses of $432.4 million. In 2024 and 2023, we sold our working interest in certain non-strategic, non-operated properties for $1.2 million and $41.3 million, respectively.

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COMSTOCK RESOURCES, INC.

Natural Gas and Oil Reserves

The following table sets forth our estimated proved natural gas and oil reserves as of December 31, 2025:

	Oil (MBbls)		Natural Gas (MMcf)(1)		Total (MMcfe)(1)		PV 10 Value (000's)(2)
Proved Developed:
Producing		198		2,813,569		2,814,757	$	3,042,599
Non-producing		—		27,069		27,069		17,309
Total Proved Developed		198		2,840,638		2,841,826		3,059,908
Proved Undeveloped		—		4,163,483		4,163,483		1,403,430
Total Proved		198		7,004,121		7,005,309		4,463,338
Discounted Future Income Taxes								(596,264	)
Standardized Measure of Discounted Cash Flows							$	3,867,074

______________

(1)Natural gas volumes include NGLs. Oil and NGLs are converted to natural gas equivalents by using a conversion factor of one barrel of oil or NGLs for six Mcf of natural gas based upon the approximate relative energy content of oil to natural gas, which is not indicative of natural gas and oil prices.

(2)The PV 10 Value represents the discounted future net cash flows attributable to our proved natural gas and oil reserves before income tax, discounted at 10%. Although it is a non-GAAP measure, we believe that the presentation of PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our natural gas and oil properties. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved natural gas and oil reserves after income tax, discounted at 10%.

The following table sets forth our year end reserves as of December 31 for each of the last three fiscal years:

	2025				2024				2023
	Oil (MBbls)		Natural Gas (MMcf) (1)		Oil (MBbls)		Natural Gas (MMcf) (1)		Oil (MBbls)		Natural Gas (MMcf) (1)
Proved Developed		198		2,840,638		331		2,731,812		548		2,734,175
Proved Undeveloped		—		4,163,483		—		1,030,286		—		2,206,051
Total Proved Reserves		198		7,004,121		331		3,762,098		548		4,940,226

______________

(1)Natural gas volumes include NGLs. NGLs are converted to natural gas equivalents by using a conversion factor of one barrel of NGLs for six Mcf of natural gas based upon the approximate relative energy content.

Substantially all of our proved reserves are in the Haynesville and Bossier shales in North Louisiana and East Texas. These wells produce from depths of 10,500 to 19,200 feet. All of our proved undeveloped reserves represent wells to be drilled in the next five years on our Haynesville and Bossier shale acreage.

Proved reserves that are attributable to existing producing wells are primarily determined using decline curve analysis and rate transient analysis, which incorporates the principles of hydrocarbon flow. Proved reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. Technologies relied on to establish reasonable certainty of economic producibility include electrical logs, radioactivity logs, core analyses, geologic maps and available production data, seismic data and well test data.

There are numerous uncertainties inherent in estimating quantities of proved natural gas and oil reserves. Natural gas and oil reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of natural gas and oil that are ultimately recovered.

Prices used in determining quantities of natural gas and oil reserves and future cash inflows from natural gas and oil reserves represent the average first of the month prices received at the point of sale for the last twelve months. These prices have been adjusted from index prices for both location and quality differences.

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COMSTOCK RESOURCES, INC.

The natural gas and oil prices used for reserves estimation were as follows:

Year	Natural Gas Price (per Mcf)		Oil Price (per Bbl)
2025	$	3.07	$	61.98
2024	$	1.84	$	71.07
2023	$	2.39	$	72.63

Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered, and they are scheduled to be drilled within five years of their initial inclusion as proved reserves, unless specific circumstances justify a longer time. In connection with estimating proved undeveloped reserves for our reserve report, reserves on undrilled acreage were limited to those that are reasonably certain of production when drilled where we can verify the continuity of the reservoir. We only include wells in our proved undeveloped reserves that we currently plan to drill and in which we have adequate capital resources to enable us to drill them. Using empirical evidence, we utilize control points and sample sizes to show continuity in the reservoir. We reflect changes to undeveloped reserves that occur in the same field as revisions to the extent that proved undeveloped locations are revised due to changes in future development plans, including changes to proposed lateral lengths, development spacing and timing of development. As of December 31, 2025, our proved undeveloped reserves did not include any undrilled wells with a rate of return less than 10%.

As of December 31, 2025, our proved undeveloped reserves were comprised of 4.2 Tcf of natural gas consisting of 332 undeveloped locations. All of our natural gas undeveloped reserves are associated with our Haynesville and Bossier shale properties where our 2026 drilling program is focused. Our natural gas and oil proved undeveloped reserves increased by 3.1 Tcf during 2025 due to higher natural gas prices used to determine the proved reserves. During 2025, thirteen proved undeveloped locations included in our 2024 reserves were converted to proved developed reserves. Certain of our proved undeveloped locations that were excluded from our proved reserves at December 31, 2024 due to the low natural gas price that was used to determine proved reserves were included in our 2025 proved reserves given the significant improvement in natural gas prices during 2025.

As of December 31, 2024, our proved undeveloped reserves were comprised of 1.0 Tcf of natural gas consisting of 56 undeveloped locations. All of our natural gas undeveloped reserves are associated with our Haynesville and Bossier shales (including Western Haynesville and Bossier) properties. Our natural gas proved undeveloped reserves decreased by 1.2 Tcf during 2024. During 2024, 21 proved undeveloped locations were converted to proved developed reserves.

The following table presents the changes in our estimated proved undeveloped natural gas and oil reserves for the years ended December 31, 2025, 2024 and 2023:

	Proved Undeveloped Reserves
	2025					2024					2023
	Oil (MBbls)		Natural Gas (MMcf)			Oil (MBbls)		Natural Gas (MMcf)			Oil (MBbls)			Natural Gas (MMcf)
Beginning Balance		—		1,030,286			—		2,206,051			69			4,166,108
Revisions		—		13,241			—		(996,816	)		—			(1,634,178	)
Extension and Discoveries		—		3,175,001			—		94,538			—			407,629
Conversion from Undeveloped to Developed		—		(55,045	)		—		(273,487	)		(69	)		(733,508	)
Total Change		—		3,133,197			—		(1,175,765	)		(69	)		(1,960,057	)
Ending Balance		—		4,163,483			—		1,030,286			—			2,206,051

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The timing, by year, when our proved undeveloped reserve quantities are estimated to be converted to proved developed reserves is as follows:

	Proved Undeveloped Reserves
	2025				2024				2023
Year ended December 31,	Oil (MBbls)		Natural Gas (MMcf)		Oil (MBbls)		Natural Gas (MMcf)		Oil (MBbls)		Natural Gas (MMcf)
2024		—		—		—		—		—		273,487
2025		—		—		—		162,370		—		425,458
2026		—		451,393		—		90,525		—		656,609
2027		—		615,813		—		70,859		—		509,227
2028		—		900,524		—		302,749		—		341,270
2029		—		1,212,891		—		403,783		—		—
2030		—		982,862		—		—		—		—
Total		—		4,163,483		—		1,030,286		—		2,206,051

The following table presents the timing of our estimated future development capital costs to be incurred for the years ended December 31, 2025, 2024 and 2023:

	Future Development Costs Total Proved Undeveloped Reserves
	2025		2024		2023
Year ended December 31,	(in millions)
2024	$	—	$	—	$	184.5
2025		—		97.1		427.2
2026		411.6		65.7		728.7
2027		643.2		55.4		522.4
2028		1,013.5		279.1		351.3
2029		1,458.9		394.2		—
2030		1,175.1		—		—
Total	$	4,702.3	$	891.5	$	2,214.1

The following table presents the changes in our estimated future development costs for the years ended December 31, 2025 and December 31, 2024:

	(in millions)
Total as of December 31, 2023	$	2,214.1
Development Costs Incurred		(422.6	)
Additions		96.2
Revisions		(996.2	)
Total Changes		(1,322.6	)
Total as of December 31, 2024		891.5
Development Costs Incurred		(393.2	)
Additions		3,645.5
Revisions		558.5
Total Changes		3,810.8
Total as of December 31, 2025	$	4,702.3

Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2025 of $4.7 billion increased by $3.8 billion from our estimated future capital costs of $0.9 billion as of December 31, 2024. This increase was attributable to the increase in future proved undeveloped locations included in the 2025 proved reserves with the higher natural gas prices in 2025. Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2024 of $0.9 billion decreased by $1.3 billion from our estimated future capital costs of $2.2 billion as of December 31, 2023 due to a lower number of future proved undeveloped locations expected to generate an economic return as a result of lower natural gas prices.

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We performed an analysis to compare our proved reserve estimates as of December 31, 2025, to proved reserve estimates using year-end market prices of $3.23 per Mcf natural gas price and a $56.82 per Bbl oil price, which represents the NYMEX futures market prices as of December 31, 2025, adjusted for basis differentials ("alternative price case"), to show the sensitivity of our proved reserve estimates to price fluctuations. This sensitivity analysis is meant to demonstrate the impact that changing natural gas and oil prices may have on our proved reserve estimates and the related PV 10 Value and there is no assurance this outcome will be realized.

Our proved natural gas and oil reserves utilizing SEC prices and the alternative price case are as follows:

	SEC Price Case		Alternative Price Case
Oil (MBbls)
Proved Developed		198		194
Proved Undeveloped		—		—
Total		198		194
Natural Gas (MMcf) (1)
Proved Developed		2,840,638		2,842,840
Proved Undeveloped		4,163,483		4,339,833
Total		7,004,121		7,182,673
Total Proved Reserves (MMcfe) (1)		7,005,309		7,183,837
PV 10 Value (in thousands) (2)	$	4,463,338	$	5,180,999

______________

(1)Natural gas volumes include NGLs. Oil and NGLs are converted to natural gas equivalents by using a conversion factor of one barrel of oil or NGLs for six Mcf of natural gas based upon the approximate relative energy content of oil to natural gas, which is not indicative of natural gas and oil prices.

(2)The PV 10 Value represents the discounted future net cash flows attributable to our proved natural gas and oil reserves before income tax, discounted at 10%. Although it is a non-GAAP measure, we believe that the presentation of PV 10 Value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We use this measure when assessing the potential return on investment related to our natural gas and oil properties. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved natural gas and oil reserves after income tax, discounted at 10%.

Proved reserve information in this report is based on estimates prepared by our petroleum engineering staff and is the responsibility of management. We retained an independent petroleum consultant to conduct an audit of our December 31, 2025 reserve estimates. Netherland, Sewell & Associates, Inc. ("NSAI") audited 100% of our total PV 10 Value as of December 31, 2025. The purpose of this audit was to provide additional assurance on the reasonableness of internally prepared reserve estimates. NSAI was selected for its geographic expertise and historical experience.

The audit letter prepared by NSAI is included as an exhibit to this report. The technical persons at the independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

The independent consultant's estimates of proved reserves and the pretax present value of such reserves discounted at 10% did not differ from our estimates by more than 7% in the aggregate. However, when compared on a lease-by-lease, field-by-field or area-by-area basis, some of our estimates may be greater than those of our independent consultant and some may be less than the estimates of the independent consultant. When such differences do not exceed 10% in the aggregate, our reserve auditor is satisfied that the proved reserves and pretax present value of such reserves discounted at 10% are reasonable and will issue an unqualified opinion. The remaining differences are not resolved due to the limited cost benefit of continuing such analysis. During the year, our reserves group also performs separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions.

We have established and maintain internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations promulgated by the SEC. These internal controls include documented process workflows, employing qualified engineering and geological personnel, and on-going education for personnel involved in our reserves estimation process. Our internal audit function routinely tests our processes and controls. Throughout the year, our technical team meets periodically with representatives of our independent petroleum consultants to

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review properties and discuss methods and assumptions. We provide historical information to our consultants for our largest producing properties such as ownership interest, production, well test data, commodity prices and operating and development costs. In some cases, additional meetings are held to review identified reserve differences.

All of our reserve estimates are reviewed with our executive management, our independent consultants perform an independent analysis, and ultimately our reserve estimates are approved by our Director of Reservoir Engineering, Kristine Bartlett. Ms. Bartlett holds a Bachelor of Science degree in Petroleum Engineering and Geoscience from the University of Texas at Austin and has 13 years of engineering experience in the oil and gas industry.

We did not provide estimates of total proved natural gas and oil reserves during the three-year period ended December 31, 2025 to any federal authority or agency, other than the SEC.

Production, Price and Cost Summary

Annual production, average prices that we realized from sales of natural gas and oil and the associated lifting costs for each of the last three fiscal years were as follows:

	Year Ended December 31,
	2025		2024		2023
Net Production Volumes:
Natural gas - MMcf		450,202		527,548		524,467
Oil - MBbls		37		50		70
Average Prices:
Natural Gas - $/Mcf	$	3.17	$	1.98	$	2.40
Oil - $/Bbl	$	61.95	$	71.94	$	73.73
Lifting Costs - $/Mcfe:
Lease operating	$	0.27	$	0.25	$	0.25
Gathering and transportation	$	0.37	$	0.37	$	0.35
Production and ad valorem taxes	$	0.09	$	0.11	$	0.18

Drilling Activity Summary

During the three-year period ended December 31, 2025, we drilled development and exploratory wells as set forth in the table below:

	2025				2024				2023
	Gross		Net		Gross		Net		Gross		Net
Development:
Oil		—		—		—		—		—		—
Gas		34		26.2		39		31.9		63		47.6
Dry		—		—		—		—		1		1.0
		34		26.2		39		31.9		64		48.6
Exploratory:
Oil		—		—		—		—		—		—
Gas		18		18.0		11		11.0		7		6.9
Dry		—		—		—		—		—		—
		18		18.0		11		11.0		7		6.9
Total		52		44.2		50		42.9		71		55.5

As of December 31, 2025, 2024 and 2023, we had 35 (28.8 net), 21 (17.3 net), and 30 (26.9 net), respectively, operated wells in the process of being drilled and completed.

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Producing Well Summary

The following table sets forth the gross and net producing natural gas and oil wells in which we owned an interest as of December 31, 2025:

	Oil				Natural Gas
	Gross		Net		Gross		Net
Louisiana		—		—		1,212		669.6
Oklahoma		6		0.6		98		8.8
Texas		10		5.2		372		273.6
Wyoming		—		—		26		1.9
Total		16		5.8		1,708		953.9

We operate 1,074 of the 1,724 producing wells presented in the above table. As of December 31, 2025, we did not own an interest in any wells containing multiple completions, which means that a well is producing from more than one completed zone.

Acreage

The following table summarizes our developed and undeveloped leasehold acreage as of December 31, 2025, all of which is onshore in the continental United States. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.

	Developed				Undeveloped
	Gross		Net		Gross		Net
Louisiana		193,399		151,439		25,608		18,856
Oklahoma		26,080		3,382		—		—
Texas		194,617		159,082		725,954		516,742
Wyoming		13,440		927		—		—
Total		427,536		314,830		751,562		535,598

As of December 31, 2025, our undeveloped acreage expires as follows:

	Gross				Net
2026		79,799	11	%		54,529	10	%
2027		57,925	8	%		42,319	8	%
2028		46,116	6	%		28,696	5	%
2029		5,733	1	%		2,815	1	%
2030		12,191	2	%		5,170	1	%
Thereafter		549,798	72	%		402,069	75	%
		751,562	100	%		535,598	100	%

The title to our natural gas and oil properties is subject to royalty, overriding royalty, carried and other similar interests and contractual arrangements customary in the natural gas and oil industry, liens incident to operating agreements and for current taxes not yet due and other minor encumbrances. All of our natural gas and oil properties are pledged as collateral under our bank credit facility. As is customary in the natural gas and oil industry, we are generally able to retain our ownership interest in undeveloped acreage by production from wells producing from a different reservoir, by drilling activity which establishes commercial reserves sufficient to maintain the lease, by payment of delay rentals or by the exercise of contractual extension rights.

Markets and Customers

The market for our production of natural gas and oil depends on factors beyond our control, including the extent of domestic production and imports of natural gas and oil, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for natural gas and oil, the marketing of competitive fuels and the effects of state and federal regulation. The natural gas and oil industry also competes with other industries in supplying the energy and fuel requirements of industrial, residential and commercial consumers along with electric generator customers.

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Our natural gas production is primarily sold under contracts with various terms and priced on first of the month index prices or on daily spot market prices or fixed prices. We target selling approximately 70% to 75% of our natural gas on first of month index price, with the remaining volumes on daily spot market pricing. The percentage of natural gas sold on spot market pricing can be impacted when new wells commence production as such production is typically sold on daily spot market pricing during the month the well is first brought on line. Enterprise Products Operating and its subsidiaries, Venture Global LNG, Inc. and Shell Energy North America US, L.P. accounted for 18%, 11%, and 10%, respectively, of our total 2025 sales. The loss of any of these customers would not have a material adverse effect on us as there is an available market for our natural gas and oil production from other purchasers.

We have entered into longer-term transportation arrangements to ensure that we have adequate transportation to deliver our natural gas production in North Louisiana and East Texas to various markets. As an alternative to constructing our own gathering and treating facilities, we have entered into a variety of gathering and treating agreements with midstream companies to transport our natural gas to a central point or other long-haul natural gas pipelines. We currently have agreements with certain natural gas midstream companies to provide us with firm transportation for an average of approximately 1.7 Bcf per day in 2026 on the long-haul pipelines. To the extent we are not able to deliver the contracted natural gas volumes, we may be responsible for the transportation costs.

Competition

The natural gas and oil industry is highly competitive. Competitors include major oil companies, other independent energy companies and individual producers and operators, many of which have financial resources, personnel and facilities substantially greater than we do. We face intense competition for the acquisition of natural gas and oil properties and leases for natural gas and oil exploration.

Regulation

General. Various aspects of our natural gas and oil operations are subject to extensive and continually changing regulation, as legislation affecting the natural gas and oil industry is under constant review for amendment or expansion. Numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding upon the natural gas and oil industry and its individual members. The Federal Energy Regulatory Commission ("FERC") regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 ("NGA") and the Natural Gas Policy Act of 1978. In 1989, however, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and nonprice controls affecting all "first sales" of natural gas, effective January 1, 1993, subject to the terms of any private contracts that may be in effect. While sales by producers of natural gas and all sales of crude oil, condensate and natural gas liquids can currently be made at uncontrolled market prices, in the future Congress could reenact price controls or enact other legislation with detrimental impact on many aspects of our business. Under the provisions of the Energy Policy Act of 2005 (the "2005 Act"), the NGA has been amended to prohibit any form of market manipulation with the purchase or sale of natural gas, and the FERC has issued new regulations that are intended to increase natural gas pricing transparency. The 2005 Act has also significantly increased the penalties for violations of the NGA. The FERC has issued Order No. 704 et al. which requires a market participant to make an annual filing if it has sales or purchases equal to or greater than 2.2 million MMBtu in the reporting year to facilitate price transparency.

Regulation and transportation of natural gas. Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. The FERC requires interstate pipelines to provide open-access transportation on a not unduly discriminatory basis for similarly situated shippers. The FERC frequently reviews and modifies its regulations regarding the transportation of natural gas, with the stated goal of fostering competition within the natural gas industry.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The Texas Railroad Commission has been changing its regulations governing transportation and gathering services provided by intrastate pipelines and gatherers. While the changes by these state regulators affect us only indirectly, they are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC or state regulators will take on these matters; however, we do not believe that we will be affected differently in any material respect than other natural gas producers with which we compete by any action taken.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, state commissions and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach pursued by the FERC, Congress and state regulatory authorities will continue.

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Federal leases. Some of our operations are located on federal natural gas and oil leases that are administered by the Bureau of Land Management ("BLM") of the United States Department of the Interior. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed Department of Interior and BLM regulations and orders that are subject to interpretation and change. These leases are also subject to certain regulations and orders promulgated by the Department of Interior's Bureau of Ocean Energy Management, Regulation & Enforcement, through its Minerals Revenue Management Program, which is responsible for the management of revenues from both onshore and offshore leases. Our operations located on federal natural gas and oil leases are insignificant to our total operations.

Oil and natural gas liquids transportation rates. Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. The price received from the sale of these products may be affected by the cost of transporting the products to market.

The FERC's regulation of pipelines that transport crude oil, condensate and natural gas liquids under the Interstate Commerce Act is generally more light-handed than the FERC's regulation of natural gas pipelines under the NGA. FERC-regulated pipelines that transport crude oil, condensate and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates are permitted in certain circumstances. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates governed by the Interstate Commerce Act that allowed for an increase or decrease in the transportation rates. The FERC's regulations include a methodology for such pipelines to change their rates through the use of an index system that establishes ceiling levels for such rates. The mandatory five-year review in 2005 revised the methodology for this index to be based on Producer Price Index for Finished Goods (PPI-FG) plus 1.3 percent for the period July 1, 2006 through June 30, 2011. The mandatory five-year review in 2012 revised the methodology for this index to be based on PPI-FG plus 2.65 percent for the period July 1, 2011 through June 30, 2016. The regulations provide that each year the Commission will publish the oil pipeline index after the PPI-FG becomes available.

With respect to intrastate crude oil, condensate and natural gas liquids pipelines subject to the jurisdiction of state agencies, such state regulation is generally less rigorous than the regulation of interstate pipelines. State agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests. Complaints or protests have been infrequent and are usually resolved informally.

We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate or natural gas liquids pipelines will affect us in a way that materially differs from the way it affects other crude oil, condensate and natural gas liquids producers or marketers.

Environmental regulations. We are subject to stringent federal, state and local laws. These laws, among other things, govern the issuance of permits to conduct exploration, drilling and production operations, the amounts and types of materials that may be released into the environment, the discharge and disposition of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, sites and facilities. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup cost without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of natural gas and oil production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the natural gas and oil industry increases our cost of doing business and consequently affects our profitability. These costs are considered a normal, recurring cost of our on-going operations. Our domestic competitors are generally subject to the same laws and regulations.

We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements or new regulatory schemes such as carbon "cap and trade" or pricing programs could have a material adverse effect upon our

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capital expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas. The Biden administration has made, and the Trump administration may also make additional changes to applicable regulations. There are costs associated with responding to changing regulations and policies, whether such regulations are more or less stringent. As such, there can be no assurance that material costs and liabilities will not be incurred in the future.

The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") imposes liability, without regard to fault, on certain classes of persons that are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances at such sites. Under CERCLA, such persons may be subject to joint and several liability for the cost of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the cost of certain health studies. In addition, companies that incur liability frequently also confront third party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a polluted site. Many states have adopted similar statutes that impose liability for the release of hazardous substances and petroleum. In addition, from time to time the U.S. Environmental Protection Agency ("EPA"), states, and other agencies make new findings that certain chemicals are potential environmental concerns, sometimes referred to as emerging contaminants. These agencies may also adjust risk-based assessment or cleanup levels, in some instances, to be more stringent. The EPA and other agencies may impose new restrictions or cleanup requirements on such chemicals. We may incur costs to comply with such requirements.

The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 ("RCRA"), regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites. RCRA currently excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of natural gas and oil gas from regulation as "hazardous waste". Disposal of such non-hazardous natural gas and oil exploration, development and production wastes usually are regulated by state law. Other wastes handled at exploration and production sites or used in the course of providing well services may not fall within this exclusion. Moreover, stricter standards for waste handling and disposal may be imposed on the natural gas and oil industry in the future. From time to time, legislation is proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from RCRA's definition of "hazardous wastes", thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general. The impact of future revisions to environmental laws and regulations cannot be predicted.

Certain natural gas and oil wastes may also contain naturally occurring radioactive material ("NORM"), which is regulated by the federal Occupational Safety and Health Administration and state agencies. These regulations require certain worker protections and waste handling and disposal procedures. We believe our operations comply in all material respects with these worker protection and waste handling and disposal requirements.

Our operations are also subject to the Clean Air Act ("CAA"), and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. EPA issued its final rule on December 2, 2023 that has a number of provisions intended to reduce methane emissions from natural gas and oil operations. On March 12, 2025, EPA Administrator Lee Zeldin announced that the EPA was reconsidering the prior rule, and, on July 28, 2025 and December 3, 2025, the EPA issued an interim final rule and final rule, respectively, extending the deadlines for certain provisions on the rule. We believe our operations will not be materially adversely affected by the new requirements, and the requirements will not be any more burdensome to us than to other similarly situated companies involved in natural gas and oil exploration and production activities.

The Federal Water Pollution Control Act of 1972, as amended (the "Clean Water Act"), imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. In January 2023, the EPA and the U.S. Army Corps of Engineers ("USACE") issued a new rule that revises the definition of "waters of the United States" ("WOTUS"). The new rule has been challenged by several states and industry groups. If upheld, such regulations may impact certain exploration and production activities. On November 17, 2025, the EPA and the USACE announced a proposed rule to further revise the definition of WOTUS. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into certain coastal and offshore waters, unless otherwise authorized. Further, the EPA has adopted regulations requiring certain natural gas and oil exploration and production

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facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the cost of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution and that the requirements, including those under the 2023 WOTUS rule and 2025 WOTUS rule, are not any more burdensome to us than to other similarly situated companies involved in natural gas and oil exploration and production activities.

The Federal Safe Drinking Water Act of 1974, as amended, requires the EPA to develop minimum federal requirements for Underground Injection Control ("UIC") programs and other safeguards to protect public health by preventing injection wells from contaminating underground sources of drinking water. The UIC program does not regulate wells that are solely used for production. However, the EPA has authority to regulate hydraulic fracturing when diesel fuels are used in fluids or propping agents. In February 2014, the EPA issued guidance on when UIC permitting requirements apply to fracking fluids containing diesel. We believe that our operations comply in all material respects with the requirements of the Federal Safe Drinking Water Act and similar state statutes. We believe the requirements are not any more burdensome to us than to other similarly situated companies involved in natural gas and oil exploration and production activities.

State and federal regulatory agencies have studied possible connections between hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Arkansas, California, Colorado, Illinois, Kansas, Ohio, Oklahoma, and Texas, have modified their regulations to account for induced seismicity. There continues to be research into the possible linkage between natural gas and oil activity and induced seismicity. A 2012 report published by the National Academy of Sciences, as well as a more recent paper published in the journal Reviews of Geophysics and cited on the U.S. Geological Survey website, concluded that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. In 2015, the U.S. Geological Survey identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or natural gas and oil extraction. In March 2016, the U.S. Geological Survey identified six states with the most significant hazards from induced seismicity, including Texas, Colorado, Oklahoma, Kansas, New Mexico, and Arkansas. In addition, a number of lawsuits have been filed, including in Oklahoma, alleging that disposal well operations have caused damage to or injury at nearby properties or otherwise violated state and federal rules regulating waste disposal. It is possible that the EPA or other agencies may develop rules to specifically address the disposal of wastewater from natural gas and oil development and the potential for induced seismicity from wastewater injection. Future regulatory developments could adversely affect our operations by placing restrictions on the use of injection wells and hydraulic fracturing and/or causing us to incur increased operating expenses.

In December 2016, the EPA finalized its report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities could impact drinking water resources under some circumstances. Other governmental agencies, including the U.S. Department of Energy, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies have the potential to impact the likelihood or scope of future legislation or regulation.

Federal regulators require certain owners or operators of facilities that store or otherwise handle oil to prepare and implement spill prevention, control, countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990 ("OPA") contains numerous requirements relating to the prevention and response to oil spills in the WOTUS. The OPA subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages relating to a spill. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities.

Executive Order 13158, issued on May 26, 2000, directs federal agencies to safeguard existing Marine Protected Areas, or MPAs, in the United States and establish new MPAs. The order requires federal agencies to avoid harm to MPAs to the extent permitted by law and to the maximum extent practicable. It also directs the EPA to propose new regulations under the Clean Water Act to ensure appropriate levels of protection for the marine environment. This order has the potential to adversely affect our operations by restricting areas in which we may carry out future exploration and development projects and/or causing us to incur increased operating expenses.

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Certain flora and fauna that have officially been classified as "threatened" or "endangered" are protected by the Endangered Species Act. This law prohibits any activities that could "take" a protected plant or animal or reduce or degrade its habitat area. If endangered species are located in an area we wish to develop, the work could be prohibited or delayed and/or expensive mitigation might be required.

Other statutes that provide protection to animal and plant species and which may apply to our operations include, but are not necessarily limited to, the Oil Pollution Act, the Emergency Planning and Community Right to Know Act, the Marine Mammal Protection Act, the Marine Protection, Research and Sanctuaries Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and may limit or prohibit construction, drilling and other activities on certain lands lying within wilderness or wetlands and other protected areas and impose substantial liabilities for pollution resulting from our operations. The permits required for our various operations are subject to revocation, modification and renewal by issuing authorities. In addition, laws such as the National Environmental Policy Act and the Coastal Zone Management Act may make the process of obtaining certain permits more difficult or time consuming, resulting in increased costs and potential delays that could affect the viability or profitability of certain activities. Administrative policies with respect to such laws are also changing, and we incur costs to follow such changes and comply as changes become effective.

Certain statutes, such as the Emergency Planning and Community Right to Know Act, require the reporting of hazardous chemicals manufactured, processed, or otherwise used, which may lead to heightened scrutiny of the company's operations by regulatory agencies or the public. In 2012, the EPA adopted the Petroleum and Natural Gas Systems Greenhouse Gas Reporting Rule (40 C.F.R. Part 98, Subpart W), which requires certain onshore petroleum and natural gas facilities to collect data on their emissions of greenhouse gases ("GHG"). GHGs include gases such as methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning natural gas. Different GHGs have different global warming potentials with CO2 having the lowest global warming potential, so emissions of GHGs are typically expressed in terms of CO2 equivalents ("CO2e"). The rule applies to facilities that emit 25,000 metric tons of CO2e or more per year, and requires onshore petroleum and natural gas operators to group all equipment under common ownership or control within a single hydrocarbon basin together when determining if the threshold is met. These greenhouse gas reporting rules were amended on October 22, 2015 to expand the number of sources and operations that are subject to these rules, and again on November 18, 2016 to provide less burdensome reporting requirements. We have determined that these reporting requirements apply to us and we believe we have met all of the EPA required reporting deadlines and strive to ensure accurate and consistent emissions data reporting. On September 12, 2025, the EPA announced a proposed rule to end the GHG Reporting Rule. Other EPA actions with respect to the reduction of greenhouse gases (such as the EPA's Greenhouse Gas Endangerment Finding, and the EPA's Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule) and various state actions have or could impose mandatory reductions in greenhouse gas emissions. We are unable to predict at this time how much the cost of compliance with any legislation or regulation of greenhouse gas emissions will be in future periods.

The U.S. has not passed legislation to expressly regulate GHG emissions; however, in recent years the EPA moved ahead with its efforts to regulate GHG emissions from certain sources by rule. Beyond requiring measurement and reporting of GHGs as discussed above, the EPA issued an "Endangerment Finding" under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. However, in 2025, President Trump directed the EPA to reevaluate the Endangerment Finding, which could impact the EPA's prior and future rulemaking. On July 29, 2025, the EPA proposed to rescind the Endangerment Finding and, on January 7, 2026, the EPA sent its draft final rule to the White House Office of Management and Budget for review. The EPA has adopted regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. States in which we operate may also require permits and reductions in GHG emissions. Additionally, as discussed above, the EPA has promulgated rules that require reductions in volatile organic compounds ("VOCs") and methane generation from natural gas and oil operations. In addition, on April 10, 2024, the BLM finalized a rule establishing new requirements designed to reduce waste of natural gas from venting, flaring and leaks. Since all of our natural gas and oil production is in the United States, laws or regulations that have been or may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur substantial increased operating costs, and could have an adverse effect on demand for the natural gas and oil we produce. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires ratifying countries to review and "represent a progression" in the ambitions of their nationally determined contributions, which set GHG emission reduction goals, every five years. The United States signed the Paris Agreement on April 22, 2016; although the Trump administration provided notice of its intent to withdraw from the Paris Agreement in 2017 and again in 2025. Further, the United States has made additional commitments with respect to GHG emissions through the United Nations Climate Change Conference,

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including with respect to reducing methane emissions. It is difficult to predict the timing and certainty of any future government action and the effect on our operations. Future legislation or regulations adopted to address climate change could also make our products more or less desirable than competing sources of energy. However, we expect that the impacts to our operations will not be materially different from other similarly situated companies involved in natural gas and oil exploration and production activities.

The Inflation Reduction Act (the "IRA"), which was signed into law on August 16, 2023, established a new program, the Methane Emission Reduction Program, that imposes a first-time federal fee on methane emissions for the oil and gas sector, the Waste Emissions Charge ("WEC"). In general, under the EPA's November 12, 2024 final rule implementing the WEC, covered facilities that emit 25,000 metric tons of carbon dioxide equivalent or more per year are required to pay for "excess" methane emissions, with the fee starting at $900 per metric ton in 2024, and increasing to $1,500 per metric ton by 2026. The calculation of the methane fee is determined by (1) the facility's reported emissions under the federal Greenhouse Gas Reporting Program, and (2) an emissions threshold that varies by facility type. For example, for offshore and onshore petroleum and natural gas production facilities, the fee applies to the number of reported tons of methane that exceed (i) 0.2% of the natural gas sent to sale from the facility. On March 14, 2025, President Trump signed a Joint Resolution of Disapproval under the Congressional Review Act overturning the EPA's WEC rule. The One Big Beautiful Bill Act signed into law by President Trump on July 4, 2025 postpones the implementation of the WEC to 2034. We believe our operations will not be materially adversely affected by the IRA, and the requirements will not be any more burdensome to us than to other similarly situated companies involved in natural gas and oil exploration and production activities.

In 2021, the Biden administration issued an Executive Order pausing new natural gas and oil leasing and drilling permits for U.S. public lands and offshore waters until the Secretary of the Interior conducts a comprehensive review and reconsideration of Federal natural gas and oil permitting and leasing practices. In 2022, the Biden administration reopened federal lands for natural gas and oil leasing under a reformed program that significantly reduces the acreage available for lease and, in 2025, President Trump revoked the 2021 Executive Order. We believe our operations will not be materially adversely affected by these changes and expect that the impacts to our operations will be similar to other similarly situated companies involved in natural gas and oil exploration and production activities.

Such changes in environmental laws and regulations which result in more stringent and costly reporting, or waste handling, storage, transportation, disposal or cleanup activities, could materially affect companies operating in the energy industry. Adoption of new regulations further regulating emissions from natural gas and oil production could adversely affect our business, financial position, results of operations and prospects, as could the adoption of new laws or regulations which levy taxes or other costs on greenhouse gas emissions from other industries, which could result in changes to the consumption and demand for natural gas. We may also be assessed administrative, civil and/or criminal penalties if we fail to comply with any such new laws and regulations applicable to natural gas and oil production.

Regulation of natural gas and oil exploration and production. Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulations include requiring permits and drilling bonds for the drilling of wells, regulating the location of wells, the method of drilling and casing wells and the surface use and restoration of properties upon which wells are drilled. Many states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of natural gas and oil properties, the establishment of maximum rates of production from natural gas and oil wells and the regulation of spacing, plugging and abandonment of such wells. Some state statutes limit the rate at which natural gas and oil can be produced from our properties. It is also possible that certain states may increase regulatory activity in response to changing federal regulations or policies.

State regulation. Most states regulate the production and sale of natural gas and oil, including requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas and oil resources. The rate of production may be regulated and the maximum daily production allowable from both natural gas and oil wells may be established on a market demand or conservation basis or both.

Office and Operations Facilities

Our executive offices are located at 5300 Town and Country Blvd., Suite 500 in Frisco, Texas 75034, and our telephone number is (972) 668-8800. We lease office space in Frisco, Texas covering 66,382 square feet. This lease expires on December 31, 2031. We have an option to terminate the lease on December 31, 2028. We also own production offices and pipe yard facilities near Carthage, Franklin, Marshall, Marquez and Tennessee Colony in Texas and Bossier City, Grand Cane, Greenwood, Homer, Mansfield and Logansport in Louisiana.

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Human Capital

As of December 31, 2025, we had 252 employees and utilized contract employees for certain of our drilling, completion and production operations. We seek to attract a qualified workforce and maintain strong non-discrimination and anti-harassment policies.

The safety of our employees, contractors and the community is a core business value and in order to achieve our goals of operational excellence and an injury-free workplace, we maintain a strong health and safety management system. The framework includes policies and procedures outlining how we do our work, programs to engage employees and drive a proactive safety culture, employee training to help ensure our employees have the knowledge to perform their work safely, setting targets and objectives for clearly defined deliverables and accountabilities and periodic audit and inspection of results using data collection of key performance indicators and scorecards to measure our success and develop improvement strategies.

We utilize a third-party contractor management service to ensure a consistent approach in aligning our expectations with all third parties involved in our operations. We hold our contractors accountable to the highest performance standards through our contractor onboarding and continuous auditing process.

Directors and Executive Officers

The following table sets forth certain information concerning our executive officers and directors.

Name	Position with Company	Age
M. Jay Allison	Chief Executive Officer and Chairman of the Board of Directors	70
Roland O. Burns	President, Chief Financial Officer, Secretary and Director	65
Daniel S. Harrison	Chief Operating Officer	62
Clifford "Trey" D. Newell	Chief Commercial Officer and Vice President of Corporate Development	47
Patrick H. McGough	Vice President of Operations	45
Ronald E. Mills	Vice President of Finance and Investor Relations	53
Daniel K. Presley	Vice President of Accounting, Controller and Treasurer	65
LaRae L. Sanders	Vice President of Land	63
Brian C. Claunch	Vice President of Financial Reporting	51
Elizabeth B. Davis	Director	63
Morris E. Foster	Director	83
Jim L. Turner	Director	80

A brief biography of each person who serves as an executive officer or director follows below.

Executive Officers

M. Jay Allison has been our Chief Executive Officer since 1988. Mr. Allison was elected Chairman of the Board in 1997 and has been a director since 1987. From 1988 to 2013, Mr. Allison served as our President. From 1981 to 1987, he was a practicing oil and gas attorney with the firm of Lynch, Chappell & Alsup in Midland, Texas. He received B.B.A., M.S. and J.D. degrees from Baylor University in 1978, 1980 and 1981, respectively.

Roland O. Burns has been our President since 2013, Chief Financial Officer since 1990, Secretary since 1991 and a director since 1999. Mr. Burns served as our Senior Vice President from 1994 to 2013 and Treasurer from 1990 to 2013. From 1982 to 1990, Mr. Burns was employed by the public accounting firm, Arthur Andersen. During his tenure with Arthur Andersen, Mr. Burns worked primarily in the firm's oil and gas audit practice. Mr. Burns received B.A. and M.A. degrees from the University of Mississippi in 1982 and is a Certified Public Accountant.

Daniel S. Harrison has been our Chief Operating Officer since 2019 and served as Vice President of Operations since 2017. Mr. Harrison has been with us since 2008 and served in various engineering and operations management positions of increasing responsibility during that time. Prior to joining us, Mr. Harrison was an operations engineer at Cimarex Energy Company from 2005 to 2008. Prior to 2005, he worked in various petroleum engineering operations management positions for

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several independent oil and gas exploration and development companies. Mr. Harrison received a B.S. Degree in Petroleum Engineering from the Louisiana State University in 1985.

Clifford "Trey" D. Newell has been our Chief Commercial Officer and Vice President of Corporate Development since 2022. Mr. Newell has over two decades of experience in commercial, marketing and operations experience in the midstream energy industry. Prior to joining us, Mr. Newell was responsible for producer relationships, business development, project management, scheduling and marketing as Commercial Vice President at Trace Midstream, Blue Mountain Midstream and Penntex Midstream. He received his Bachelor of Business Administration in Economics and Pre-Law and Executive Master of Business Administration from Centenary College of Louisiana in 2006 and 2013, respectively. He also received his Master of Energy Business from the University of Tulsa in 2015.

Patrick H. McGough has been our Vice President of Operations since 2019 following our acquisition of Covey Park Energy, LLC. He joined Covey Park in August 2018 as the Vice President of Operations, where he was responsible for drilling, completion, and production operations and engineering. Prior to his time at Covey Park, Mr. McGough held significant roles as a drilling, completion, and production engineer at Brammer Engineering. Mr. McGough received a Bachelor of Science in Chemical Engineering from Louisiana Tech University in 2003 and an MBA from Centenary College of Louisiana in 2010.

Ronald E. Mills has been our Vice President of Finance and Investor Relations since 2019. Prior to joining us, Mr. Mills was an Equity Member and Senior Analyst responsible for covering exploration and production companies at Johnson Rice & Company LLC. Mr. Mills joined Johnson Rice in August 1995. Mr. Mills received a Bachelor of Arts in Economics and Master of Business Administration from Tulane University in 1994 and 1995, respectively.

Daniel K. Presley has been our Treasurer since 2013. Mr. Presley, who has been with us since 1989, also continues to serve as our Vice President of Accounting and Controller, positions he has had held since 1997 and 1991, respectively. Prior to joining us, Mr. Presley had six years of experience with several independent oil and gas companies including AmBrit Energy, Inc. Prior thereto, Mr. Presley spent two and one-half years with B.D.O. Seidman, a public accounting firm. Mr. Presley received a Bachelor of Business Administration degree from Texas A & M University in 1983.

LaRae L. Sanders has been our Vice President of Land since 2014. Ms. Sanders has been with us since 1995. She has served as Land Manager since 2007 and has been instrumental in all of our active development programs and major acquisitions. Prior to joining us, Ms. Sanders held positions with Bridge Oil Company and Kaiser-Francis Oil Company, as well as other independent exploration and production companies. Ms. Sanders is a Certified Professional Landman and became the nation's first Certified Professional Lease and Title Analyst in 1990.

Brian C. Claunch has been our Vice President of Financial Reporting since 2021. Mr. Claunch joined the Company in 2020 as Director of Financial Reporting. Prior to joining Comstock, Mr. Claunch served as Director of Financial Reporting at Guidon Energy and Controller at Pioneer Natural Resources Company. He received his Bachelor of Business Administration and Master of Science in Accounting degrees from the University of Texas at Arlington in 1999 and is a Certified Public Accountant.

Outside Directors

Elizabeth B. Davis has served as a director since 2014. Dr. Davis is currently the President of Furman University. Dr. Davis was the Executive Vice President and Provost for Baylor University until July 2014 and served as Interim Provost from 2008 until 2010. Prior to her appointment as Provost, she was a professor of accounting at the Hankamer School of Business at Baylor University where she also served as associate dean for undergraduate programs and as acting chair for the Department of Accounting and Business Law. Prior to joining Baylor University, she worked for the public accounting firm Arthur Andersen from 1984 to 1987.

Morris E. Foster has served as a director since 2017. Mr. Morris retired in 2008 as Vice President of ExxonMobil Corporation and President of ExxonMobil Production Company following more than 40 years of service with the ExxonMobil group. Mr. Foster served in a number of production engineering and management roles domestically as well as in the United Kingdom and Malaysia prior to his appointment in 1995 as a Senior Vice President in charge of the upstream business of Exxon Company, USA. In 1998, Mr. Foster was appointed President of Exxon Upstream Development Company and following the merger of Exxon and Mobil in 1999, he was named to the position of President of ExxonMobil Development Company. In 2004, Mr. Foster was named President of Exxon Mobil Production Company, the division responsible for ExxonMobil's upstream oil and gas exploration and production business, and a Vice President of ExxonMobil Corporation. Mr. Foster currently serves as Chairman of Stagecoach Properties Inc., a real estate holding corporation with properties in Salado, Houston

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and College Station, Texas and Carmel, California and as a member of the Board of Regents of Texas A&M University. In addition, Mr. Foster currently serves on the board of directors of Scott & White Medical Institute.

Jim L. Turner has served as a director since 2014. Mr. Turner currently serves as Chairman of Turner Holdings, LLC and CEO of JLT Automotive, Inc. Mr. Turner served as President and Chief Executive Officer of Dr Pepper/Seven Up Bottling Group, Inc. from its formation in 1999 through 2005, when he sold this interest in that company. Prior to that, Mr. Turner served as Owner/Chairman of the Board and Chief Executive Officer of the Turner Beverage Group, the largest privately owned independent bottler in the United States. Mr. Turner is past-Chairman and served on the Board of Trustees of Baylor Scott and White Health, the largest not-for-profit healthcare system in the State of Texas from 2013 through 2025, where he also served as Chairman of the Finance Committee and as a member of the Executive Committee. He is a past board member of Crown Holdings where he also served as Chairman of the Compensation Committee and as a member of the Nominating and Governance Committee. He is on the Board of Directors of INSURICA, a full-service insurance agency. Mr. Turner is former Chairman of Dean Foods Company where he also served as Chairman of the Compensation Committee and as a member of the Governance Committee.

Available Information

We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934. The SEC maintains a website that contains reports, proxy and information statements, and other information that is electronically filed with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov. We also make available free of charge on our website (www.comstockresources.com) our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we file such material with, or furnish it to, the SEC.

ITEM 1A. RISK FACTORS

You should carefully consider the following material risk factors as well as the other information contained or incorporated by reference in this report, as these important factors, among others, could cause our actual results to differ from our expected or historical results. It is not possible to predict or identify all such factors. Consequently, you should not consider any such list to be a complete statement of all of our potential risks or uncertainties. Based on the information currently known to us, we believe the following information identifies the most material risk factors affecting us, but the below risks and uncertainties are not the only ones related to our businesses and are not necessarily listed in the order of their significance. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business.

An extended period of depressed natural gas prices would adversely affect our business, financial condition, cash flow, liquidity, results of operations and our ability to meet our capital expenditure obligations and financial commitments.

Our business is heavily dependent upon the price of and demand for natural gas. Historically, natural gas prices have been volatile and are likely to remain volatile in the future. The prices we receive for our natural gas production depend on numerous factors beyond our control, including the following:

•the domestic and foreign supply of natural gas;

•weather conditions;

•the price and quantity of exports of natural gas;

•political conditions and events in other natural gas-producing countries, including embargoes and other sustained military campaigns, acts of terrorism or sabotage, and armed conflicts;

•tariffs and trade restrictions that may be imposed by the United States or other countries on natural resources, including natural gas;

•domestic government regulation, legislation and policies;

•the level of global natural gas inventories;

•technological advances affecting energy consumption;

•the price and availability of alternative fuels; and

•overall U.S. and global economic and political conditions, including inflationary pressures, interest rate adjustments, a general economic slowdown or recession, political tensions and war (including future developments in the ongoing Russia-Ukraine conflict and conflicts in the Middle East).

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Lower natural gas prices will adversely affect:

•our revenues, profitability and cash flow from operations;

•the value of our proved natural gas reserves;

•the economic viability of certain of our drilling prospects;

•our borrowing capacity; and

•our ability to obtain additional capital.

Our future production and revenues depend on our ability to replace our reserves.

Our future production and revenues depend upon our ability to find, develop or acquire additional natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful drilling activities or acquire properties containing proved reserves, or both. To increase reserves and production, we must continue our acquisition and drilling activities. We cannot assure you that we will have adequate capital resources to conduct acquisition and drilling activities or that our acquisition and drilling activities will result in significant additional reserves or that we will have continuing success drilling productive wells at low finding and development costs. Furthermore, while our revenues may increase if prevailing natural gas and oil prices increase significantly, our finding costs for additional reserves could also increase.

Prospects that we decide to drill may not yield natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return and firm transportation commitments.

A prospect is a property in which we own an interest, or have operating rights to, and that has what our geoscientists believe, based on available seismic and geological information, to be an indication of potential oil or natural gas. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional evaluation and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in commercial quantities. The analysis that we perform using data from other wells, more fully explored prospects and/or producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling prospects. If we drill additional unsuccessful wells, our drilling success rate may decline and we may not achieve our targeted rate of return. Further, unsuccessful drilling may impact our ability to fulfill our firm transportation commitments.

Market conditions or operational impediments may hinder our access to natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory natural gas transportation arrangements may hinder our access to natural gas markets or delay our production. The availability of a ready market for our natural gas production depends on a number of factors, including the demand for and supply of natural gas and the proximity of reserves to pipelines and processing facilities. Our ability to market our production depends in a substantial part on the availability and capacity of gathering systems, pipelines and processing facilities, which, in some cases, may be owned and operated by third parties. Our failure to obtain such services on acceptable terms, if at all, could materially harm our business. We may be required to shut in wells due to a lack of market demand or because of the inadequacy or unavailability of pipelines or gathering system capacity. If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.

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Some of our undeveloped leasehold acreage is subject to leases that will expire unless production is established on units containing the acreage. Failure to administer lease acquisitions, lease contracting, lease maintenance and timely lease payments could lead to loss of leased land.

A large portion of our undeveloped leasehold acreage is subject to leases with primary terms that expire prior to 2028 unless we establish and maintain production on units containing these leases during their terms or we renew them before their expiration. The cost to renew such leases could increase significantly and we may not be able to renew such leases on economically beneficial terms or at all. If our leases expire or we are unable to renew such leases, we will lose our right to develop such leasehold acreage and our exploration and development activities could materially differ from our current expectations, which could adversely affect our business.

The unavailability or high cost of drilling rigs, completion equipment, supplies, qualified personnel and oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

When drilling and completion activity in the United States or a particular operating area increases, associated costs also increase, including costs associated with drilling rigs, completion equipment, drill pipe, casing and other tubular goods, sand and other proppants, personnel and other related services. If these costs increase, we may not be able to obtain necessary equipment, supplies and services or obtain them at economically beneficial terms. Such increases in cost could result in delays in our drilling or completion activities, which could limit our ability to establish and replace reserves, or should we choose to incur higher costs, could negatively impact our business.

Substantial exploration and development activities could require significant outside capital, which could dilute the value of our common shares and restrict our activities. Also, we may not be able to obtain needed capital or financing on satisfactory terms, which could lead to a limitation of our future business opportunities and a decline in our natural gas and oil reserves.

We expect to continue to expend substantial capital in the acquisition of, exploration for and development of natural gas reserves. In order to finance these activities, we may need to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of non-strategic assets or other means. The issuance of additional equity securities could have a dilutive effect on the value of our common shares and may not be possible on terms acceptable to us given the current volatility in the financial markets. The issuance of additional debt would likely require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions, dividends and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Our cash flow from operations and access to capital is subject to a number of variables, including:

•our estimated proved reserves;

•the level of natural gas we are able to produce from existing wells;

•our ability to extract natural gas liquids from the natural gas we produce;

•the prices at which natural gas liquids and natural gas are sold; and

•our ability to acquire, locate and produce new reserves.

If our revenues decrease as a result of lower natural gas prices, operating difficulties or declines in reserves, our ability to obtain the capital necessary to undertake or complete future exploration and development programs and to pursue other opportunities may be limited, which could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could result in a decline in our natural gas and oil reserves.

We pursue acquisitions as part of our growth strategy and there are risks associated with such acquisitions.

Our growth has been attributable in part to acquisitions of producing properties and companies. Recently we have been focused on acquiring acreage for our drilling program. We expect to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms we consider favorable. However, we cannot assure you that suitable acquisition candidates will be identified in the future, or that we will be able to finance such acquisitions on favorable terms. In addition, we compete against other companies for acquisitions, and we cannot assure you that we will successfully acquire any material property interests. Further, we cannot assure you that future acquisitions by us will be integrated successfully into our operations or will increase our profits.

The successful acquisition of producing properties requires an assessment of numerous factors beyond our control, including, without limitation:

•recoverable reserves;

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•exploration potential;

•future natural gas prices;

•operating costs; and

•potential environmental and other liabilities.

In connection with such assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. The resulting assessments are inexact and their accuracy uncertain, and such a review may not reveal all existing or potential problems, nor will it necessarily permit us to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is made.

Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics or geographic location than our existing properties. While our current operations are focused in Texas and Louisiana, we may pursue acquisitions or properties located in other geographic areas.

Our operations may incur substantial liabilities due to compliance with environmental laws and regulations.

We are subject to stringent federal, state and local laws. These laws, among other things, govern the issuance of permits to conduct exploration, drilling and production operations, the amounts and types of materials that may be released into the environment, the discharge and disposition of waste materials, the remediation of contaminated sites and the reclamation and abandonment of wells, sites and facilities. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and even criminal penalties for failure to comply. The regulatory burden on the natural gas and oil industry from these environmental laws and regulations increases our cost of doing business and consequently affects our profitability.

Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements or new regulatory schemes such as carbon "cap and trade" or pricing programs could have a material adverse effect upon our capital expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas.

Our business involves many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our success depends on the success of our exploration and development activities. Exploration activities involve numerous risks, including the risk that no commercially productive natural gas reserves will be discovered. In addition, these activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their costs, unsuccessful wells can hurt our efforts to replace production and reserves.

Our business involves a variety of operating risks, including:

•unusual or unexpected geological formations;

•fires;

•explosions;

•blow-outs and surface cratering;

•uncontrollable flows of natural gas and formation water;

•natural disasters, such as hurricanes, tropical storms and other adverse weather conditions;

•pipe, cement, or pipeline failures;

•casing collapses;

•mechanical difficulties, such as lost or stuck oil field drilling and service tools;

•abnormally pressured formations; and

•environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

If we experience any of the above operating risks, our well bores, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations.

We could also incur substantial losses as a result of:

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•injury or loss of life;

•severe damage to and destruction of property, natural resources and equipment;

•pollution and other environmental damage;

•clean-up responsibilities;

•regulatory investigation and penalties;

•suspension of our operations; and

•repairs to resume operations.

We maintain insurance against "sudden and accidental" occurrences, which may cover some, but not all, of the risks described above. Most significantly, the insurance we maintain will not cover the risks described above which occur over a sustained period of time. Further, there can be no assurance that such insurance will continue to be available to cover all such cost or that such insurance will be available at a cost that would justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and results of operations.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of these programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include loss of our communication links, our inability to find, produce, process and sell natural gas and oil and the inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any of these consequences could have a material effect on our business.

Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions.

We rely on information technology and operational technology systems to process, transmit, and store information, to manage and support a variety of business processes and activities, and to comply with regulatory, legal and tax requirements. Our information technology and operational technology systems, some of which are dependent on third-party business partners, may be vulnerable to damage, interruption or shutdown due to any number of causes outside of our control such as catastrophic events, natural disasters, fires, power outages, systems failures, telecommunications failures and employee error or malfeasance. As a natural gas and oil producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security or operation of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cybersecurity attacks in particular are evolving and include, but are not limited to, ransomware or other malicious software, social engineering attacks, deepfakes and artificial intelligence ("AI")-enhanced phishing, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Threat actors may leverage AI and machine learning, technologies to conduct more sophisticated surveillance, reconnaissance and attacks against our systems. We seek to prevent, detect and investigate cybersecurity incidents, but in some cases, we might be unaware of an incident or its magnitude and effects. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing.

Further, we rely on third-party service providers and technologies on a limited basis to operate business systems to process sensitive information in a variety of contexts, including, without limitation, cloud-based infrastructure, encryption and authentication technology and other similar functions. Our ability to monitor these third parties' information security practices is limited, and these third parties may not have adequate information security measures in place, or they may suffer unexpected power losses or computer system or data network failures that negatively impact the systems or solutions on which we rely. If our third-party service providers experience a security incident or other type of interruption or if an unexpected flaw or failed software update related to third-party software used in our information systems occurs, even if inadvertent, our information systems may become disabled or inaccessible and access to our data and other business information may be limited, which could materially disrupt our operations.

If any of these events were to materialize, either to the Company or a third party upon which we rely, they could lead to, without limitation, any of the following:

•Loss of or damage to our data, intellectual property, or other proprietary or confidential information;

•Interruption or degradation of our operations, services, or systems availability;

•Compromise or corruption of our data or systems integrity;

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•Reputational harm or loss of customer trust or confidence;

•Legal liability, regulatory fines, penalties, or sanctions;

•Remediation or mitigation costs, such as increased security expenditures, investigation expenses, or litigation fees;

•Increased insurance premiums or difficulty in obtaining adequate insurance coverage; or

•Other negative consequences.

We face a growing regulatory landscape around data protection and cybersecurity incident reporting, including, but not limited to, new SEC rules requiring disclosure of material cybersecurity incidents within specified timeframes which may result in proposed rulemaking affecting incident reporting requirements for our industry.

Any of the foregoing could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.

We are subject to extensive governmental laws and regulations that may adversely affect the cost, manner or feasibility of doing business.

Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, natural gas and oil, as well as the safe operations thereof. Future laws or regulations, adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with present and future governmental laws and regulations, such as:

•lease permit restrictions;

•drilling bonds and other financial responsibility requirements, such as plug and abandonment bonds;

•spacing of wells;

•unitization and pooling of properties;

•safety precautions;

•regulatory requirements; and

•taxation.

Under these laws and regulations, we could be liable for:

•personal injuries;

•property and natural resource damages;

•well reclamation costs; and

•governmental sanctions, such as fines and penalties.

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions. There are also costs associated with responding to changing regulations and policies, whether such regulations are more or less stringent. As such, there can be no assurance that material cost and liabilities will not be incurred in the future.

Our debt service requirements could adversely affect our operations and limit our growth.

We had $2.8 billion principal amount of debt as of December 31, 2025.

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Our outstanding debt has important consequences, including, without limitation:

•a portion of our cash flow from operations is required to make debt service payments;

•our ability to borrow additional amounts for capital expenditures (including acquisitions) or other purposes is limited; and

•our debt limits (i) our ability to capitalize on significant business opportunities, (ii) our flexibility in planning for or reacting to changes in market conditions, and (iii) our ability to withstand competitive pressures and economic downturns.

Future acquisitions or development activities may require us to alter our capitalization significantly. These changes in capitalization may significantly increase our debt. Moreover, our ability to meet our debt service obligations and to reduce our total debt will be dependent upon our future performance, which will be subject to general economic conditions and financial, business and other factors affecting our operations, many of which are beyond our control. If we are unable to service our indebtedness and to meet other commitments, we will be required to adopt one or more alternatives, such as refinancing or restructuring our indebtedness, selling material assets or seeking to raise additional debt or equity capital. We cannot assure you that any of these actions could be affected on a timely basis or on satisfactory terms or that these actions would enable us to continue to satisfy our capital requirements.

Our debt agreements contain a number of significant covenants. These covenants limit our ability to, among other things:

•borrow additional money;

•merge, consolidate or dispose of assets;

•make certain types of investments;

•enter into transactions with our affiliates; and

•pay dividends.

Our failure to comply with any of these covenants could cause a default under our bank credit facility and the indentures governing our outstanding notes. A default, if not waived, could result in acceleration of our indebtedness, in which case the debt would become immediately due and payable. If this occurs, we may not be able to repay our debt or borrow sufficient funds to refinance it given the current status of the credit markets. Even if new financing is available, it may not be on terms that are acceptable to us. Furthermore, our bank credit facility is subject to various interest rates that are tied to adjusted Secured Overnight Financing Rate ("SOFR") or an alternate base rate, at our option. Any increase in these interest rates would have an adverse impact on our results of operations and cash flow.

Complying with these covenants may cause us to take actions that we otherwise would not take or not take actions that we otherwise would take.

Our hedging transactions could result in financial losses or could reduce our income. To the extent we have hedged a significant portion of our expected production and our actual production is lower than we expected or the costs of goods and services increase, our profitability would be adversely affected.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of natural gas, we have entered into and may continue to enter into hedging transactions for certain of our expected natural gas production. These transactions could result in both realized and unrealized hedging losses. Further, these hedges may be inadequate to protect us from prolonged declines in the price of natural gas. To the extent that natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same level as our current hedges, and our results of operations and financial condition would be negatively impacted.

The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we utilize are primarily based on NYMEX futures prices, which may differ significantly from the actual natural gas prices we realize in our operations. Furthermore, we have adopted a policy that requires that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we will continue to have direct commodity price exposure on the portion of our production volumes not covered by these derivative financial instruments.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions. If our actual future production is higher than we estimated, we will have greater commodity price exposure than we intended. If our actual future production is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution in our profitability and

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liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.

In addition, our hedging transactions are subject to the following risks:

•we may be limited in receiving the full benefit of increases in natural gas prices as a result of these transactions;

•a counterparty may not perform its obligation under the applicable derivative financial instrument or may seek bankruptcy protection;

•there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

•the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

We may be subject to physical and financial risks associated with climate-related effects.

Changing climate and weather conditions may create physical and financial risks to our business. Energy needs vary with weather conditions. To the extent weather conditions may be affected by climate change, energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. Extreme weather conditions in general require more equipment redundancy, adding to costs, and can ‎contribute to increased risk of delivery disruptions.

Additionally, extreme adverse weather conditions or volatility may lead to higher insurance costs, or a decrease in available coverage, for our assets in areas subject to severe weather. These climate-related changes could damage our physical assets, especially operations located in low-lying areas near coasts and riverbanks, and facilities situated in hurricane-prone and rain-susceptible regions. To the extent the frequency of extreme weather events increases, this could increase our cost of producing products. We may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical risks.

Environmental regulations relating to climate change and/or greenhouse gases could also reduce demand for our products or increase our operating and drilling costs. Our business could also be affected by the potential for lawsuits against companies that emit greenhouse gases, based on links drawn between greenhouse gas emissions and climate conditions. To the extent financial markets view GHG emissions as a financial risk, this could negatively impact our cost of and access to capital.

Scrutiny and uncertain expectations from stakeholders with respect to our environmental, social and governance practices may impose additional costs on us or expose us to new or additional risks.

Companies across all industries are facing scrutiny from stakeholders related to their environmental, social and governance ("ESG") practices. Different stakeholders, including investor advocacy groups, certain institutional investors, investment funds, other influential investors, consumers and governmental agencies have varied and often conflicting perspectives on ESG practices. Companies that do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or that are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.

Additionally, adverse effects upon the oil and gas industry related to the worldwide social and political environment, including uncertainty or instability resulting from climate change, changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and renewable energy, concern about the environmental impact of climate change, and investors' expectations regarding ESG matters, may also adversely affect demand for our products. Any long-term material adverse effect on the natural gas and oil industry could have a significant financial and operational adverse impact on our business.

The occurrence of any of the foregoing could have a material adverse effect on the price of our stock and our business and financial condition.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

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We face various cybersecurity threats that could adversely affect our business, financial condition, and results of operations. We have implemented processes and procedures and engaged third-party service providers to assess, identify, and manage these risks, as well as to respond to and mitigate the impact of any potential or actual cybersecurity incidents to our information systems and the information residing therein.

Risk Management and Strategy

Our cybersecurity risk management processes have been integrated into our enterprise risk framework, which identifies, aggregates, and evaluates risks across the enterprise. We identify our enterprise risks through each member of our management team, along with counsel from our internal auditors and attorneys and we present an assessment of our enterprise risks to our board of directors on an annual basis. Our information technology management plays an integral part in the identification and communication of cybersecurity risks to our management team.

Our processes for assessing and identifying cybersecurity risks include, but are not limited to, the following elements:

•regular network security assessments and vulnerability scans performed by third parties;

•third-party audits of our information systems,

•third-party systems for monitoring and analysis of network activity and threat intelligence;

•systems for protecting our information technology, such as firewalls and anti-virus software;

•cybersecurity awareness training for our employees and contractors, including senior management;

•and processes to oversee and identify cybersecurity risks associated with our use of third-party service providers, such as conducting due diligence, reviewing contracts, and verifying compliance with security standards and best practices.

Despite our efforts, there is the ever-present risk that our systems and/or data will suffer a successful cyber incident such as unauthorized access, use, disclosure, modification, or destruction by hackers, cybercriminals, state-sponsored actors, insiders, or other malicious actors. We have experienced attempts to compromise our systems and/or data. These attempts included phishing attacks, malware infections, and unauthorized access attempts. We do not believe that these attempts, if successful, would have resulted in a material adverse effect on our business, financial condition, or results of operations. We continue to be diligent in preventing, detecting, and responding to cyber incidents. However, we cannot guarantee that we will not suffer cybersecurity incidents in the future. See Item 1A. Risk Factors "Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions."

Governance

The Audit Committee of our Board of Directors provides oversight over our cybersecurity risk management and strategy. The committee receives updates from our information technology management and external advisors on our cybersecurity posture, initiatives, and incidents on an annual or as needed basis. Our information technology department is responsible for assessing and managing our cybersecurity risks on a day-to-day basis and their processes for managing cybersecurity risks include implementing and maintaining security controls, policies, and procedures to protect our information systems and the information residing therein. They also provide periodic awareness notifications to our employees and contractors on cybersecurity best practices and their roles and responsibilities. In addition, we have established an incident response plan to coordinate our response to and recovery from any cybersecurity incidents. Our Director of Information Technology has over 20 years of experience in managing organizations in the energy and telecom industries. We also have a Certified Information Systems Security Professional, who has nine years of experience in cyber and information security.

ITEM 2. PROPERTIES

The information set forth under Item 1 of this Annual Report is incorporated herein by reference.

ITEM 3. LEGAL PROCEEDINGS

We are not a party to any legal proceedings which management believes will have a material adverse effect on our consolidated results of operations or financial condition.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is listed for trading on the New York Stock Exchange and the New York Stock Exchange Texas under the symbol "CRK". As of February 18, 2026, we had 294,021,740 shares of common stock outstanding, which were held by 150 holders of record. We have not paid a dividend on our common stock since 2023. The declaration and payment of future dividends will be at the discretion of the board of directors and will depend upon the results of our operations, capital requirements, our financial condition and such other factors as our board of directors may deem relevant.

Stockholder Return Performance

The following graph compares the yearly percentage change in the cumulative total stockholder return on our common stock during the five years ended December 31, 2025 with the cumulative returns during the same period for the New York Stock Exchange Index and the SPDR Standard & Poor's ("S&P") Oil and Gas Exploration and Production ETF. The graph assumes that $100.00 was invested on the last trading day of 2020, and that dividends, if any, were reinvested.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN (1)

Among Comstock, the NYSE Composite Index and the S&P Oil & Gas Exploration and Production ETF Index

	As of December 31,
Total Return Analysis	2020		2021		2022		2023		2024		2025
Comstock	$	100.00	$	185.13	$	315.87	$	213.56	$	439.66	$	559.35
NYSE Composite	$	100.00	$	120.68	$	109.39	$	124.46	$	144.12	$	169.62
SPDR S&P Oil and Gas Exploration and Production ETF	$	100.00	$	166.74	$	242.38	$	251.01	$	248.50	$	243.15

_______________

(1)The data contained in the above graph is deemed to be furnished and not filed pursuant to Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that section.

ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our selected historical consolidated financial data and our accompanying consolidated financial statements and the notes to those financial statements included elsewhere in this report. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in "Risk Factors" and "Cautionary Note Regarding Forward-Looking Statements."

Overview

We are an independent energy company engaged in the acquisition, exploration, development and production of natural gas and oil in the United States. Our assets are concentrated in the Haynesville and Bossier shale located in North Louisiana and East Texas, a premier natural gas basin with superior economics due to the geographic proximity to Gulf Coast natural gas markets. We own interests in 1,724 producing natural gas and oil wells (959.7 net to us) and we operate 1,074 of these wells.

We use the successful efforts method of accounting, which allows only for the capitalization of costs associated with developing proven natural gas and oil properties as well as exploration costs associated with successful exploration activities. Accordingly, our exploration costs consist of costs we incur to acquire seismic data used for exploration, impairments of our unevaluated leasehold where we were not successful in discovering reserves and the costs of unsuccessful exploratory wells that we drill.

We generally sell our natural gas and oil at current market prices at the point where our wells connect to third party purchaser pipelines or terminals. We have entered into certain transportation and treating agreements with midstream and pipeline companies to transport a substantial portion of our natural gas production to long-haul gas pipelines. We market our products in several different ways depending upon a number of factors, including the availability of purchasers for the product, the availability and cost of pipelines near our wells, market prices, pipeline constraints and operational flexibility. Accordingly, our revenues are heavily dependent upon the prices of and demand for natural gas. Natural gas prices have historically been volatile and are likely to remain volatile in the future.

Our operating costs are generally comprised of several components, including costs of our field personnel, insurance, repair and maintenance costs, production supplies, fuel used in operations, transportation costs, workover expenses and state production and ad valorem taxes.

Like all natural gas and oil exploration and production companies, we face the challenge of replacing our reserves. Although in the past we have offset the effect of declining production rates from existing properties through successful acquisition and drilling efforts, there can be no assurance that we will be able to continue to offset production declines or maintain production at current rates through future acquisitions or drilling activity.

Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, natural gas and oil, and operating safety. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may have an adverse effect on our business, results of operations and financial condition. Applicable environmental regulations require us to remove our equipment after production has ceased, to plug and abandon our wells and to remediate any environmental damage our operations may have caused. The present value of the estimated future costs to plug and abandon our natural gas and oil wells and to dismantle and remove our production facilities is included in our reserve for future abandonment costs, which was $20.8 million as of December 31, 2025.

Prices for natural gas and oil have been highly volatile in recent years but we expect our natural gas production to increase in 2026, assuming we maintain a sufficient development program to offset expected production declines from our producing wells. The level of our drilling activity is dependent on natural gas prices. If we are unable to offset production declines with the new wells we plan to drill in 2026 and future periods, our production volumes and cash flows from our operating activities may not be sufficient to fund our capital expenditures, and thus, we may need to either curtail drilling activity or seek additional borrowings, which would result in an increase in our interest expense in 2026 and future periods.

We recognized $29.1 million of impairments to our non-operated Eagle Ford shale unproved and proved properties in 2025 to adjust the carrying value of our Eagle Ford shale assets to their estimated fair value. We may need to recognize further impairments of our natural gas and oil properties if natural gas and oil prices decline, and as a result, the expected future cash flows from these properties become insufficient to recover their carrying value.

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Results of Operations

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024

Our operating data for the year ended December 31, 2025 and 2024 are summarized below:

	Year Ended December 31,
	2025		2024
	(In thousands except per unit amounts)
Net Production Data:
Natural gas (MMcf)		450,202		527,548
Oil (MBbls)		37		50
Natural gas equivalent (MMcfe)		450,423		527,847
Revenues:
Natural gas sales	$	1,425,857	$	1,043,886
Oil sales		2,292		3,597
Total natural gas and oil sales	$	1,428,149	$	1,047,483
Expenses:
Production and ad valorem taxes	$	40,453	$	57,437
Gathering and transportation	$	166,108	$	194,890
Lease operating	$	122,662	$	130,504
Exploration	$	10,071	$	—
Average Sales Price:
Natural gas (per Mcf)	$	3.17	$	1.98
Oil (per Bbl)	$	61.95	$	71.94
Average equivalent (Mcfe)	$	3.17	$	1.98
Expenses ($ per Mcfe):
Production and ad valorem taxes	$	0.09	$	0.11
Gathering and transportation	$	0.37	$	0.37
Lease operating	$	0.27	$	0.25
Gas Services:
Gas services revenue	$	500,202	$	206,097
Gas services expense	$	516,224	$	205,407

Natural gas and oil sales. Natural gas and oil sales of $1.4 billion in 2025 increased by $0.4 billion, or 36%, as compared to $1.0 billion in 2024. The increase was primarily due to higher prices received for our natural gas production. Our 2025 natural gas production decreased 15% to 450.2 Bcf (1.2 Bcf per day), which was sold at an average price of $3.17 per Mcf as compared to 527.5 Bcf (1.4 Bcf per day) sold at an average price of $1.98 in 2024.

We utilize natural gas derivative financial instruments to manage our exposure to changes in prices of natural gas to protect returns on investment from our drilling activities. The following table presents our natural gas prices before and after the effect of cash settlements of our derivative financial instruments:

	Year Ended December 31,
	2025		2024
Average Realized Natural Gas Price:
Natural gas, per Mcf	$	3.17	$	1.98
Cash settlements on derivative financial instruments, per Mcf		0.04		0.39
Price per Mcf, including cash settlements on derivative    financial instruments	$	3.21	$	2.37

Gas services revenues. Gas services revenues of $500.2 million in 2025 increased $294.1 million (143%) from $206.1 million in 2024. Gas services activities include sales of natural gas purchased from unaffiliated third parties for resale and fees received from unaffiliated third parties for natural gas gathering and treating services. Gas services revenues increased in 2025 due primarily to higher natural gas prices on sales of natural gas purchased to utilize our excess transport capacity.

Gain on sale of assets. We reported a gain on sale of assets of $291.9 million in 2025, which was primarily related to the divestiture of our Shelby Trough properties in East Texas for net proceeds of $417.2 million. We also sold our interest in

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our Cotton Valley properties in East Texas and North Louisiana for net proceeds of $15.2 million. In 2024, we sold our interest in certain non-operated properties and realized a gain of $0.9 million.

Production and ad valorem taxes. Our production and ad valorem taxes decreased $17.0 million (30%) to $40.5 million in 2025 from $57.4 million in 2024. This decrease was primarily related to a decrease in Louisiana production tax and ad valorem tax rates and lower natural gas production volumes in 2025.

Gathering and transportation. Gathering and transportation costs decreased $28.8 million (15%) to $166.1 million in 2025 as compared to $194.9 million in 2024. This decrease was due primarily to lower production volumes in 2025.

Lease operating expenses. Our lease operating expense of $122.7 million ($0.27 per Mcfe) in 2025 was $7.8 million, or 6% lower than lease operating expenses in 2024 of $130.5 million ($0.25 per Mcfe). The decrease in lease operating expense was due to lower production volumes as compared to 2024.

Gas services expenses. Gas services expenses of $516.2 million in 2025 were $310.8 million (151%) higher than gas services expenses in 2024 of $205.4 million. The increase was due primarily to higher natural gas prices for purchases of third-party natural gas for resale.

Depreciation, depletion and amortization expense ("DD&A"). DD&A expense decreased $154.2 million (19%) to $641.2 million in 2025 from $795.4 million in 2024. Our DD&A expense per equivalent Mcf produced was $1.42 per Mcfe in 2025 as compared to $1.51 per Mcfe in 2024. The decrease in DD&A rate was primarily due to the increase in estimated proved undeveloped reserves used in determining the DD&A rate, which resulted from the higher natural gas price used in the estimation of proved reserves at December 31, 2025.

General and administrative expenses. General and administrative expenses, which are reported net of overhead reimbursements, increased to $48.7 million in 2025 from $39.4 million in 2024 due primarily to higher personnel costs including stock-based compensation. Stock-based compensation included in general and administrative expenses was $21.2 million and $15.3 million in 2025 and 2024, respectively.

Impairment of oil and gas properties. We recorded an impairment to our Eagle Ford shale proved and unproved natural gas and oil properties of $29.1 million in 2025. This charge primarily resulted from diminished activity on our leasehold acreage in the area by operators, low oil prices and our capital allocation strategy, which prioritizes higher-return projects in the Haynesville and Bossier shales.

Derivative financial instruments. We use derivative financial instruments as part of our price risk management program to protect the cash flow we generate from our operating activities. We had net gains on derivative financial instruments of $82.5 million for 2025 as compared to $10.2 million for 2024. Realized net gains from our natural gas price risk management program were $20.1 million in 2025 as compared to $207.8 million in 2024. We recognized unrealized gains on derivative financial instruments of $62.4 million and unrealized losses of $197.6 million in 2025 and 2024, respectively.

Interest expense. Interest expense was $222.8 million for 2025 as compared to $210.6 million for 2024. Included in interest expense was amortization of the premiums or discounts on our senior notes and the debt issuance cost amortization associated with our outstanding debt. The non-cash interest expense for 2025 totaled $12.0 million compared with $11.5 million for 2024. The increase in interest expense in 2025 was due primarily to the issuance of our 6.75% senior notes in 2024 and increased borrowings on our bank credit facility in 2025.

Exploration expense. Exploration expense was $10.1 million in 2025, which was related to the acquisition of seismic data for our Western Haynesville area.

Income taxes. Our income tax provision was $88.5 million in 2025 as compared to a benefit of $149.1 million in 2024. Our effective tax rate of 17% in 2025 differed from the federal income tax rate of 21% due primarily to research and development and other tax credits claimed in 2025 and state income taxes. Our effective tax rate of 41% in 2024 differed from the federal income tax rate of 21% primarily due to changes in our valuation allowance on our federal and state net operating loss carryforwards and state income taxes.

Net income. We reported net income of $420.2 million or $1.43 per diluted share in 2025 and a net loss of $218.8 million or $0.76 per diluted share in 2024. The net income in 2025 is primarily due to the impact of higher natural gas prices in 2025, gain on sale of assets of $291.9 million and the unrealized gain on our derivative financial instruments of $62.4 million. Income from operations in 2025 was $645.9 million as compared to loss from operations of $168.6 million in 2024.

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Year Ended December 31, 2024 Compared to Year Ended December 31, 2023

Discussions of 2024 items and year-to-year comparisons between 2024 and 2023 that are not included in this Annual Report on Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2024 filed with the SEC on February 21, 2025.

Cash Flows, Liquidity and Capital Resources

Cash Flows

The following table summarizes sources and uses of cash and cash equivalents:

	Year Ended December 31,
	2025		2024
	(in thousands)
Sources of cash and cash equivalents:
Operating activities	$	899,607	$	620,337
Proceeds from asset sales		428,868		1,214
Contributions from noncontrolling interest		215,500		60,500
Issuance of 6.75% senior notes		—		372,000
Issuance of common stock		—		100,450
Total	$	1,543,975	$	1,154,501
Uses of cash and cash equivalents:
Capital expenditures	$	1,344,278	$	1,085,490
Repayments on bank credit facility, net of borrowings		155,000		65,000
Distributions to noncontrolling interest		16,520		3,653
Income tax withholdings on equity awards		11,010		3,373
Debt and stock issuance costs		36		6,855
Total	$	1,526,844	$	1,164,371

Cash flows from operating activities. Net cash provided by our operating activities increased $279.3 million (45%) to $899.6 million in 2025 from $620.3 million in 2024. The increase was primarily due to the higher natural gas prices we realized in 2025.

Proceeds from asset sales. In 2025, we sold our Shelby Trough properties in East Texas and our Cotton Valley properties in East Texas and North Louisiana and other assets. In 2024, we sold certain non-operated properties for net proceeds of $1.2 million.

Contributions from and distributions to noncontrolling interest. In 2023, we formed a midstream partnership to fund the future build-out of our Western Haynesville midstream system. During 2025 and 2024, our noncontrolling partner contributed $215.5 million and $60.5 million, respectively, to the midstream partnership. Also during 2025 and 2024, we distributed preferred dividends of $16.5 million and $3.7 million, respectively, to our noncontrolling partner.

Issuance of 6.75% senior notes and debt issuance costs. In April 2024, we issued $400.0 million principal amount of 6.75% senior notes due 2029 in a private placement and received net proceeds after deducting the initial purchasers' discounts of $365.2 million, which were used to pay down outstanding borrowings on our bank credit facility. We incurred $6.8 million of debt issuance costs associated with the senior note issuance.

Issuance of common stock and stock issuance costs. In 2024, we issued 12,500,000 shares of common stock to two entities controlled by our majority stockholder in a private placement, receiving total proceeds of $100.5 million.

Capital expenditures. The increase in capital expenditures of $258.8 million is primarily due to higher drilling and completion activities in 2025.

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COMSTOCK RESOURCES, INC.

Our capital expenditures are summarized in the following table:

	Year Ended December 31,
	2025			2024
	(in thousands)
Acquisitions:
Unproved property	$	54,670		$	106,386
Exploration and development:
Developmental leasehold costs		14,562			13,461
Exploratory drilling and completion costs		490,429			354,557
Development drilling and completion costs		517,375			503,550
Other development costs		32,493			30,500
Asset retirement obligations		444			1,594
Total exploration and development		1,109,973			1,010,048
Midstream		223,592			85,377
Other property		17,893			2,264
Total capital expenditures	$	1,351,458		$	1,097,689
Change in accrued capital expenditures and other		(1,656	)		1,383
Prepaid drilling costs		(5,002	)		(11,988	)
Asset retirement obligations		(522	)		(1,594	)
Total cash capital expenditures	$	1,344,278		$	1,085,490

We currently expect to spend approximately $1.4 billion to $1.5 billion in 2026 on our development and exploration projects primarily focused on the continued development of our Haynesville/Bossier shale properties including the exploration and development of our Western Haynesville acreage. We also expect to spend $100 million to $150 million in our Western Haynesville midstream partnership. Under our 2026 operating plan, we currently expect to drill 66 operated horizontal wells (59.7 net) and to turn 72 operated wells (63.1 net) to sales in 2026.

Liquidity and Capital Resources

As of December 31, 2025, we had $260.0 million outstanding under a bank credit facility. Aggregate commitments under the credit facility are $1.5 billion, which matures on November 15, 2027. Borrowings under the bank credit facility are subject to a borrowing base, which is currently set at $2.0 billion. The borrowing base is re-determined on a semi-annual basis and upon the occurrence of certain other events. Borrowings under the bank credit facility are secured by substantially all of our assets and those of our restricted subsidiaries and bear interest at our option, at either adjusted SOFR plus 2.25% to 3.25% or an alternate base rate plus 1.25% to 2.25%, in each case depending on the utilization of the borrowing base. We also pay a commitment fee of 0.375% to 0.5% on the unused portion of the committed borrowing base. The bank credit facility places certain restrictions upon our and our restricted subsidiaries' ability to, among other things, incur additional indebtedness, pay cash dividends, repurchase common stock, make certain loans, investments and divestitures and redeem our senior notes. The only financial covenants are the maintenance of a leverage ratio of less than 3.5 to 1.0 and an adjusted current ratio of at least 1.0 to 1.0. We were in compliance with the covenants as of December 31, 2025.

As of December 31, 2025, we had $1.3 billion of liquidity, comprised of $1.2 billion of unused borrowing capacity under our bank credit facility and $23.9 million of cash and cash equivalents on hand. Our short and long-term capital requirements consist primarily of funding our development and exploration activities, acquisitions, payments of contractual obligations, and debt service.

We expect to fund our future development and exploration activities with future operating cash flow or borrowings under our bank credit facility. The timing of most of our capital expenditures is mostly discretionary. We have a significant degree of flexibility to adjust the level of our capital expenditures as circumstances warrant. If our plans or assumptions change or prove to be inaccurate, we may be required to seek additional capital, including debt or equity financing. We expect to fund future acquisitions, depending on the size and timing, with future operating cash flow, borrowings under our bank credit facility, or other debt or equity financings, to the extent available. The availability and attractiveness of debt or equity financing will depend upon a number of factors, some of which will relate to our financial condition and performance and some of which will be beyond our control, such as prevailing interest rates, natural gas and oil prices and other market conditions. We cannot provide any assurance that we will be able to obtain such capital, or if such capital is available, that we will be able to obtain it on acceptable terms.

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COMSTOCK RESOURCES, INC.

Our contractual obligations consist primarily of principal and interest payments on our senior notes and bank credit facility, natural gas transportation and gathering contracts and other operating lease obligations. Interest payments under our senior notes and bank credit facility are $182.6 million for 2026, $180.6 million for 2027, $166.3 million for 2028, $75.0 million for 2029 and $2.4 million for 2030. Our natural gas transportation and gathering contracts extend to 2031 and commitments under these contracts are $85.4 million for 2026, $84.2 million for 2027, $79.3 million for 2028, $67.6 million for 2029, $27.7 million for 2030 and $58.9 million for commitments thereafter.

Federal and State Taxation

On December 31, 2025, we had $1.4 billion in U.S. federal net operating loss carryforwards, $1.8 billion in certain state net operating loss carryforwards, $17.7 million of U.S. federal research and development tax credits and $11.0 million of certain state research and development tax credits. As a result of a change of control in August 2018, our ability to use U.S. federal net operating losses ("NOLs") to reduce taxable income is limited. If we do not generate a sufficient level of taxable income prior to the expiration of the pre-2018 NOL carry-forward periods, then we will lose the ability to apply those NOLs as offsets to future taxable income. We estimate that $740.6 million of the U.S. federal NOL carryforwards and $1.2 billion of the estimated state NOL carryforwards will expire unused.

Our federal income tax returns for the years subsequent to December 31, 2021 remain subject to examination. Our income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2022. Currently, we are under examination with the United States Internal Revenue Service and the state of Louisiana and we believe that our significant filing positions are highly certain and that all of our other significant income tax filing positions and deductions will be sustained under audit or the final resolution will not have a material effect on our consolidated financial statements. Therefore, we have not established any significant reserves for uncertain tax positions.

In July 2025, the One Big Beautiful Bill Act ("OBBBA") was signed into United States federal law. We have benefited from certain provisions contained in the OBBBA, including increased interest expense deductions and bonus depreciation, which are included in our income tax provision for the year ending December 31, 2025.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and use assumptions that can affect the reported amounts of assets, liabilities, revenues or expenses.

Successful efforts accounting. We are required to select among alternative acceptable accounting policies. There are two generally acceptable methods for accounting for natural gas and oil producing activities. The full cost method allows the capitalization of all costs associated with finding natural gas and oil reserves. The successful efforts method allows only for the capitalization of costs associated with developing proven natural gas and oil properties as well as exploration costs associated with successful exploration projects. Costs related to exploration that are not successful are expensed when it is determined that commercially productive oil and gas reserves were not found. We have elected to use the successful efforts method to account for our oil and gas activities.

Natural gas and oil reserve quantities. The determination of depreciation, depletion and amortization expense is highly dependent on the estimates of the proved natural gas and oil reserves attributable to our properties. The determination of whether impairments should be recognized on our oil and gas properties is also dependent on these estimates, as well as estimates of probable reserves. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be precisely measured. The accuracy of any reserve estimate depends on the quality of available data, production history and engineering and geological interpretation and judgment. Because all reserve estimates are to some degree imprecise, the quantities and timing of natural gas and oil that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future natural gas and oil prices may all differ materially from those assumed in these estimates. Proved reserve estimates included in this report were prepared by the Company's engineers and audited by independent petroleum engineers.

The information regarding present value of the future net cash flows attributable to our proved natural gas and oil reserves are estimates only and should not be construed as the current market value of the estimated natural gas and oil reserves attributable to our properties. Thus, such information includes revisions of certain reserve estimates attributable to proved properties included in the preceding year's estimates. Such revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Any future downward revisions could adversely affect our financial condition, our future prospects and the value of our common stock.

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Impairment of natural gas and oil properties. We evaluate our proved properties for potential impairment when circumstances indicate that the carrying value of an asset may not be recoverable. If impairment is indicated based on a comparison of the asset's carrying value to its undiscounted expected future net cash flows, then it is recognized to the extent that the carrying value exceeds fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Expected future cash flows are determined using estimated future prices based on market based forward prices applied to projected future production volumes. The projected production volumes are based on the property's proved and risk adjusted probable natural gas and oil reserves estimates at the end of the period. The estimated future cash flows that we use in our assessment of the need for an impairment are based on a corporate forecast which considers forecasts from multiple independent price forecasts. Prices are not escalated to levels that exceed observed historical market prices. Costs are also assumed to escalate at a rate that is based on our historical experience, currently estimated at 2% per annum. The natural gas and oil prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of the average first day of the month historical price for the year. Unproved properties are evaluated for impairment based upon the results of drilling, planned future drilling and the terms of our natural gas and oil leases. During 2025, we recognized impairment charges of $29.1 million to reduce the capitalized costs of our proved and unproved natural gas and oil properties in the Eagle Ford shale to their fair value. It is reasonably possible that our estimates of undiscounted future net cash flows attributable to our natural gas and oil properties may change in the future. The primary factors that may affect estimates of future cash flows include future adjustments, both positive and negative, to proved and appropriate risk-adjusted probable natural gas and oil reserves, results of future drilling activities, future prices for natural gas and oil, and increases or decreases in production and capital costs. As a result of these changes, there may be further impairments in the carrying values of our proved and unproved natural gas and oil properties in the future.

Income Taxes. We account for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the future tax consequences attributable to the future utilization of existing tax NOLs and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that the change in rate is enacted.

In recording deferred income tax assets, we consider whether it is more likely than not that some portion or all of our deferred income tax assets will be realized in the future. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. We believe that after considering all the available objective evidence, historical and prospective, with greater weight given to historical evidence, we are not able to determine that it is more likely than not that all of our deferred tax assets will be realized. As a result, we established valuation allowances for our deferred tax assets and U.S. federal and state NOL carryforwards that are not expected to be utilized due to the uncertainty of generating taxable income prior to the expiration of the carryforward periods. We will continue to assess the valuation allowances against deferred tax assets considering all available information obtained in future reporting periods.

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COMSTOCK RESOURCES, INC.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of natural gas and oil. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors, some of which are beyond our control. Factors influencing natural gas and oil prices include the level of global demand for oil, the foreign supply of natural gas and oil, the establishment of and compliance with production quotas by oil exporting countries, weather conditions that determine the demand for natural gas, the price and availability of alternative fuels and overall economic conditions. It is impossible to predict future natural gas and oil prices with any degree of certainty. Sustained weakness in natural gas and oil prices may adversely affect our financial condition and results of operations and may also reduce the amount of natural gas and oil reserves that we can produce economically. Any reduction in our natural gas and oil reserves, including reductions due to price fluctuations, can have an adverse effect on our ability to obtain capital for our exploration and development activities. Similarly, any improvements in natural gas and oil prices can have a favorable impact on our financial condition, results of operations and capital resources.

As of December 31, 2025, we had natural gas price swap agreements to hedge approximately 116.8 Bcf of our 2026 production at an average price of $3.51 per MMBtu. We have also entered into natural gas collars to hedge approximately 167.9 Bcf of natural gas with an average floor price of $3.50 per MMBtu and an average ceiling price of $4.35 per MMBtu. None of our derivative contracts have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date.

An increase of 10% in the market price of natural gas on December 31, 2025 would decrease the fair value of our natural gas swaps and collars by approximately $70.4 million. A decrease of 10% in the market price of natural gas on December 31, 2025 would increase the fair value of our natural gas price swaps and collars by approximately $70.0 million. The impact of hypothetical changes in market prices of natural gas on our natural gas derivative financial instruments does not include the offsetting impact that the same hypothetical changes in market prices of natural gas may have on our physical sales of natural gas. Since our outstanding natural gas derivative financial instruments hedge only a portion of our forecasted physical gas production, a positive or negative impact to the fair value of our natural gas derivative financial instruments would be partially offset by our physical sales of natural gas.

Since December 31, 2025, we entered into natural gas collar contracts to hedge an additional 58.4 Bcf of 2027 natural gas production at an average ceiling price of $4.37 per MMBtu and an average floor price of $3.50 per MMBtu.

Interest Rates

At December 31, 2025, we had approximately $2.8 billion principal amount of long-term debt outstanding. $965.0 million of our long-term debt bear interest at a fixed rate of 5.875% and $1.6 billion of our long-term debt bear interest at a fixed rate of 6.75%. The fair market value of the senior notes due 2030 and senior notes due 2029 as of December 31, 2025 were $931.2 million and $1.6 billion, respectively, based on the market price of approximately 97% and 99% of the face amount of such debt. At December 31, 2025, we had $260.0 million of outstanding borrowings under our bank credit facility, which is subject to variable rates of interest that are tied to adjusted SOFR or an alternate base rate, at our option. Any increase in these interest rates would have an adverse impact to our results of operations and cash flow.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Our consolidated financial statements are included on pages F-1 to F-25 of this report.

We have prepared these financial statements in conformity with generally accepted accounting principles. We are responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary for us to make informed estimates and judgments based on currently available information on the effects of certain events and transactions.

Our registered independent public accountants, Ernst & Young LLP, are engaged to audit our financial statements and to express an opinion thereon. Their audit is conducted in accordance with the standards of the Public Company Accounting Oversight Board to enable them to report whether the financial statements present fairly, in all material respects, our financial position and results of operations in accordance with accounting principles generally accepted in the United States.

The audit committee of our board of directors is comprised of three directors who are not our employees. This committee meets periodically with our independent public accountants and management. Our independent public accountants have full and free access to the audit committee to meet, with and without management being present, to discuss the results of their audits and the quality of our financial reporting.

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COMSTOCK RESOURCES, INC.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Controls and Procedures. Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act) are designed to provide reasonable assurance that information required to be disclosed in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

We performed an evaluation of the effectiveness of our disclosure controls and procedures as of December 31, 2025. The evaluation was performed with the participation of senior management of each business segment and key corporate functions, and under the supervision of the Chief Executive Officer and Chief Financial Officer.

Based on our evaluation of our disclosure controls and procedures, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2025 to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and to provide reasonable assurance that information required to be disclosed by us is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting during the quarter ended December 31, 2025 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Management's Report on Internal Control over Financial Reporting. We are responsible for establishing and maintaining adequate internal control over financial reporting for the Company. In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act, we conducted an assessment, including testing, using the criteria in Internal Control — Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the "COSO criteria"). Our system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. As of December 31, 2025, we assessed the effectiveness of the Company's internal control over financial reporting based on the COSO criteria, and based on that assessment we determined that the Company maintained effective internal control over financial reporting as of December 31, 2025.

Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2025. The report, which expresses an unqualified opinion on the effectiveness of the Company's internal control over financial reporting as of December 31, 2025, follows below.

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COMSTOCK RESOURCES, INC.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Comstock Resources, Inc.

Opinion on Internal Control over Financial Reporting

We have audited Comstock Resources, Inc. and subsidiaries' internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Comstock Resources, Inc. and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2025, and the related notes and our report dated February 19, 2026 expressed an unqualified opinion thereon.

Basis for Opinion

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ ERNST & YOUNG LLP

Dallas, Texas

February 19, 2026

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COMSTOCK RESOURCES, INC.

ITEM 9B. OTHER INFORMATION

None.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item is incorporated herein by reference to "Business – Directors and Executive Officers" in this Form 10-K and to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2025.

Code of Ethics. We have adopted a Code of Business Conduct and Ethics that is applicable to all of our directors, officers and employees as required by New York Stock Exchange rules. We have also adopted a Code of Ethics for Senior Financial Officers that is applicable to our Chief Executive Officer and Senior Financial Officers. Both the Code of Business Conduct and Ethics and Code of Ethics for Senior Financial Officers may be found on our website at www.comstockresources.com. Both of these documents are also available, without charge, to any stockholder upon request to: Comstock Resources, Inc., Attn: Investor Relations, 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034, (972) 668-8800. We intend to disclose any amendments or waivers to these codes that apply to our Chief Executive Officer and senior financial officers on our website in accordance with applicable SEC rules. Please see the definitive proxy statement for our 2026 annual meeting, which will be filed with the SEC within 120 days of December 31, 2025, for additional information regarding our corporate governance policies.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2025.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following table summarizes certain information regarding our equity compensation plans as of December 31, 2025:

	Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)	Number of securities authorized for future issuance under equity compensation plans (excluding outstanding options, warrants and rights)
Equity compensation plans approved by stockholders	3,207,832	9,451,616

(1)Represents performance share unit awards that would be issuable based upon achievement of the maximum awards under the terms of the performance share unit awards.

We do not have any equity compensation plans that were not approved by stockholders.

Further information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2025.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2025.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this item is incorporated herein by reference to our definitive proxy statement which will be filed with the SEC within 120 days after December 31, 2025.

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COMSTOCK RESOURCES, INC.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)Financial Statements:

1.	The following consolidated financial statements and notes of Comstock Resources, Inc. are included on Pages F-1 to F-25 under Item 83 Financial Statements and Supplementary Data of this Annual report:
	Report of Independent Registered Public Accounting Firm	F-1
	Consolidated Balance Sheets as of December 31, 2025 and 2024	F-3
	Consolidated Statements of Operations For the Years Ended December 31, 2025, 2024 and 2023	F-4
	Consolidated Statements of Stockholders' Equity	F-5
	Consolidated Statements of Cash Flows For the Years Ended December 31, 2025, 2024 and 2023	F-6
	Notes to Consolidated Financial Statements	F-7
2.	All financial statement schedules are omitted because they are not applicable, or are immaterial or the required information is presented in the consolidated financial statements or the related notes.

(b)Exhibits:

The exhibits to this Annual Report required to be filed pursuant to Item 15(c) are listed below.

Exhibit No.	Description
2.1	Contribution Agreement dated May 9, 2018, by and among Arkoma Drilling, L.P., Williston Drilling, L.P. and the Company (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K/A dated May 9, 2018).
2.2	Amendment No. 1 to the Contribution Agreement, dated as of August 14, 2018, by and among Arkoma Drilling, L.P., Williston Drilling, L.P. and the Company (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K dated August 13, 2018).
3.1	Second Amended and Restated Articles of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated August 13, 2018).
3.2	Amendment to Second Amended and Restated Articles of Incorporation of the Company, dated July 16, 2019 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated July 15, 2019).
3.3	Amended and Restated Bylaws (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated August 21, 2014).
3.4	First Amendment to Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K dated August 17, 2018).
3.5	Amendment No. 2 to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to our Current Report on Form 8-K dated July 15, 2019).
4.1	Indenture dated March 4, 2021, by and among the Company, each of the guarantor subsidiaries named therein, and American Stock Transfer & Trust Company, LLC for the 6.75% Senior Notes due 2029 (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K dated March 4, 2021).
4.2	Indenture dated June 28, 2021, by and among the Company, each of the guarantor subsidiaries named therein, and American Stock Transfer & Trust Company, LLC for the 5.875% Senior Notes due 2030 (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K dated June 28, 2021).
4.3	Indenture dated April 9, 2024, by and among the Company, each of the guarantor subsidiaries named therein, and Equiniti Trust Company, LLC for the 6.75% Senior Notes due 2029 (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K dated April 9, 2024).
4.4	Shareholders Agreement, dated June 7, 2019, by and among the Company, Arkoma Drilling CP, LLC, Williston Drilling CP, LLC, Arkoma Drilling, L.P., Williston Drilling, L.P., New Covey Park Energy LLC and Jerral W. Jones (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated June 10, 2019).

44

COMSTOCK RESOURCES, INC.

4.5*	Description of Securities.
10.1	Second Amended and Restated Credit Agreement dated as of November 15, 2022, among the Company, Wells Fargo Bank National Association as Administrative Agent and the lenders party thereto from time to time (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated November 15, 2022).
10.2	First Amendment to Second Amended and Restated Credit Agreement dated as of October 27, 2023, among the Company, Wells Fargo Bank National Association as Administrative Agent and the lenders party thereto from time to time (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2023).
10.3	Second Amendment to Second Amended and Restated Credit Agreement dated as of October 30, 2024, among the Company, Wells Fargo Bank National Association as Administrative Agent and the lenders party thereto from time to time (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2024).
10.4#	Comstock Resources, Inc. 2019 Long-term Incentive Plan Amended and Restated as of April 7, 2025 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated June 3, 2025).
10.5#	Employment Agreement dated September 7, 2018 by and between the Company and M. Jay Allison (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K dated September 7, 2018).
10.6#	Employment Agreement dated September 7, 2018 by and between the Company and Roland O. Burns (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K dated September 7, 2018).
10.7	Amended and Restated Lease between Stonebriar I Office Partners, Ltd. and Comstock Resources, Inc. dated December 22, 2023 (incorporated by reference to Exhibit 10.6 to our Annual Report on Form 10-K for the year ended December 31, 2023.
19.1	Insider Trading section of our Code of Business Conduct and Ethics (incorporated by reference to Exhibit 19.1 to our Annual Report on Form 10-K for the year ended December 31, 2024).
19.2	Insider Trading sections of our Policy on Compliance with Federal Securities Laws for our Directors and Officers (incorporated by reference to Exhibit 19.2 to our Annual Report on Form 10-K for the year ended December 31, 2024).
21*	Subsidiaries of the Company.
23.1*	Consent of Ernst & Young LLP.
23.2*	Consent of Independent Petroleum Engineers Netherland, Sewell & Associates, Inc.
31.1*	Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1+	Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2+	Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
97.1	Executive Compensation Clawback Policy (as amended and restated) adopted by the Compensation Committee of the Board of Directors of Comstock Resources, Inc., effective as of June 6, 2023 (incorporated by reference to Exhibit 97.1 to our Annual Report on Form 10-K for the year ended December 31, 2023).
99.1*	Audit Letter of Netherland, Sewell & Associates, Inc. on Proved Reserves as of December 31, 2025.
101.INS*	XBRL Instance Document
101.SCH*	Inline XBRL Taxonomy Extension Schema With Embedded Linkbases Document
104*	Cover Page Interactive Data File (embedded within the Inline XBRL document)

_______________

* Filed herewith.

+ Furnished herewith.

# Management contract or compensatory plan document.

ITEM 16. FORM 10-K SUMMARY

Not applicable.

45

COMSTOCK RESOURCES, INC.

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.

	COMSTOCK RESOURCES, INC.
	By:	/s/ M. JAY ALLISON
		M. Jay Allison Chief Executive Officer
Date: February 19, 2026		(Principal Executive Officer)

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.

/s/ M. JAY ALLISON	Chief Executive Officer and	February 19, 2026
M. Jay Allison	Chairman of the Board of Directors (Principal Executive Officer)
/s/ ROLAND O. BURNS	President, Chief Financial Officer,	February 19, 2026
Roland O. Burns	Secretary and Director (Principal Financial and Accounting Officer)
/s/ ELIZABETH B. DAVIS	Director	February 19, 2026
Elizabeth B. Davis
/s/ MORRIS E. FOSTER	Director	February 19, 2026
Morris E. Foster
/s/ JIM L. TURNER	Director	February 19, 2026
Jim L. Turner

46

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

FINANCIAL STATEMENTS

INDEX

Report of Independent Registered Public Accounting Firm (PCAOB ID: 42)	F-1
Consolidated Balance Sheets as of December 31, 2025 and 2024	F-3
Consolidated Statements of Operations For the Years Ended December 31, 2025, 2024 and 2023	F-4
Consolidated Statements of Stockholders' Equity	F-5
Consolidated Statements of Cash Flows For the Years Ended December 31, 2025, 2024 and 2023	F-6
Notes to Consolidated Financial Statements	F-7

47

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Comstock Resources, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Comstock Resources, Inc. and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 19, 2026 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Depreciation, Depletion and Amortization of Proved Natural Gas and Oil Properties

Description of the Matter

At December 31, 2025, the net book value of the Company's proved natural gas and oil properties was $5,445 million, and depreciation, depletion and amortization expense ("DD&A") was $641 million for the year then ended. As described in Note 1 to the consolidated financial statements, the Company follows the successful efforts method of accounting for its natural gas and oil properties. Under this method, the capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves, as estimated by the Company's engineers. Proved natural gas and oil reserve estimates are impacted by various inputs, including historical production, natural gas and oil price assumptions, and future operating and capital cost assumptions, among others, and requires the expertise of the Company's engineers in evaluating and interpreting the relevant data. Because of the complexity involved in estimating natural gas and oil reserves, management used independent petroleum engineers to audit the estimates prepared by the Company's engineers as of December 31, 2025.

F-1

Auditing the impact of proved natural gas and oil reserves on DD&A is especially complex because of the use of the work of the Company's engineers and the independent petroleum engineers and the evaluation of management's determination of the inputs described above used by the engineers in estimating proved natural gas and oil reserves.

How We Addressed the Matter in Our Audit

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's estimates of proved natural gas and oil reserve volumes. The work of management's specialists was used in performing the procedures to evaluate the reasonableness of the proved natural gas and oil reserve volumes. As a basis for using this work, the specialists' qualifications were understood and the Corporation's relationship with the specialists was assessed. The procedures performed also included i) evaluating the methods and assumptions used by the specialists, ii) testing the completeness and accuracy of the data used by the specialists related to historical production volumes, iii) evaluating the specialists' findings related to estimated future production volumes by comparing the estimate to relevant historical and current period information, iv) for proved undeveloped reserves, we evaluated management's development plan for compliance with SEC requirements, as applicable.

/s/ ERNST & YOUNG LLP

We have served as the Company's auditor since 2003.

Dallas, Texas

February 19, 2026

F-2

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	As of December 31,
	2025			2024
ASSETS	(In thousands)
Cash and cash equivalents	$	23,930		$	6,799
Accounts receivable:
Natural gas and oil sales and gas services		203,549			145,398
Joint interest operations		35,400			23,956
From affiliates		3,596			5,492
Derivative financial instruments		19,206			4,865
Other current assets		75,257			97,524
Total current assets		360,938			284,034
Property and equipment:
Natural gas and oil properties, successful efforts method:
Proved		8,984,969			8,054,250
Unproved		391,065			424,648
Other		386,656			150,023
Accumulated depreciation, depletion and amortization		(3,547,196	)		(2,940,532	)
Net property and equipment		6,215,494			5,688,389
Goodwill		335,897			335,897
Operating lease right-of-use assets		94,733			73,777
	$	7,007,062		$	6,382,097
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable	$	501,695		$	421,814
Accrued expenses		153,248			146,173
Operating leases		46,937			35,927
Derivative financial instruments		27,636			8,940
Total current liabilities		729,516			612,854
Long-term debt		2,809,066			2,952,090
Deferred income taxes		437,098			345,116
Derivative financial instruments		—			66,757
Long-term operating leases		47,692			37,740
Reserve for future abandonment costs		20,787			33,996
Total liabilities		4,044,159			4,048,553
Commitments and contingencies
Stockholders' equity:
Common stock—$0.50 par, 400,000,000 shares authorized, 293,054,806 and    292,260,645 shares issued and outstanding at December 31, 2025 and    2024, respectively		146,527			146,130
Additional paid-in capital		1,376,053			1,366,274
Accumulated earnings		1,124,230			728,619
Total stockholders' equity attributable to Comstock		2,646,810			2,241,023
Noncontrolling interest		316,093			92,521
Total stockholders' equity		2,962,903			2,333,544
	$	7,007,062		$	6,382,097

The accompanying notes are an integral part of these statements.

F-3

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2025			2024			2023
	(In thousands, except per share amounts)
Revenues:
Natural gas sales	$	1,425,857		$	1,043,886		$	1,259,450
Oil sales		2,292			3,597			5,161
Total natural gas and oil sales		1,428,149			1,047,483			1,264,611
Gas services		500,202			206,097			300,498
Gain on sale of assets		291,938			875			125
Total revenues and other operating income		2,220,289			1,254,455			1,565,234
Operating expenses:
Production and ad valorem taxes		40,453			57,437			91,803
Gathering and transportation		166,108			194,890			184,906
Lease operating		122,662			130,504			132,203
Depreciation, depletion and amortization		641,163			795,397			607,908
Gas services		516,224			205,407			282,050
General and administrative, net		48,685			39,435			37,992
Impairment of natural gas and oil properties		29,071			—			—
Exploration		10,071			—			1,775
Total operating expenses		1,574,437			1,423,070			1,338,637
Operating income (loss)		645,852			(168,615	)		226,597
Other income (expenses):
Gain from derivative financial instruments		82,537			10,196			187,639
Other income		3,144			1,211			1,771
Interest expense		(222,797	)		(210,621	)		(169,018	)
Total other income (expenses)		(137,116	)		(199,214	)		20,392
Income (loss) before income taxes		508,736			(367,829	)		246,989
(Provision for) benefit from income taxes		(88,533	)		149,075			(35,095	)
Net income (loss)		420,203			(218,754	)		211,894
Net income attributable to noncontrolling interest		(24,592	)		(10,897	)		(777	)
Net income (loss) available to Comstock	$	395,611		$	(229,651	)	$	211,117
Net income (loss) per share — basic	$	1.43		$	(0.76	)	$	0.76
Net income (loss) per share — diluted	$	1.43		$	(0.76	)	$	0.76
Weighted average shares outstanding:
Basic		290,779			287,010			276,806
Diluted		294,131			287,010			276,806
Dividends per share	$	—		$	—		$	0.500

The accompanying notes are an integral part of these statements.

F-4

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

	Common Shares			Common Stock- Par Value			Additional Paid-in Capital			Accumulated Earnings (Deficit)			Noncontrolling Interest			Total
	(In thousands)
Balance at December 31, 2022		277,517		$	138,759		$	1,253,417		$	886,138		$	—		$	2,278,314
Stock-based compensation		1,103			550			9,317			—			—			9,867
Income tax withholdings on equity awards		(190	)		(95	)		(1,804	)		—			—			(1,899	)
Net income		—			—			—			211,117			777			211,894
Payment of common stock dividends		—			—			—			(138,985	)		—			(138,985	)
Contributions from noncontrolling interest		—			—			—			—			24,000			24,000
Balance at December 31, 2023		278,430			139,214			1,260,930			958,270			24,777			2,383,191
Stock-based compensation		1,622			812			14,449			—			—			15,261
Income tax withholdings on equity awards		(291	)		(146	)		(3,227	)		—			—			(3,373	)
Issuance of common stock		12,500			6,250			94,200			—			—			100,450
Stock issuance costs		—			—			(78	)		—			—			(78	)
Net income (loss)		—			—			—			(229,651	)		10,897			(218,754	)
Contributions from noncontrolling interest		—			—			—			—			60,500			60,500
Distributions to noncontrolling interest		—			—			—			—			(3,653	)		(3,653	)
Balance at December 31, 2024		292,261			146,130			1,366,274			728,619			92,521			2,333,544
Stock-based compensation		1,255			628			20,594			—			—			21,222
Income tax withholdings on equity awards		(461	)		(231	)		(10,779	)		—			—			(11,010	)
Stock issuance costs		—			—			(36	)		—			—			(36	)
Net income		—			—			—			395,611			24,592			420,203
Contributions from noncontrolling interest		—			—			—			—			215,500			215,500
Distributions to noncontrolling interest		—			—			—			—			(16,520	)		(16,520	)
Balance at December 31, 2025		293,055		$	146,527		$	1,376,053		$	1,124,230		$	316,093		$	2,962,903

The accompanying notes are an integral part of these statements.

F-5

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	420,203		$	(218,754	)	$	211,894
Adjustments to reconcile net income (loss) to net cash provided by    operating activities:
Deferred income taxes		91,982			(124,919	)		44,301
Impairment of natural gas and oil properties		29,071			—			—
Gain on sale of assets		(291,938	)		(875	)		(125	)
Depreciation, depletion and amortization		641,163			795,397			607,908
Gain on derivative financial instruments		(82,537	)		(10,196	)		(187,639	)
Cash settlements of derivative financial instruments		20,135			207,803			80,328
Amortization of debt discount, premium and issuance costs		11,976			11,476			7,964
Stock-based compensation		21,222			15,261			9,867
(Increase) decrease in accounts receivable		(60,496	)		56,584			278,697
(Increase) decrease in other current assets		17,518			(22,893	)		745
Increase (decrease) in accounts payable and accrued expenses		81,308			(88,547	)		(37,094	)
Net cash provided by operating activities		899,607			620,337			1,016,846
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(1,349,280	)		(1,097,478	)		(1,425,086	)
Prepaid drilling costs		5,002			11,988			(34,010	)
Proceeds from sales of assets		428,868			1,214			41,295
Net cash used for investing activities		(915,410	)		(1,084,276	)		(1,417,801	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on bank credit facility		750,000			645,000			820,000
Repayments on bank credit facility		(905,000	)		(710,000	)		(340,000	)
Issuance of Senior Notes		—			372,000			—
Issuance of common stock		—			100,450			—
Debt and stock issuance costs		(36	)		(6,855	)		(144	)
Income tax withholdings on equity awards		(11,010	)		(3,373	)		(1,899	)
Common stock dividends paid		—			—			(138,985	)
Contributions from noncontrolling interest		215,500			60,500			24,000
Distributions to noncontrolling interest		(16,520	)		(3,653	)		—
Net cash provided by financing activities		32,934			454,069			362,972
Net increase (decrease) in cash and cash equivalents		17,131			(9,870	)		(37,983	)
Cash and cash equivalents, beginning of the year		6,799			16,669			54,652
Cash and cash equivalents, end of the year	$	23,930		$	6,799		$	16,669

The accompanying notes are an integral part of these statements.

F-6

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)Summary of Significant Accounting Policies

Accounting policies used by Comstock Resources, Inc. and subsidiaries reflect natural gas and oil industry practices and conform to accounting principles generally accepted in the United States of America.

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of Comstock Resources, Inc., its wholly owned or controlled subsidiaries and a variable interest entity for which Comstock is the primary beneficiary (collectively, "Comstock" or the "Company"). All significant intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its undivided interest in natural gas and oil properties using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are included in its financial statements. Net income (loss) and comprehensive income (loss) are the same in all periods presented. All adjustments are of a normal recurring nature unless otherwise disclosed. Certain amounts in prior period footnote disclosures have been reclassified to conform with current period presentation.

Comstock entered into an agreement with an affiliate of Quantum Capital Solutions ("Quantum"), in 2023 to form Pinnacle Gas Services, LLC ("PGS"), a midstream company in Comstock's Western Haynesville area. As part of the transaction, Comstock contributed a high-pressure pipeline and a natural gas treating plant. Quantum committed to contribute up to $300 million to fund future expansion costs. Quantum is entitled to a 12% dividend on its invested capital and 80% of any distributions from Pinnacle until an investment return hurdle is met. After the return hurdle is met, Quantum's ownership reduces to 30%. Comstock operates and manages PGS pursuant to a management services agreement. The Board of PGS is comprised of five members: three selected by Comstock and two selected by Quantum. PGS is considered a variable interest entity to Comstock.

Comstock has the power to direct the activities that most significantly impact the performance of PGS and has the obligation to absorb losses or right to receive benefits that could potentially be significant to PGS. Accordingly, Comstock is considered the primary beneficiary and consolidates the assets, liabilities and results of operations of PGS in the accompanying consolidated financial statements. PGS assets that cannot be used by Comstock include $363.9 million of other property and equipment as of December 31, 2025. Other PGS assets that cannot be used by Comstock and PGS liabilities for which creditors do not have recourse to Comstock's assets are not material to the Company's consolidated financial statements. The portion of PGS net income and stockholders' equity not attributable to Comstock's controlling interest are shown separately as noncontrolling interests in the accompanying consolidated statements of operations and statements of stockholders' equity.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from those estimates. Changes in the future estimated natural gas and oil reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analyses could have a significant impact on the future results of operations.

Concentration of Credit Risk, Accounts Receivable and Credit Losses

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative financial instruments. The Company places its cash with high credit quality financial institutions and its derivative financial instruments with financial institutions and other firms that management believes have high credit ratings. Substantially all of the Company's accounts receivable are due from either purchasers of natural gas and oil or participants in natural gas and oil wells for which the Company serves as the operator. Generally, operators of natural gas and oil wells have the right to offset future revenues against unpaid charges related to operated wells. Natural gas and oil sales are generally unsecured. The Company's policy is to assess the collectability of its receivables based upon their age, the credit quality of the purchaser or participant and the potential for revenue offset. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectible. Accordingly, no allowance for doubtful accounts has been recorded for the years ended December 31, 2025, 2024 and 2023, respectively.

F-7

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Current Assets

Other current assets at December 31, 2025 and 2024 consist of the following:

	As of December 31,
	2025		2024
	(In thousands)
Prepaid drilling costs	$	53,134	$	58,136
Other receivables		9,929		4,140
Production tax refunds receivable		5,827		4,074
Income tax receivable		3,024		28,813
Prepaid expenses		2,968		2,361
Other		375		—
	$	75,257	$	97,524

Fair Value Measurements

The Company holds or has held certain financial assets and liabilities that are required to be measured at fair value in the financial statements. These include cash and cash equivalents held in bank accounts and derivative financial instruments. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. A three-level hierarchy is followed for disclosure to show the extent and level of judgment used to estimate fair value measurements:

Level 1 — Inputs used to measure fair value are unadjusted quoted prices that are available in active markets for the identical assets or liabilities as of the reporting date.

Level 2 — Inputs used to measure fair value, other than quoted prices included in Level 1, are either directly or indirectly observable as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.

Level 3 — Inputs used to measure fair value are unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management's estimates of market participant assumptions.

The following presents the carrying amounts and the fair values of the Company's financial instruments as of December 31, 2025 and 2024:

	As of December 31,
	2025				2024
	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets:	(In thousands)
Commodity-based derivatives (1)	$	19,206	$	19,206	$	4,865	$	4,865
Liabilities:
Commodity-based derivatives (1)		27,636		27,636		75,697		75,697
Bank credit facility (2)		260,000		260,000		415,000		415,000
6.75% senior notes due 2029 (3)		1,607,880		1,603,582		1,603,679		1,581,283
5.875% senior notes due 2030 (3)		965,000		931,225		965,000		899,863

(1)The Company's commodity-based derivatives are classified as Level 2 and measured at fair value using a market approach using third party pricing services and other active markets or broker quotes that are readily available in the public markets.

(2)The carrying value of our floating rate debt outstanding approximates fair value.

(3)The fair value of the Company's fixed rate debt was based on quoted prices as of December 31, 2025 and 2024, respectively, a Level 1 measurement.

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COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Property and Equipment

The Company follows the successful efforts method of accounting for its natural gas and oil properties. Costs incurred to acquire natural gas and oil leasehold are capitalized. Acquisition costs for proved natural gas and oil properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related natural gas and oil reserves. Equivalent units are determined by converting oil to natural gas at the ratio of one barrel of oil for six thousand cubic feet of natural gas. This conversion ratio is not based on the price of oil or natural gas, and there may be a significant difference in price between an equivalent volume of oil versus natural gas.

Exploratory well costs are initially capitalized as proved property in the consolidated balance sheets but charged to exploration expense if and when the well is determined not to have found commercial proved natural gas and oil reserves. The changes in capitalized exploratory well costs are as follows:

	Year Ended December 31,
	2025			2024
	(in thousands)
Beginning capitalized exploratory project costs	$	68,223		$	96,233
Additions to exploratory well costs pending the determination of proved reserves		490,429			354,557
Determined to have found proved reserves		(348,525	)		(382,567	)
Ending capitalized exploratory well costs	$	210,127		$	68,223

As of December 31, 2025 and 2024, the Company had no exploratory wells for which costs have been capitalized greater than one year.

The estimated future costs of dismantlement, restoration, plugging and abandonment of natural gas and oil properties and related facilities disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense. Exploration expense includes geological and geophysical expenses and delay rentals related to exploratory natural gas and oil properties, costs of unsuccessful exploratory drilling and impairments of unproved properties. As of December 31, 2025 and 2024, the unproved properties primarily relate to future drilling locations that were not included in proved undeveloped reserves. Most of these future drilling locations are located on acreage where the reservoir is known to be productive but have been excluded from proved reserves due to uncertainty on whether the wells would be drilled within the next five years as required by SEC rules in order to be included in proved reserves. The costs of unproved properties are transferred to proved natural gas and oil properties when they are either drilled or they are reflected in proved undeveloped reserves and amortized on an equivalent unit-of-production basis. Costs associated with unevaluated exploratory acreage are periodically assessed for impairment on a property by property basis, and any impairment in value is included in exploration expense. Exploratory drilling costs are initially capitalized as proved property but charged to expense if and when the well is determined not to have found commercial proved natural gas and oil reserves. Exploratory drilling costs are evaluated within a one-year period after the completion of drilling.

The Company assesses the need for an impairment of the costs capitalized for its proved natural gas and oil properties when events or changes in circumstances, such as a significant drop in commodity prices, indicate that the Company may not be able to recover its capitalized costs. If impairment is indicated based on undiscounted expected future cash flows attributable to the property, then a provision for impairment is recognized to the extent that net capitalized costs exceed the estimated fair value of the property. The Company determines the fair values of its natural gas and oil properties using a discounted cash flow model and proved and risk-adjusted probable reserves. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included in the cash flow model include management's outlook for natural gas and oil prices, future natural gas and oil production, production costs, capital expenditures, and the total proved and risk-adjusted probable natural gas and oil reserves expected to be recovered. Management's natural gas and oil price outlook is developed based on multiple third-party longer-term price forecasts as of each measurement date. The expected future net cash flows are discounted using an appropriate discount rate in determining a property's fair value. The natural gas and oil prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of an average price based on the first day of each month of the preceding year. Unproved properties are evaluated for impairment based upon the results of drilling, planned future drilling and the terms of the natural gas and oil leases. In the fourth quarter of 2025, the Company measured the fair value of its Eagle Ford shale proved property using Level 3 unobservable inputs at $1.2 million and as a result, the Company recognized an impairment charge of $7.8 million. Comstock also recognized an impairment charge to its Eagle Ford shale unproved property of $21.3 million. This

F-9

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

charge primarily resulted from diminished activity in the area on its leasehold acreage by operators, low oil prices and the Company's capital allocation strategy, which prioritizes higher-return projects in the Haynesville and Bossier shales.

The Company's estimates of undiscounted future net cash flows attributable to its natural gas and oil properties may change in the future. The primary factors that may affect estimates of future cash flows include future adjustments, both positive and negative, to proved and appropriate risk-adjusted probable natural gas and oil reserves, results of future drilling activities, future prices for natural gas and oil, and increases or decreases in production and capital costs. As a result of these changes, there may be future impairments in the carrying values of our natural gas and oil properties.

Other property and equipment consists primarily of pipelines and natural gas treating plants ("midstream assets"), computer equipment, furniture and fixtures, office buildings and an airplane which are depreciated over estimated useful lives ranging from three to 50 years on a straight-line basis. The following table presents the balances of other property and equipment and accumulated depreciation as of December 31, 2025 and 2024:

	As of December 31,
	2025			2024
	(in thousands)
Midstream assets	$	363,855		$	140,263
Accumulated depreciation		(4,914	)		(1,976	)
Net midstream assets		358,941			138,287
Other property and equipment		22,801			9,760
Accumulated depreciation		(1,982	)		(3,063	)
Net other property and equipment		20,819			6,697
Total	$	379,760		$	144,984

The Company also assesses the need for an impairment of its midstream assets when events or changes in circumstances, such as a significant decline in natural gas volumes gathered and processed, indicate that the Company may not be able to recover its capitalized costs. If impairment is indicated based on undiscounted expected future cash flows attributable to the pipelines and natural gas treating plants, then impairment is recognized to the extent the capitalized costs of the pipelines and natural gas treating plants exceed their estimated fair value. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included in the cash flow model include management's outlook for future natural gas gathering and processing volumes, operation costs and capital expenditures and the expected future net cash flows are discounted at an appropriate rate to determine fair value.

Goodwill

The Company had goodwill of $335.9 million as of December 31, 2025 and 2024. Goodwill represents the excess of purchase price over fair value of net tangible and identifiable intangible assets in a business combination.

The Company is required to conduct an annual review of goodwill for impairment and performs the assessment of goodwill on October 1st of each year. If the carrying value of goodwill exceeds the fair value, an impairment charge would be recorded for the difference between fair value and carrying value. The Company performed its assessment of goodwill as of October 1, 2025 and determined there was no indication of impairment.

Leases

The Company had right-of-use lease assets of $94.7 million and $73.8 million as of December 31, 2025 and 2024, respectively, related to its corporate office lease, certain office equipment, vehicles and drilling rigs with corresponding short-term and long-term liabilities. The value of the lease assets and liabilities are determined based upon discounted future minimum cash flows contained within each of the respective contracts, including the effects of early termination provisions. The Company determines if contracts contain a lease at inception of the contract. Since most of the Company's lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate at the commencement date of the lease. To the extent that contract terms representing a lease are identified, leases are identified as being either an operating lease or a finance-type lease. Comstock currently has no finance-type leases. Right-of-use lease assets represent the Company's right to use an underlying asset for the lease term and the related lease liabilities represent its obligation to make lease payments under the terms of the contracts. Short-term leases that have an initial term of one year or less are not capitalized; however,

F-10

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

amounts paid for those leases are included as part of its lease cost disclosures. Short-term lease costs exclude expenses related to leases with a lease term of one month or less.

Comstock contracts for a variety of equipment used in its natural gas and oil exploration and development operations. Contract terms for this equipment vary broadly, including the contract duration, pricing, scope of services included along with the equipment, cancellation terms, and rights of substitution, among others. The Company's drilling and completion operations routinely change due to changes in commodity prices, demand for natural gas and oil, and the overall operating and economic environment. Accordingly, Comstock manages the terms of its contracts for drilling rigs and completion equipment so as to allow for maximum flexibility in responding to these changing conditions. The Company's hydraulic fracturing fleet contracts are on terms of less than one year and include rights of substitution. As of December 31, 2025, the Company had four drilling rig lease contracts with a three-year term with options to extend the term by mutual agreement at mutually acceptable terms or terminate the contracts at any time without default by the lessor. The Company's other drilling rig contracts are presently either for periods of one year or less, or they are on terms that provide for cancellation with 30 or 45 days advance notice without a specified expiration date. The costs associated with drilling and completion operations are accounted for under the successful efforts method, which generally require that these costs be capitalized as part of our proved natural gas and oil properties on our balance sheet unless they are incurred on exploration wells that are unsuccessful, in which case they are charged to exploration expense. For drilling rig leases, the Company has elected the practical expedient to not separate lease components from non-lease components in the determination of their lease asset and liability values.

Lease costs recognized during the years ended December 31, 2025, 2024 and 2023 were as follows:

	Year Ended December 31,
	2025		2024		2023
	(In thousands)
Operating lease cost included in general and administrative expense	$	1,700	$	1,686	$	1,768
Operating lease cost included in lease operating expense		2,326		2,208		2,060
Operating lease cost included in proved natural gas and oil properties		48,321		34,644		56,755
Variable lease cost (drilling and completion costs included in proved natural gas and oil properties)		8,221		2,555		28,406
Short-term lease cost (drilling costs included in proved natural gas and oil properties)		31,160		26,276		89,163
	$	91,728	$	67,369	$	178,152

Cash payments for operating leases associated with right-of-use assets included in cash provided by operating activities were $4.0 million, $3.9 million and $3.8 million for the years ended December 31, 2025, 2024 and 2023, respectively. Cash payments for operating leases associated with right-of-use assets included in cash used for investing activities were $87.7 million, $63.5 million and $174.3 million for the years ended December 31, 2025, 2024 and 2023, respectively.

As of December 31, 2025 and 2024, the operating leases had a weighted average remaining term of 2.4 years and 2.0 years, respectively, and the weighted-average discount rate used to determine the present value of future operating lease payments was 6.8% and 7.3%, respectively.

As of December 31, 2025, expected future payments related to contracts that contain operating leases were as follows:

	(In thousands)
2026	$	51,848
2027		29,113
2028		14,470
2029		7,430
Total lease payments		102,861
Imputed interest		(8,232	)
Total lease liability	$	94,629

Accrued Expenses

Accrued expenses at December 31, 2025 and 2024 consist of the following:

F-11

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	As of December 31,
	2025		2024
	(In thousands)
Accrued interest payable	$	64,042	$	64,041
Accrued drilling costs		36,148		34,493
Accrued transportation costs		28,304		28,031
Accrued employee compensation		14,926		14,076
Accrued income and other taxes		4,000		1,350
Accrued lease operating expenses		3,744		2,630
Other		2,084		1,552
	$	153,248	$	146,173

Reserve for Future Abandonment Costs

The Company's asset retirement obligations relate to future plugging and abandonment costs of its natural gas and oil properties and related facilities disposal. The Company records a liability in the period in which an asset retirement obligation is incurred, in an amount equal to the estimated fair value of the obligation that is capitalized. Thereafter, this liability is accreted up to the final retirement cost. Accretion of the discount is included as part of depreciation, depletion and amortization in the accompanying consolidated statements of operations.

The following table summarizes the changes in the Company's total estimated liability:

	Year Ended December 31,
	2025			2024
	(In thousands)
Reserve for future abandonment costs at beginning of the year	$	33,996		$	30,773
New wells placed on production		193			136
Changes in estimates and timing		484			1,497
Liabilities settled		(155	)		(40	)
Divestitures		(15,471	)		(157	)
Accretion expense		1,740			1,787
Reserve for future abandonment costs at end of the year	$	20,787		$	33,996

Stock-based Compensation

The Company has stock-based employee compensation plans under which stock awards, comprised primarily of restricted stock and performance share units ("PSUs"), are issued to employees and non-employee directors. The Company follows the fair value-based method in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period. Forfeitures are recognized as they occur.

Segment Reporting

The Company presently operates in one business segment, the exploration and production of North American natural gas and oil, primarily in the Haynesville and Bossier shale. This is consistent with the internal reporting provided to the Company's Chief Executive Officer, who is the chief operating decision maker ("CODM"). The CODM evaluates the performance of the Company and allocates resources based on consolidated financial information.

The measure of segment profit or loss used by the CODM is consolidated net income, which is provided in the accompanying consolidated statements of operations. The significant segment expenses regularly provided to the CODM are operating expenses and certain significant non-operating items, such as gains or losses from derivative financial instruments, interest expense and income tax expense. These items are also detailed in the accompanying consolidated statements of operations.

Derivative Financial Instruments and Hedging Activities

F-12

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company accounts for derivative financial instruments (including derivative instruments embedded in other contracts) as either an asset or liability measured at its fair value. Changes in the fair value of derivatives are recognized currently in earnings and in net cash flows from operating activities. The fair value of derivative contracts that expire in less than one year are recognized as current assets or liabilities. Those that expire in more than one year are recognized as long-term assets or liabilities.

Major Purchasers

In 2025, the Company had three major purchasers of its natural gas production that accounted for 18%, 11% and 10% of its total natural gas and oil sales. In 2024, the Company had two major purchasers of its natural gas production that accounted for 21% and 12% of its total natural gas and oil sales. In 2023, the Company had three major purchasers of its natural gas production that accounted for 20%, 17% and 10% of its total natural gas and oil sales. The loss of any of these purchasers would not have a material adverse effect on the Company as there is an available market for its natural gas and oil production from other purchasers.

Revenue Recognition and Gas Balancing

Comstock produces natural gas and oil and reports revenues separately for each of these two primary products in its statements of operations. Revenues are recognized upon the transfer of produced volumes to the Company's customers, who take control of the volumes and receive all the benefits of ownership upon delivery at designated sales points. Costs incurred to gather or transport each product prior to the transfer of control are recognized as operating expenses.

Gas services revenues represent sales of natural gas purchased for resale from unaffiliated third parties and fees received for gathering and treating services provided by PGS to third parties. Revenues are recognized upon completion of the gathering and treating of contracted natural gas volumes and delivery of purchased natural gas volumes to the Company's customers. Profits and losses earned in the gathering and treating of natural gas produced by the Company's natural gas wells are eliminated in consolidation. Revenues and expenses associated with natural gas purchased for resale are presented on a gross basis in the Company's consolidated statements of operations as the Company acts as the principal in the transaction by assuming the risks and rewards from ownership of the natural gas volumes purchased and the responsibility to deliver the natural gas volumes to their sales point.

All natural gas and oil and gas services revenues are subject to contracts that have commercial substance, contain specific pricing terms, and define the enforceable rights and obligations of both parties. These contracts typically provide for cash settlement within 25 days following each production month and are cancellable upon 30 days' notice by either party for oil and vary for natural gas based upon the terms set out in the confirmations between both parties. Prices for sales of natural gas and oil are generally based upon terms that are common in the natural gas and oil industry, including index or spot prices, location and quality differentials, as well as market supply and demand conditions. As a result, prices for natural gas and oil routinely fluctuate based on changes in these factors. Prices for gathering and treating services are generally fixed in nature but can vary due to the quality of the gas being treated. Each unit of production (thousand cubic feet of natural gas and barrel of crude oil ) represents a separate performance obligation under the Company's contracts since each unit has economic benefit on its own and each is priced separately according to the terms of the contracts.

Comstock has elected to exclude all taxes from the measurement of transaction prices, and its natural gas and oil revenues are reported net of royalties and exclude revenue interests owned by others because the Company acts as an agent when selling natural gas and oil, on behalf of royalty owners and working interest owners. Natural gas and oil sales revenue is recorded in the month of production based on an estimate of the Company's share of volumes produced and prices realized. Gas services revenue is recorded in the month the services are performed and purchased gas is sold based on an estimate of natural gas volumes and contract prices. The Company recognizes any differences between estimates and actual amounts received in the month when payment is received. Historically, differences between estimated revenues and actual revenues received have not been significant. The amount of natural gas or oil sold may differ from the amount to which the Company is entitled based on its revenue interests in the properties. The Company did not have any significant imbalance positions at December 31, 2025 or 2024.

The Company has recognized accounts receivable of $203.5 million and $145.4 million as of December 31, 2025 and 2024, respectively, from customers for contracts where performance obligations have been satisfied and an unconditional right to consideration exists.

F-13

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

General and Administrative Expenses

General and administrative expenses are reported net of reimbursements of overhead costs that are received from working interest owners of the natural gas and oil properties operated by the Company of $30.5 million, $30.7 million and $29.7 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Income Taxes

The Company accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the tax consequences attributable to the future utilization of existing net operating loss and other carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that the change in rate is enacted.

Earnings Per Share

Unvested restricted stock containing non-forfeitable rights to dividends are included in common stock outstanding and are considered to be participating securities and included in the computation of basic and diluted earnings per share pursuant to the two-class method. At December 31, 2025 and 2024, 1,957,381 and 2,091,087 shares of restricted stock, respectively, are included in common stock outstanding as such shares have a non-forfeitable right to participate in any dividends that might be declared and have the right to vote on matters submitted to the Company's shareholders.

Weighted average shares of unvested restricted stock outstanding were as follows:

	Year Ended December 31,
	2025		2024		2023
	(in thousands)
Unvested restricted stock		2,145		2,187		1,248

PSUs represent the right to receive a number of shares of the Company's common stock that may range from zero to up to two times the number of PSUs granted on the award date based on the achievement of certain performance measures during a performance period. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective period, assuming that date was the end of the performance period. The treasury stock method is used to measure the dilutive effect of PSUs.

	Year Ended December 31,
	2025		2024		2023
	(In thousands, except per unit amounts)
Weighted average PSUs		1,479		1,272		662
Weighted average grant date fair value per unit	$	19.46	$	13.21	$	15.92

None of the Company's participating securities participate in losses and as such are excluded from the computation of basic earnings per share during periods of net losses. For the year ended December 31, 2023, the weighted average shares of unvested restricted stock and PSUs were excluded from the computation of earnings per share because to include them would have been antidilutive to the calculation.

F-14

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Basic and diluted income (loss) per share were determined as follows:

	Year Ended December 31,
	2025			2024			2023
	(In thousands, except per share amounts)
Net income (loss)	$	420,203		$	(218,754	)	$	211,894
Income allocable to unvested restricted stock		(3,077	)		—			(327	)
Basic net income (loss)	$	417,126		$	(218,754	)	$	211,567
Income allocable to unvested restricted stock		3,077			—			—
Diluted net income (loss)	$	420,203		$	(218,754	)	$	211,567
Basic weighted average shares outstanding		290,779			287,010			276,806
Effect of dilutive securities:
PSUs		2,170			—			—
Restricted stock		1,182			—			—
Diluted weighted average shares outstanding		294,131			287,010			276,806
Basic income (loss) per share	$	1.43		$	(0.76	)	$	0.76
Diluted income (loss) per share	$	1.43		$	(0.76	)	$	0.76

Supplementary Information with Respect to the Consolidated Statements of Cash Flows

For the purpose of the consolidated statements of cash flows, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Cash payments made for interest and income taxes and other non-cash investing and financing activities were as follows:

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
Cash payments for:
Interest	$	210,820		$	190,016		$	161,009
Income tax payments (refunds):
Federal	$	(31,000	)	$	—		$	24,700
State (1)	$	—		$	37		$	5,083
Non-cash investing activities include:
Increase (decrease) in accrued capital expenditures	$	1,655		$	(1,383	)	$	(18,562	)
Liabilities assumed in exchange for right-of-use lease assets	$	67,179		$	34,668		$	195,402

(1)State tax payments were made in Texas and Louisiana.

Recent Accounting Pronouncements

In December 2023, the FASB issued ASU 2023-09 "Improvements to Income Tax Disclosures". ASU 2023-09 requires additional disclosures around effective tax rates and cash income taxes paid and is effective for public entities for annual periods beginning after December 15, 2024. ASU 2023-09 was implemented retrospectively in this 2025 Annual Report. See (9) Income Taxes for the impact on the Company's disclosures.

In November 2024, the FASB issued ASU 2024-03 "Disaggregation of Income Statement Expenses". ASU 2024-03 requires additional disclosure, in the notes to the financial statements, of specified information about certain costs and expenses, including purchases of inventory, employee compensation, depreciation, intangible asset amortization and depreciation, depletion and amortization recognized as part of oil and gas-producing activities included in each relevant expense caption. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027 and will not have an impact on the Company's reported results of operations, financial position or liquidity but will have an impact on the Company's financial statement disclosures. The Company is still evaluating the impact of this standard on its financial statement disclosures.

F-15

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(2)Acquisitions and Dispositions of Natural Gas and Oil Properties

Acquisitions

During 2025, 2024 and 2023, the Company spent $54.7 million, $106.4 million and $98.6 million on its leasing program to acquire 17,856, 265,290 and 79,741 net acres, respectively, of undeveloped acreage in the Western Haynesville area through direct leasing or through acquisitions of undeveloped rights from third-party operators.

Dispositions

On December 2, 2025, the Company sold its interest in its Shelby Trough assets in East Texas for net proceeds of $417.2 million. The assets sold included 163 (74.8 net) producing wells and 36,000 net leasehold acres in Nacogdoches, San Augustine and Sabine counties in Texas. The Company realized a $292.3 million pre-tax gain on the sale of the unproved property. The producing wells and associated proved undeveloped reserves were valued at $120.5 million and recorded as a retirement of the Company's proved property. The Company's reserve for future abandonment costs was reduced by $1.7 million as a result of the divestiture.

On September 2, 2025, the Company sold its interest in its Cotton Valley assets in East Texas and North Louisiana for net proceeds of $15.2 million. The assets sold included the Company's interest in 883 (770.9 net) producing wells and 46 (27.3 net) inactive wells. The Company incurred a $1.5 million pre-tax loss on the divestiture and the Company's reserve for future abandonment costs was reduced by $13.8 million.

The Company sold its interests in certain non-operated natural gas and oil properties for $1.2 million and $41.3 million in 2024 and 2023, respectively.

(3)Natural Gas and Oil Producing Activities

Set forth below is certain information regarding the aggregate capitalized costs of natural gas and oil properties and costs incurred by the Company for its natural gas and oil property acquisition, development and exploration activities:

Capitalized Costs

	As of December 31,
	2025			2024
	(In thousands)
Proved properties:
Leasehold costs	$	3,194,699		$	3,244,996
Wells and related equipment and facilities		5,790,270			4,809,254
Accumulated depreciation depletion and amortization		(3,540,300	)		(2,935,493	)
		5,444,669			5,118,757
Unproved properties		391,065			424,648
	$	5,835,734		$	5,543,405

Costs Incurred

	Year Ended December 31,
	2025		2024		2023
	(In thousands)
Property acquisitions:
Unproved property	$	54,670	$	106,386	$	98,553
Exploration and development:
Developmental leasehold costs		14,562		13,461		27,905
Exploratory drilling and completion costs		490,429		354,557		244,129
Development drilling and completion costs		517,375		503,550		974,664
Other development costs		32,493		30,500		25,130
Asset retirement obligations		444		1,594		(19	)
Total capital expenditures	$	1,109,973	$	1,010,048	$	1,370,362

F-16

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(4)Long-term Debt

Long-term debt is comprised of the following:

	As of December 31,
	2025			2024
	(In thousands)
Bank Credit Facility	$	260,000		$	415,000
6.75% Senior Notes due 2029:
Principal		1,623,880			1,623,880
Discount, net of amortization		(16,000	)		(20,201	)
5.875% Senior Notes due 2030:
Principal		965,000			965,000
Debt issuance costs, net of amortization		(23,814	)		(31,589	)
	$	2,809,066		$	2,952,090

The discount and premium on the 6.75% senior notes due 2029 are being amortized over its life using the effective interest rate method. Debt issuance costs are amortized over the lives of the bank credit facility and senior notes on a straight-line basis which approximates the amortization that would be calculated using an effective interest rate method.

The following table summarizes Comstock's principal amount of debt as of December 31, 2025 by year of maturity:

	2026		2027		2028		2029		2030		Total
	(In thousands)
Bank Credit Facility	$	—	$	260,000	$	—	$	—	$	—	$	260,000
6.75% Senior Notes due 2029		—		—		—		1,623,880		—		1,623,880
5.875% Senior Notes due 2030		—		—		—		—		965,000		965,000
	$	—	$	260,000	$	—	$	1,623,880	$	965,000	$	2,848,880

As of December 31, 2025, the Company had $260.0 million outstanding under a bank credit facility. Aggregate commitments under the bank credit facility are $1.5 billion, which matures on November 15, 2027. Borrowings under the bank credit facility are subject to a borrowing base, which is currently set at $2.0 billion. The borrowing base is re-determined on a semi-annual basis and upon the occurrence of certain other events. Borrowings under the bank credit facility are secured by substantially all of the assets of the Company and its restricted subsidiaries and bear interest at the Company's option, at either adjusted SOFR plus 2.25% to 3.25% or an alternate base rate plus 1.25% to 2.25%, in each case depending on the unused portion of the committed borrowing base. The Company also pays a commitment fee of 0.375% to 0.5%, which is dependent on the utilization of the borrowing base. The weighted average interest rate on borrowings under the bank credit facility were 6.76% and 7.32% during the years ended December 31, 2025 and 2024, respectively. The bank credit facility places certain restrictions upon the Company's and its restricted subsidiaries' ability to, among other things, incur additional indebtedness, pay cash dividends, repurchase common stock, make certain loans, investments and divestitures and redeem the senior notes. The only financial covenants are the maintenance of a leverage ratio of less than 3.5 to 1.0 and an adjusted current ratio of at least 1.0 to 1.0. The Company was in compliance with the covenants as of December 31, 2025.

In April 2024, the Company issued $400.0 million principal amount of 6.75% senior notes due 2029 (the "New 2029 Notes") in a private placement and received net proceeds after offering costs and deducting the initial purchasers' discounts of $365.2 million, which were used to pay down the outstanding borrowings on the Company's bank credit facility. The New 2029 Notes have substantially identical terms as the Company's $1,223.9 million aggregate principal amount of 6.75% senior notes due 2029, which mature on March 1, 2029 and accrue interest at a rate of 6.75% per annum, payable semi-annually on March 1 and September 1 of each year.

F-17

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(5)Commitments and Contingencies

The Company has drilling rig contracts with terms ranging from less than one year to three years. The service contracts with terms less than one year are generally for terms ranging from 30 to 45 days. The Company has four drilling rigs under contract with initial terms of three years that were put into service in 2023, 2024 and 2025. These four rigs qualify as operating leases and their corresponding lease obligation is reflected on the Company's balance sheet as of December 31, 2025. In 2025, the Company took delivery of one additional drilling rig with a one-year term, which has a remaining commitment of $3.2 million.

The Company has natural gas transportation and gathering contracts which extend to 2035. Commitments under these contracts are $85.4 million for 2026, $84.2 million for 2027, $79.3 million for 2028, $67.6 million for 2029, $27.7 million for 2030 and $58.9 million for 2031 through 2035. During the years ended December 31, 2025, 2024 and 2023, expenditures under these contracts totaled $86.3 million, $92.8 million and $96.5 million, respectively.

From time to time, the Company is involved in certain litigation that arise in the normal course of its operations. The Company records a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. The Company does not believe the resolution of these matters will have a material adverse effect on the Company's financial position, results of operations or cash flows and no material amounts are accrued relative to these matters at December 31, 2025 or 2024.

(6)Stockholders' Equity

The authorized capital of the Company is 405,000,000 shares, of which 400,000,000 shares are common stock, $0.50 par value per share, and 5,000,000 are preferred stock, $10.00 par value per share.

In March 2024, the Company issued 12,500,000 shares of common stock in a private placement to two entities controlled by Comstock's majority stockholder, receiving proceeds of $100.5 million. Following the issuance, Comstock's majority stockholder's beneficial ownership in the Company increased to 67%. As a result of open market purchases made by the Company's majority stockholder during the third quarter of 2024, beneficial ownership increased to 71%.

(7)Stock-based Compensation

The Company grants restricted shares of common stock and PSUs to key employees and directors as part of their compensation. Grants are made pursuant to the Company's 2019 Long-term Incentive Plan (the "2019 Plan"), which was approved by the Company's shareholders on May 31, 2019. Future authorized equity awards available under the 2019 Plan as of December 31, 2025 were 9,451,616 shares of common stock.

Stock-based compensation expense is included in general and administrative expenses. During the years ended December 31, 2025, 2024 and 2023 the Company had $21.2 million, $15.3 million and $9.9 million, respectively, in stock-based compensation expense.

Restricted Stock

The fair value of restricted stock grants is amortized over the vesting period, generally one year to three years, using the straight-line method. The fair value of each restricted share on the date of grant is equal to the market price of a share of the Company's stock.

A summary of restricted stock activity is presented below:

	Number of Restricted Shares			Weighted Average Grant Price
Outstanding at January 1, 2025		2,091,087		$	9.25
Granted		840,783		$	18.18
Vested		(962,854	)	$	10.53
Forfeitures		(11,635	)	$	12.25
Outstanding at December 31, 2025		1,957,381		$	12.44

F-18

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Year Ended December 31,
	2025		2024		2023
	(In thousands, except per share data)
Fair value of vested restricted stock	$	22,126	$	7,536	$	4,241
Grant date weighted average fair value	$	18.18	$	7.78	$	9.80
Compensation expense recognized for restricted stock grants	$	12,507	$	9,884	$	6,519
Unrecognized compensation expense related to unvested shares	$	15,389
Expected recognition period	1.7 years

Performance Share Units

The Company issues PSUs as part of its long-term equity incentive compensation. PSU awards can result in the issuance of common stock to the holder if certain performance criteria are met during a performance period. The performance periods consist of three years. The performance criteria for the PSUs are based on the Company's annualized total stockholder return ("TSR") for the performance period as compared with the TSR of certain peer companies for the performance period. The costs associated with PSUs are recognized as general and administrative expense over the performance periods of the awards.

The fair value of PSUs was measured at the grant date using the Geometric Brownian Motion Model. Significant assumptions used in this simulation include the Company's expected volatility and a risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the vesting periods, as well as the volatilities for each of the Company's peers. Assumptions regarding volatility included the historical volatility of each company's stock and the implied volatilities of publicly traded stock options.

Significant assumptions used to value PSUs included:

	Year Ended December 31,
	2025			2024			2023
Risk free interest rate		3.9	%		4.4	%		4.2	%
Range of implied volatility:
Minimum		29	%		33	%		38	%
Maximum		55	%		58	%		68	%

A summary of PSU activity is presented below:

	Number of PSUs			Weighted Average Grant Price
Outstanding at January 1, 2025		1,290,755		$	13.21
Granted		529,670		$	36.77
Earned		(216,509	)	$	24.50
Outstanding at December 31, 2025		1,603,916		$	19.46

	Year Ended December 31,
	2025		2024		2023
	(In thousands, except per unit data)
Number of PSUs granted		530		706		391
Grant date fair value	$	19,476	$	6,837	$	4,906
Grant date fair value per unit	$	36.77	$	9.69	$	13.64
Compensation expense recognized for PSUs	$	8,716	$	5,375	$	3,348
Unrecognized compensation expense related to unvested shares	$	19,105
Expected recognition period	2.0 years

The fair value of PSUs is amortized over the vesting period of three years, using the straight-line method. The final number of shares of common stock issued may vary depending upon the performance multiplier and can result in the issuance of zero to 3,207,832 shares of common stock based on the achieved performance ranges from zero to two hundred percent.

F-19

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(8)Retirement Plan

The Company has a 401(k) profit sharing plan which covers all of its employees. At its discretion, Comstock may match the employees' contributions to the plan. Matching contributions to the plan were approximately $2.2 million, $2.1 million and $1.9 million for the years ended December 31, 2025, 2024 and 2023, respectively.

(9)Income Taxes

Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates.

The following is an analysis of the consolidated income tax provision (benefit):

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
Current - Federal	$	(3,449	)	$	(24,200	)	$	(4,570	)
Current - State		—			44			(4,636	)
Deferred - Federal		94,461			(88,001	)		52,520
Deferred - State		(2,479	)		(36,918	)		(8,219	)
	$	88,533		$	(149,075	)	$	35,095

In recording deferred income tax assets, the Company considers whether it is more likely than not that its deferred income tax assets will be realized in the future. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that all of its deferred tax assets will be realized. As a result, the Company established valuation allowances for its deferred tax assets and U.S. federal and state net operating loss carryforwards that are not expected to be utilized due to the uncertainty of generating taxable income prior to the expiration of the carryforward periods. The Company will continue to assess the valuation allowances against deferred tax assets considering all available information obtained in future periods.

The tax effects of significant temporary differences representing the net deferred tax liabilities were as follows:

	As of December 31,
	2025			2024
	(In thousands)
Deferred tax assets:
Interest expense limitation	$	209,968		$	207,053
Net operating loss carryforwards		212,344			79,628
Research and development and other tax credits		28,688			17,411
Asset retirement obligation		7,654			6,991
Unrealized hedging losses		1,956			16,701
Other		7,209			4,731
		467,819			332,515
Valuation allowance on deferred tax assets		(52,693	)		(53,687	)
Deferred tax assets		415,126			278,828
Deferred tax liabilities:
Property and equipment		(850,365	)		(621,561	)
Other		(1,859	)		(2,383	)
Deferred tax liabilities		(852,224	)		(623,944	)
Net deferred tax liability	$	(437,098	)	$	(345,116	)

F-20

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The difference between the customary rate of 21.0% and the effective tax rate on income (losses) is due to the following:

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
Tax at statutory rate	$	106,834		$	(77,244	)	$	51,868
Tax effect of:
Tax credits:
Research and development		(10,334	)		(32,414	)		—
Other income tax credits		(3,024	)		(1,586	)		—
Valuation allowance on deferred tax assets		—			(779	)		(968	)
State income taxes, net of federal benefit (1)		(2,479	)		(36,884	)		(11,881	)
Other		(2,464	)		(168	)		(3,924	)
Total	$	88,533		$	(149,075	)	$	35,095

	Year Ended December 31,
	2025			2024			2023
Tax at statutory rate		21.0	%		21.0	%		21.0	%
Tax effect of:
Tax credits:
Research and development		(2.0	)		8.8			—
Other income tax credits		(0.6	)		0.4			—
Valuation allowance on deferred tax assets		—			0.2			(0.4	)
State income taxes, net of federal benefit (1)		(0.5	)		10.0			(4.8	)
Other		(0.5	)		0.1			(1.6	)
Effective tax rate		17.4	%		40.5	%		14.2	%

(1)State taxes in Texas and Louisiana contributed to the tax effect of this category.

At December 31, 2025, Comstock had the following carryforwards available to reduce future income taxes:

Types of Carryforward	Years of Expiration Carryforward	Amount
		(In thousands)
Net operating loss – U.S. federal	2026-2037	$	740,631
Net operating loss – U.S. federal	Unlimited	$	634,990
Net operating loss – State	Unlimited	$	1,807,981
Interest expense – U.S. federal	Unlimited	$	818,854
Interest expense – State	Unlimited	$	874,763
Research and development tax credits – U.S. federal	2045-2046	$	17,653
Research and development tax credits – State	2043-2046	$	11,035

The Company's ability to use net operating losses ("NOLs") generated before its ownership change in 2018 to reduce taxable income is limited under IRC Section 382. NOLs that exceed the Section 382 limitation in any year continue to be allowed as carry forwards until they expire and can be used to offset taxable income for years within the carryover period subject to the limitation in each year. U.S. federal NOLs incurred prior to 2018 generally have a 20-year life until they expire. NOLs generated in 2018 and after would be carried forward indefinitely. NOLs arising after the date of an ownership change are not affected by the 382 limitation. If the Company does not generate a sufficient level of taxable income prior to the expiration of the pre-2018 NOL carry-forward periods, then it will lose the ability to apply those NOLs as offsets to future taxable income. The Company estimates that all of the U.S. federal NOL carryforwards expiring in 2037 and $1.2 billion of the estimated state NOL carryforwards will expire unused.

F-21

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Company's federal income tax returns for the years subsequent to December 31, 2021 remain subject to examination, with the Company's 2022 and 2023 federal income tax returns currently under examination with the United States Internal Revenue Service. The Company's income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2022. The Company is also currently under examination with the state of Louisiana. In both the federal and state examinations, the Company believes that its significant filing positions will be sustained under audit or the final resolution will not have a material effect on the consolidated financial statements. Therefore, the Company has not established any significant reserves for uncertain tax positions.

In July 2025, the One Big Beautiful Bill Act ("OBBBA") was signed into United States federal law. The Company is benefiting from certain provisions contained in the OBBBA, including increased interest expense deductions and bonus depreciation and has included these benefits in its income tax provision for the year ended December 31, 2025.

(10)Derivative Financial Instruments and Hedging Activities

Comstock generally uses commodity price swaps, basis swaps and collars to hedge natural gas prices to manage price risk. Swaps are settled monthly based on differences between the prices specified in the instruments and the settlement prices of futures contracts. Generally, when the applicable settlement price is less than the price specified in the contract, Comstock receives a settlement from the counterparty based on the difference multiplied by the volume or amounts hedged. Similarly, when the applicable settlement price exceeds the price specified in the contract, Comstock pays the counterparty based on the difference. Comstock generally receives a settlement from the counterparty for floors when the applicable settlement price is less than the price specified in the contract, which is based on the difference multiplied by the volumes hedged. For collars, generally Comstock receives a settlement from the counterparty when the settlement price is below the floor and pays a settlement to the counterparty when the settlement price exceeds the cap. No settlement occurs when the settlement price falls between the floor and cap.

All of the Company's derivative financial instruments are used for risk management purposes and, by policy, none are held for trading or speculative purposes. Comstock minimizes credit risk to counterparties of its derivative financial instruments through formal credit policies, monitoring procedures, and diversification. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the assets securing its bank credit facility. None of the Company's derivative financial instruments involve payment or receipt of premiums. The Company classifies the fair value amounts of derivative financial instruments as net current or noncurrent assets or liabilities, whichever the case may be, by commodity contract. None of the Company's derivative contracts are designated as fair value or cash flow hedges. The Company recognizes cash settlements and changes in the fair value of its derivative financial instruments as a single component of other income (expenses) in the consolidated statements of operations and as separate components within cash flows from operating activities in the consolidated statements of cash flows. All of Comstock's natural gas derivative financial instruments are tied to the Henry Hub-NYMEX price index.

The Company had the following outstanding natural gas price derivative financial instruments at December 31, 2025:

	Future Production Period Ending December 31, 2026
Natural Gas Price Swap Contracts:
Volume (MMBtu)	116,800,000
Average Price per MMBtu	$3.51
Natural Gas Price Collar Contracts:
Volume (MMBtu)	167,900,000
Price per MMBtu:
Average Ceiling	$4.35
Average Floor	$3.50

Subsequent to December 31, 2025, the Company entered into natural gas collar contracts to hedge an additional 58.4 Bcf of 2027 natural gas production at an average ceiling price of $4.37 per MMBtu and an average floor price of $3.50 per MMBtu.

F-22

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The aggregate fair value of the Company's derivative financial instruments is presented on a gross basis in the accompanying consolidated balance sheets. The classification of derivative financial instruments between assets and liabilities consists of the following:

		As of December 31,
Type	Consolidated Balance Sheet Location	2025		2024
		(in thousands)
Asset Derivative Financial Instruments:
Natural gas price derivatives	Derivative Financial Instruments – current	$	19,206	$	4,865
Liability Derivative Financial Instruments:
Natural gas price derivatives	Derivative Financial Instruments – current	$	27,636	$	8,940
Natural gas price derivatives	Derivative Financial Instruments – long-term	$	—	$	66,757

The Company recognizes cash settlements and changes in the fair value of its derivative financial instruments as a single component of other income (expenses). Gains and losses related to cash settlements and changes in the fair value recognized on the Company's derivative contracts recognized in the consolidated statement of operations were as follows:

	Year Ended December 31,
Gain/(Loss) Recognized in Earnings on Derivatives	2025		2024		2023
	(In thousands)
Natural gas price derivatives	$	82,537	$	10,196	$	187,639

(11)Related Party Transactions

The Company operates natural gas and oil properties held by partnerships owned by its majority stockholder. Comstock charges the partnership for the costs incurred to drill, complete and produce the wells, as well as drilling and operating overhead fees. Comstock also provides natural gas marketing services to the partnerships in return for a fee equal to $0.02 per Mcf for natural gas marketed. The Company received $1.1 million, $1.1 million and $1.3 million in 2025, 2024 and 2023, respectively, for operating and marketing services provided to the partnership. The fees received for the services are reflected as a reduction of general and administrative expenses in the accompanying consolidated statements of operations.

In connection with the operation of the wells, the Company had a $3.6 million and $5.5 million receivable from the partnerships at December 31, 2025 and 2024, respectively.

(12)Subsequent Event

In January 2026, PGS entered into an agreement with Quantum under which PGS agreed to redeem all of the outstanding Class B Units of PGS in exchange for cash consideration of $440 million plus any accrued but unpaid distributions. The redemption is expected to be completed in the first half of 2026.

F-23

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(13)Natural Gas and Oil Reserves Information (Unaudited)

Set forth below is a summary of the Company's proved natural gas and oil reserves:

	Year Ended December 31,
	2025						2024						2023
	Oil (MBbls)			Natural Gas (MMcf)			Oil (MBbls)			Natural Gas (MMcf)			Oil (MBbls)			Natural Gas (MMcf)
Proved Reserves:
Beginning of period		331			3,762,098			548			4,940,226			549			6,697,570
Revisions of previous estimates		(8	)		(29,753	)		(49	)		(1,180,157	)		(47	)		(1,803,628	)
Extensions and discoveries		—			3,737,848		—				531,258			116			570,751
Sales of minerals in place		(88	)		(15,870	)		(118	)		(1,681	)		—			—
Production		(37	)		(450,202	)		(50	)		(527,548	)		(70	)		(524,467	)
End of period		198			7,004,121			331			3,762,098			548			4,940,226
Proved Developed Reserves:
Beginning of period		331			2,731,812			548			2,734,175			480			2,531,462
End of period		198			2,840,638			331			2,731,812			548			2,734,175
Proved Undeveloped Reserves:
Beginning of period		—			1,030,286			—			2,206,051			69			4,166,108
End of period		—			4,163,483			—			1,030,286			—			2,206,051

Revisions of previous estimates. Revisions of previous estimates in 2024 and 2023 were primarily attributable to the significantly lower natural gas and oil prices that were used to determine proved reserves at the end of each year, which resulted in many of the Company's proved undeveloped locations being excluded from reserves since they did not generate an adequate return at those lower prices.

Extensions and discoveries. Extensions and discoveries for 2025, 2024 and 2023 were primarily comprised of proved reserve additions attributable to the wells drilled in the current year that were not classified as proved undeveloped in prior years and additional proved undeveloped locations that are planned to be drilled in the Company's current development plan that were not included in the prior year's reserve estimates. 2025 extensions and discoveries include proved undeveloped reserves that were excluded in 2024 and 2023 due to low natural gas prices.

Sales of minerals in place. During 2025, the Company sold certain natural gas and oil properties for $432.4 million. During 2024, the Company sold its interest in certain non-operated wells for $1.2 million.

The following table sets forth the standardized measure of discounted future net cash flows relating to proved reserves:

	As of December 31,
	2025			2024			2023
	(In thousands)
Cash Flows Relating to Proved Reserves:
Future Cash Flows	$	21,515,086		$	6,959,475		$	11,829,623
Future Costs:
Production		(5,544,264	)		(2,760,616	)		(4,019,901	)
Development and Abandonment		(4,797,691	)		(1,014,446	)		(2,285,853	)
Future Income Taxes		(1,347,093	)		(22,990	)		(341,677	)
Future Net Cash Flows		9,826,038			3,161,423			5,182,192
10% Discount Factor		(5,958,964	)		(1,563,229	)		(2,807,562	)
Standardized Measure of Discounted Future Net Cash Flows	$	3,867,074		$	1,598,194		$	2,374,630

The following table sets forth the changes in the standardized measure of discounted future net cash flows relating to proved reserves:

F-24

COMSTOCK RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
Standardized Measure, Beginning of Year	$	1,598,194		$	2,374,630		$	12,609,636
Net change in sales price, net of production costs		1,833,985			(1,478,758	)		(14,069,134	)
Development costs incurred during the year which were previously estimated		438,081			452,533			1,004,650
Revisions of quantity estimates		(45,201	)		(693,905	)		(1,583,876	)
Accretion of discount		160,277			250,170			1,551,704
Changes in future development and abandonment costs		(456,583	)		764,629			1,095,844
Changes in timing and other		176,754			94,058			(374,087	)
Extensions and discoveries		1,853,922			380,544			215,249
Sales of minerals in place		(1,747	)		(3,542	)		—
Sales, net of production costs		(1,098,926	)		(664,653	)		(855,699	)
Net changes in income taxes		(591,682	)		122,488			2,780,343
Standardized Measure, End of Year	$	3,867,074		$	1,598,194		$	2,374,630

The standardized measure of discounted future net cash flows was determined based on the simple average of the first of month market prices for natural gas and oil for each year. Prices used in determining quantities of natural gas and oil reserves and future cash inflows from natural gas and oil reserves represent prices received at the Company's sales point. These prices have been adjusted from posted or index prices for both location and quality differences. Prices used in determining natural gas and oil reserves quantities and cash flows are as follows:

	Year Ended December 31,
	2025		2024		2023
Crude Oil: $/barrel	$	61.98	$	71.07	$	72.63
Natural Gas: $/Mcf	$	3.07	$	1.84	$	2.39

Proved reserve information utilized in the preparation of the financial statements were based on estimates prepared by the Company's petroleum engineering staff in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve reports be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual agreement. All of the Company's reserves are located onshore in the continental United States of America. The Company retained an independent petroleum consultant to conduct an audit of the Company's 2025 reserve estimates. The purpose of this audit was to provide additional assurance on the reasonableness of internally prepared reserve estimates. The engineering firm was selected for their geographic expertise and their historical experience.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing proved natural gas and oil reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not reflect the impact of future operations.

F-25

EX-4.5

Exhibit 4.5

DESCRIPTION OF SECURITIES

The following description of our securities is intended as a summary only and therefore is not complete. This description is based upon, and is qualified by reference to, our Second Amended and Restated Articles of Incorporation, our Amended and Restated Bylaws, and our Certificate of Designations, each as amended from time to time, and by applicable provisions of the common law of the State of Nevada. For the complete terms of the capital stock, please refer to our Second Amended and Restated Articles of Incorporation (as amended, our "Articles of Incorporation"), our Amended and Restated Bylaws (as amended, our "Amended and Restated Bylaws"), which are incorporated by reference as exhibits to this Annual Report on Form 10-K.

General

We are a company incorporated under the laws of the State of Nevada and our affairs are governed by our Articles of Incorporation, our Amended and Restated Bylaws and the common law of the State of Nevada. Our authorized capital stock currently consists of 400,000,000 shares of common stock, par value $0.50 per share ("Common Stock") and 5,000,000 shares of preferred stock, par value $10.00 per share ("Preferred Stock"). The following description summarizes certain terms of our shares as set out more particularly in our Articles of Incorporation and our Amended and Restated Bylaws.

Common Stock

Each holder of Common Stock is entitled to one vote per share. Subject to the rights, if any, of the holders of any series of Preferred Stock pursuant to applicable law or the provision of the certificate of designation creating that series, all voting rights are vested in the holders of shares of Common Stock. Holders of shares of Common Stock have no right to cumulate votes in the election of directors, thus, the holders of a majority of the shares of Common Stock can elect all of the members of the board of directors standing for election. All outstanding shares of Common Stock are fully paid and non-assessable.

Dividends may be paid to the holders of Common Stock when, as, and if declared by the board of directors out of funds legally available for their payment. Any future determination as to the payment of dividends will depend upon the results of our operations, capital requirements, our financial condition and such other factors as our board of directors may deem relevant.

In the event of our voluntary or involuntary liquidation, dissolution, or winding up, the holders of Common Stock will be entitled to share equally, in proportion to the number of shares of Common Stock held by them, in any of our assets available for distribution after the payment in full of all debts and distributions have received their liquidation preferences in full. Holders of Common Stock are not entitled to preemptive purchase rights in future offerings of our Common Stock. Although our Articles of Incorporation do not specifically deny preemptive rights, pursuant to Nevada law, our stockholders do not have preemptive rights with respect to shares that are registered under Section 12 of the Exchange Act and our Common Stock is so registered.

Preferred Stock

Our board of directors can, without approval of our stockholders, issue one or more series of Preferred Stock and determine the number of shares of each series and the rights, preferences, and limitations of each series.

Anti-Takeover Provisions

Our Articles of Incorporation, our Amended and Restated Bylaws, and Nevada law include certain provisions which may have the effect of delaying or deterring a change in control or in our management or encouraging persons considering unsolicited tender offers or other unilateral takeover proposals to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. These provisions include authorized blank check Preferred Stock, restrictions on business combinations, and the availability of authorized but unissued Common Stock.

1

Combination with Interested Stockholders Statute

Sections 78.411 to 78.444 of the Nevada Revised Statutes (“N.R.S.”), which apply to any publicly traded Nevada corporation with 200 or more stockholders of record which has not otherwise effectively opted out of application of the Combinations with Interested Stockholders Statute in its Articles of Incorporation, or by amendment thereto, including us, prohibits an “interested stockholder” from entering into a “combination” with the corporation for two years, unless certain conditions are met. A “combination” includes:

•any merger of the corporation or any subsidiary of the corporation with an “interested stockholder,” or any other entity, whether or not itself an “interested stockholder,” which is, or after and as a result of the merger would be, an affiliate or associate of an “interested stockholder;”

•any sale, lease, exchange, mortgage, pledge, transfer, or other disposition in one transaction, or a series of transactions, to or with an “interested stockholder” or any affiliate or associate of an “interested stockholder,” of assets of the corporation or any subsidiary:

ohaving an aggregate market value equal to more than 5% of the aggregate market value of the corporation’s assets, determined on a consolidated basis;

ohaving an aggregate market value equal to more than 5% of the aggregate market value of all outstanding voting shares of the corporation; or

orepresenting more than 10% of the earning power or net income, determined on a consolidated basis, of the corporation; or

•the issuance or transfer by the corporation or any subsidiary, of any shares of the corporation or any subsidiary to an “interested stockholder” or any affiliate or associate of an “interested stockholder,” having an aggregate market value equal to 5% or more of the aggregate market value of all of the outstanding voting shares of the corporation, except under the exercise of warrants or rights to purchase shares offered, or a dividend or distribution paid or made, pro rata to all stockholders of the resident domestic corporation;

•the adoption of any plan, or proposal for the liquidation or dissolution of the corporation, under any agreement, arrangement or understanding, with the “interested stockholder,” or any affiliate or associate of the “interested stockholder;”

•if any of the following actions occurs:

oa reclassification of the corporation’s securities, including, without limitation, any splitting of shares, share dividend, or other distribution of shares with respect to other shares, or any issuance of new shares in exchange for a proportionately greater number of old shares;

orecapitalization of the corporation;

omerger or consolidation of the corporation with any subsidiary;

oor any other transaction, whether or not with or into or otherwise involving the interested stockholder,

under any agreement, arrangement or understanding, whether or not in writing, with the interested stockholder or any affiliate or associate of the interested stockholder, which has the immediate and proximate effect of increasing the proportionate share of the outstanding shares of any class or series of voting shares or securities convertible into voting shares of the corporation or any subsidiary of the corporation which is beneficially owned by the interested stockholder or any affiliate or associate of the interested stockholder, except as a result of immaterial changes because of adjustments of fractional shares.

•any receipt by an “interested stockholder” or any affiliate or associate of an “interested stockholder,” except proportionately as a stockholder of the corporation, of the benefit of any loan, advance, guarantee, pledge or other financial assistance or any tax credit or other tax advantage provided by or through the corporation.

2

An “interested stockholder” is a person who is:

•directly or indirectly, the beneficial owner of 10% or more of the voting power of the outstanding voting shares of the corporation; or

•an affiliate or associate of the corporation, which at any time within two years immediately before the date in question was the beneficial owner, ‎directly or indirectly, of 10% or more of the voting power of the then outstanding shares of the corporation.‎

A corporation to which the Combinations with Interested Stockholders Statute applies may not engage in a “combination” within two years after the interested stockholder first became an interested stockholder, unless the combination meets all of the requirements of the corporation’s articles of incorporation and (i) the combination or the transaction by which the person first became an interested stockholder is approved by the board of directors before the person first became an interested stockholder, or (ii)(a) the combination is approved by the board of directors and (b) at or after that time, the combination is approved at an annual or special meeting of the stockholders, and not by written consent, by the affirmative vote of the stockholders representing at least sixty percent (60%) of the outstanding voting power of the corporation not beneficially owned by the interested stockholder or the affiliates or associates of the interested stockholder. If this approval is not obtained, the combination may be consummated after the two year period expires if either (i)(a) the combination or transaction by which the person first became an interested stockholder is approved by the board of directors before such person first became an interested stockholder, (b) the combination is approved by a majority of the outstanding voting power of the corporation not beneficially owned by the interested stockholder or any affiliate or associate of the interested stockholder, or (c) the combination otherwise meets the requirements of the Combination with Interested Stockholders statute. Alternatively, a combination with an interested stockholder engaged in more than 2 years after the date the person first became an interested stockholder may be permissible if the aggregate amount of cash and the market value of consideration other than cash to be received by holders of shares of Common Stock and holders of any other class or series of shares meets the minimum requirements set forth in the statue, and prior to the completion of the combination, except in limited circumstances, the interested stockholder has not become the beneficial owner of additional voting shares of the corporation.

Acquisition of Controlling Interest Statute

In addition, Nevada’s “Acquisition of Controlling Interest Statute,” prohibits an acquiror, under certain circumstances, from voting shares of a target corporation’s stock after crossing certain threshold ownership percentages, unless the acquiror obtains the approval of the target corporation’s stockholders. Sections 78.378 to 78.3793 of the N.R.S. only apply to Nevada corporations with at least 200 stockholders, including at least 100 record stockholders who are Nevada residents, that do business directly or indirectly in Nevada and whose articles of incorporation or bylaws in effect 10 days following the acquisition of a controlling interest by an acquiror do not prohibit its application.

We do not intend to “do business” in Nevada within the meaning of the Acquisition of Controlling Interest Statute. Therefore, we believe it is unlikely that this statute will apply to us. The statute specifies three thresholds that constitute a controlling interest:

•at least one-fifth but less than one-third;

•at least one-third but less than a majority; and

•a majority or more, of the outstanding voting power.

Once an acquiror crosses one of these thresholds, shares which it acquired in the transaction taking it over the threshold (or within ninety days preceding the date thereof) become “control shares” which could be deprived of the right to vote until a majority of the disinterested stockholders restore that right.

A special stockholders’ meeting may be called at the request of the acquiror to consider the voting rights of the acquiror’s shares. If the acquiror requests a special meeting and gives an undertaking to pay the expenses of said meeting, then the meeting must take place no earlier than 30 days (unless the acquiror requests that the meeting be held sooner) and no more than 50 days (unless the acquiror agrees to a later date) after the delivery by the acquiror to the corporation of an information statement which sets forth the range of voting power that the acquiror has acquired or proposes to acquire and certain other information concerning the acquiror and the proposed control share acquisition.

3

If no such request for a stockholders’ meeting is made, consideration of the voting rights of the acquiror’s shares must be taken at the next special or annual stockholders’ meeting. If the stockholders fail to restore voting rights to the acquiror, or if the acquiror fails to timely deliver an information statement to the corporation, then the corporation may, if so provided in its articles of incorporation or bylaws, call certain of the acquiror’s shares for redemption at the average price paid for the control shares by the acquiror.

Our Articles of Incorporation and Amended and Restated Bylaws do not currently permit us to redeem an acquiror’s shares under these circumstances. The Acquisition of Controlling Interest Statute also provides that in the event the stockholders restore full voting rights to a holder of control shares that owns a majority of the voting stock, then all other stockholders who do not vote in favor of restoring voting rights to the control shares may demand payment for the “fair value” of their shares as determined by a court in dissenters rights proceeding pursuant to Chapter 92A of the N.R.S.

Our Transfer Agent

Equiniti Trust Company, LLC is the transfer agent and registrar for our Common Stock.

Listing of Common Stock

Our Common Stock trades on the NYSE and NYSE Texas under the symbol “CRK”.

4

EX-21

Exhibit 21

SUBSIDIARIES OF COMSTOCK RESOURCES, INC.

Name	Incorporation	Business Name
Comstock Oil & Gas, LLC	Nevada	Comstock Oil & Gas, LLC
Comstock Oil & Gas – Louisiana, LLC (1)	Nevada	Comstock Oil & Gas – Louisiana, LLC
Comstock Gas Services LLC (1)	Texas	Comstock Gas Services LLC
Pinnacle Gas Services LLC	Delaware	Pinnacle Gas Services LLC
Pinnacle Gas Treating LLC	Texas	Pinnacle Gas Treating LLC

(1)100% owned by Comstock Oil & Gas, LLC

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the following Registration Statements:

(1)Registration Statements (Form S-3 Nos. 333-228311, 333-232924, 333-234685, 333-237677, 333-238113, 333-248080, 333-256221 and 333-280104) of Comstock Resources, Inc. and in the related prospectuses,

(2)Registration Statement (Form S-8 No. 033-88962) pertaining to the Comstock Resources, Inc. 401(k) Profit Sharing Plan, and

(3)Registration Statement (Form S-8 No. 333-287809) pertaining to the Comstock Resources, Inc. 2019 Long-Term Incentive Plan;

of our reports dated February 19, 2026, with respect to the consolidated financial statements of Comstock Resources, Inc. and subsidiaries and the effectiveness of internal control over financial reporting of Comstock Resources, Inc. and subsidiaries included in this Annual Report (Form 10-K) of Comstock Resources, Inc. for the year ended December 31, 2025.

/s/ ERNST & YOUNG

Dallas, Texas

February 19, 2026

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the inclusion in the Form 10-K of Comstock Resources, Inc. (the "Form 10-K") of our audit letter dated January 22, 2026 on oil and gas reserves of Comstock Resources, Inc. and its subsidiaries as of December 31, 2025, to all references to our firm included in the Form 10-K, and to the incorporation by reference of such reports in the Registration Statements of Comstock Resources, Inc. on the following forms:

(1)Registration Statement (Form S-8 No. 033-88962) pertaining to the Comstock Resources, Inc. 401(k) Profit Sharing Plan;

(2)Registration Statement (Form S-3 No. 333-228311) of Comstock Resources, Inc.;

(3)Registration Statement (Form S-3 No. 333-232924) of Comstock Resources, Inc.;

(4)Registration Statement (Form S-3 No. 333-234685) of Comstock Resources, Inc.;

(5)Registration Statement (Form S-3 No. 333-237677) of Comstock Resources, Inc.;

(6)Registration Statement (Form S-3 No. 333-238113) of Comstock Resources, Inc.;

(7)Registration Statement (Form S-3 No. 333-248080) of Comstock Resources, Inc.;

(8)Registration Statement (Form S-3 No. 333-256221) of Comstock Resources, Inc.;

(9)Registration Statement (Form S-3 No. 333-280104) of Comstock Resources, Inc.; and

(10)Registration Statement (Form S-8 No. 333-287809) pertaining to the Comstock Resources, Inc. 2019 Long-Term Incentive Plan.

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ Eric J. Stevens
	Eric J. Stevens, P.E.
	President and Chief Operating Officer

Dallas, Texas

February 19, 2026

EX-31.1

Exhibit 31.1

Section 302 Certification

I, M. Jay Allison, certify that:

1.I have reviewed this Annual Report on Form 10-K of Comstock Resources, Inc;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 19, 2026

/s/ M. JAY ALLISON

Chief Executive Officer

EX-31.2

Exhibit 31.2

Section 302 Certification

I, Roland O. Burns, certify that:

1.I have reviewed this Annual Report on Form 10-K of Comstock Resources, Inc;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 19, 2026

/s/ ROLAND O. BURNS

President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Comstock Resources, Inc. (the “Company”) on Form 10-K for the year ending December 31, 2025 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, M. Jay Allison, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ M. JAY ALLISON

M. Jay Allison

Chief Executive Officer

February 19, 2026

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Comstock Resources, Inc. (the “Company”) on Form 10-K for the year ending December 31, 2025 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Roland O. Burns, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ ROLAND O. BURNS

Roland O. Burns

Chief Financial Officer

February 19, 2026

EX-99.1

Exhibit 99.1

January 22, 2026

Ms. Kristine Bartlett

Comstock Resources, Inc.

5300 Town & Country Boulevard, Suite 500

Frisco, Texas 75034

Dear Ms. Bartlett:

In accordance with your request, we have audited the estimates prepared by Comstock Resources, Inc. (Comstock), as of December 31, 2025, of the proved reserves and future revenue to the Comstock interest in certain gas and oil properties located in Louisiana, Oklahoma, Texas, and Wyoming. It is our understanding that the proved reserves estimates shown herein constitute all of the proved reserves owned by Comstock. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance with the definitions and regulations of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. We completed our audit on or about the date of this letter. This report has been prepared for Comstock's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The following table sets forth Comstock's estimates of the net reserves and future net revenue, as of December 31, 2025, for the audited properties:

	Net Reserves				Future Net Revenue (M$)
	Gas(1)		Oil				Present Worth
Category	(MMCFE)		(MBBL)		Total		at 10%
Proved Developed Producing		2,813,569.8		197.9		5,677,413.9		3,042,597.9
Proved Developed Non-Producing		27,068.7		0.1		42,340.6		17,309.0
Proved Undeveloped		4,163,482.9		-		5,336,964.1		1,403,430.3
Total Proved		7,004,121.1		198.0		11,056,719.9		4,463,338.0

Totals may not add because of rounding.

(1) Gas reserves are inclusive of natural gas liquids (NGL) equivalent volumes, determined using the ratio of 6 MCF of gas to 1 barrel of NGL.

Gas equivalent volumes are expressed in millions of cubic feet equivalent (MMCFE) at standard temperature and pressure bases. The oil volumes shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons.

When compared on a lease-by-lease basis, some of the estimates of Comstock are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. (NSAI). However, in our opinion the estimates shown herein of Comstock's reserves and future revenue are reasonable when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by Comstock in preparing the December 31, 2025, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Comstock.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk. Comstock's estimates do not include probable or possible reserves that exist for these properties, nor do they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.

Prices used by Comstock are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2025. For gas volumes, the average Henry Hub spot price of $3.387 per MMBTU is adjusted for energy content, transportation fees, and market differentials; when applicable, gas prices have been adjusted to include the value for NGL. For oil volumes, the average West Texas Intermediate spot price of $65.34 per barrel is adjusted for quality and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $3.070 per MCFE of gas and $61.98 per barrel of oil.

Operating costs used by Comstock are based on historical operating expense records. For the nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs for the operated properties are limited to direct lease- and field-level costs and Comstock's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into per-well costs and per-unit-of-production costs. Capital costs used by Comstock are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for tubing installation, workovers, new development wells, and production equipment. Abandonment costs used are Comstock's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Operating, capital, and abandonment costs are not escalated for inflation.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of Comstock and NSAI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Comstock, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of all properties. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by Comstock with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Our audit did not include a review of Comstock's overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the

interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by Comstock, are on file in our office. The technical persons primarily responsible for conducting this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Matthew T. Dalka, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2013 and has over 7 years of prior industry experience. William J. Knights, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 10 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By:	/s/ Richard B. Talley, Jr.
	Richard B. Talley, Jr., P.E.
	Chairman and Chief Executive Officer

By:	/s/ Matthew T. Dalka	By:	/s/ William J. Knights
	Matthew T. Dalka, P.E. 125306		William J. Knights, P.G. 1532
	Vice President		Vice President

Date Signed: January 22, 2026 Date Signed: January 22, 2026

MTD:JMP

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Feb. 18, 2026

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COMSTOCK RESOURCES, INC.

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DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Definitive Proxy Statement for the 2026 Annual Meeting of Stockholders to be filed with the Securities and Exchange Commission not later than 120 days after

December 31, 2025 are incorporated by reference into Part III of this report.

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Auditor Opinion [Text Block]

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Comstock Resources, Inc. and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 19, 2026 expressed an unqualified opinion thereon.

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
ASSETS
Cash and cash equivalents	$ 23,930	$ 6,799
Accounts receivable:
Natural gas and oil sales and gas services	203,549	145,398
Joint interest operations	35,400	23,956
From affiliates	3,596	5,492
Derivative financial instruments	19,206	4,865
Other current assets	75,257	97,524
Total current assets	360,938	284,034
Natural gas and oil properties, successful efforts method:
Proved	8,984,969	8,054,250
Unproved	391,065	424,648
Other	386,656	150,023
Accumulated depreciation, depletion and amortization	(3,547,196)	(2,940,532)
Net property and equipment	6,215,494	5,688,389
Goodwill	335,897	335,897
Operating lease right-of-use assets	94,733	73,777
Total assets	7,007,062	6,382,097
LIABILITIES AND STOCKHOLDERS' EQUITY
Accounts payable	501,695	421,814
Accrued expenses	153,248	146,173
Operating leases	46,937	35,927
Derivative financial instruments	27,636	8,940
Total current liabilities	729,516	612,854
Long-term debt	2,809,066	2,952,090
Deferred income taxes	437,098	345,116
Derivative financial instruments	0	66,757
Long-term operating leases	47,692	37,740
Reserve for future abandonment costs	20,787	33,996
Total liabilities	4,044,159	4,048,553
Commitments and contingencies
Stockholders' equity:
Common stock - $0.50 par, 400,000,000 shares authorized, 293,054,806 and 292,260,645 shares issued and outstanding at December 31, 2025 and 2024, respectively	146,527	146,130
Additional paid-in capital	1,376,053	1,366,274
Accumulated earnings	1,124,230	728,619
Total stockholders' equity attributable to Comstock	2,646,810	2,241,023
Noncontrolling interest	316,093	92,521
Total stockholders' equity	2,962,903	2,333,544
Total liabilities and stockholders' equity	$ 7,007,062	$ 6,382,097

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2025	Dec. 31, 2024
Common stock, par value (in dollars per share)	$ 0.5	$ 0.5
Common stock, shares authorized (in shares)	400,000,000	400,000,000
Common stock, shares issued (in shares)	293,054,806	292,260,645
Common stock, shares outstanding (in shares)	293,054,806	292,260,645

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CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Revenues:
Total revenues and other operating income	$ 2,220,289	$ 1,254,455	$ 1,565,234
Operating expenses:
Production and ad valorem taxes	40,453	57,437	91,803
Gathering and transportation	166,108	194,890	184,906
Lease operating	122,662	130,504	132,203
Depreciation, depletion and amortization	641,163	795,397	607,908
Gas services	516,224	205,407	282,050
General and administrative, net	48,685	39,435	37,992
Impairment of natural gas and oil properties	29,071	0	0
Exploration	10,071	0	1,775
Total operating expenses	1,574,437	1,423,070	1,338,637
Operating income (loss)	645,852	(168,615)	226,597
Other income (expenses):
Gain from derivative financial instruments	82,537	10,196	187,639
Other income	3,144	1,211	1,771
Interest expense	(222,797)	(210,621)	(169,018)
Total other income (expenses)	(137,116)	(199,214)	20,392
Income (loss) before income taxes	508,736	(367,829)	246,989
(Provision for) benefit from income taxes	(88,533)	149,075	(35,095)
Net income (loss)	420,203	(218,754)	211,894
Net income attributable to noncontrolling interest	(24,592)	(10,897)	(777)
Net income (loss) available to Comstock	$ 395,611	$ (229,651)	$ 211,117
Net income (loss) per share:
Basic (in dollars per share)	$ 1.43	$ (0.76)	$ 0.76
Diluted (in dollars per share)	$ 1.43	$ (0.76)	$ 0.76
Weighted average shares outstanding:
Basic (in shares)	290,779	287,010	276,806
Diluted (in shares)	294,131	287,010	276,806
Dividends per share	$ 0	$ 0	$ 0.500
Total natural gas and oil sales
Revenues:
Total revenues and other operating income	$ 1,428,149	$ 1,047,483	$ 1,264,611
Natural gas sales
Revenues:
Total revenues and other operating income	1,425,857	1,043,886	1,259,450
Oil sales
Revenues:
Total revenues and other operating income	2,292	3,597	5,161
Gas services
Revenues:
Total revenues and other operating income	500,202	206,097	300,498
Gain on sale of assets
Revenues:
Total revenues and other operating income	$ 291,938	$ 875	$ 125

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Accumulated Earnings (Deficit)	Noncontrolling Interest
Beginning balance (in shares) at Dec. 31, 2022		277,517
Beginning balance at Dec. 31, 2022	$ 2,278,314	$ 138,759	$ 1,253,417	$ 886,138
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation (in shares)		1,103
Stock-based compensation	9,867	$ 550	9,317
Income tax withholdings on equity awards (in shares)		(190)
Income tax withholdings on equity awards	(1,899)	$ (95)	(1,804)
Net income (loss)	211,894			211,117	$ 777
Payment of common stock dividends	(138,985)			(138,985)
Contributions from noncontrolling interest	24,000				24,000
Ending balance (in shares) at Dec. 31, 2023		278,430
Ending balance at Dec. 31, 2023	2,383,191	$ 139,214	1,260,930	958,270	24,777
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation (in shares)		1,622
Stock-based compensation	15,261	$ 812	14,449
Income tax withholdings on equity awards (in shares)		(291)
Income tax withholdings on equity awards	(3,373)	$ (146)	(3,227)
Issuance of common stock (in shares)		12,500
Issuance of common stock	100,450	$ 6,250	94,200
Stock issuance costs	(78)		(78)
Net income (loss)	(218,754)			(229,651)	10,897
Contributions from noncontrolling interest	60,500				60,500
Distributions to noncontrolling interest	(3,653)				(3,653)
Ending balance (in shares) at Dec. 31, 2024		292,261
Ending balance at Dec. 31, 2024	2,333,544	$ 146,130	1,366,274	728,619	92,521
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation (in shares)		1,255
Stock-based compensation	21,222	$ 628	20,594
Income tax withholdings on equity awards (in shares)		(461)
Income tax withholdings on equity awards	(11,010)	$ (231)	(10,779)
Stock issuance costs	(36)		(36)
Net income (loss)	420,203			395,611	24,592
Contributions from noncontrolling interest	215,500				215,500
Distributions to noncontrolling interest	(16,520)				(16,520)
Ending balance (in shares) at Dec. 31, 2025		293,055
Ending balance at Dec. 31, 2025	$ 2,962,903	$ 146,527	$ 1,376,053	$ 1,124,230	$ 316,093

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 420,203	$ (218,754)	$ 211,894
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income taxes	91,982	(124,919)	44,301
Impairment of natural gas and oil properties	29,071	0	0
Gain on sale of assets	(291,938)	(875)	(125)
Depreciation, depletion and amortization	641,163	795,397	607,908
Gain on derivative financial instruments	(82,537)	(10,196)	(187,639)
Cash settlements of derivative financial instruments	20,135	207,803	80,328
Amortization of debt discount, premium and issuance costs	11,976	11,476	7,964
Stock-based compensation	21,222	15,261	9,867
(Increase) decrease in accounts receivable	(60,496)	56,584	278,697
(Increase) decrease in other current assets	17,518	(22,893)	745
Increase (decrease) in accounts payable and accrued expenses	81,308	(88,547)	(37,094)
Net cash provided by operating activities	899,607	620,337	1,016,846
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(1,349,280)	(1,097,478)	(1,425,086)
Prepaid drilling costs	5,002	11,988	(34,010)
Proceeds from sales of assets	428,868	1,214	41,295
Net cash used for investing activities	(915,410)	(1,084,276)	(1,417,801)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings on bank credit facility	750,000	645,000	820,000
Repayments on bank credit facility	(905,000)	(710,000)	(340,000)
Issuance of Senior Notes	0	372,000	0
Issuance of common stock	0	100,450	0
Debt and stock issuance costs	(36)	(6,855)	(144)
Income tax withholdings on equity awards	(11,010)	(3,373)	(1,899)
Common stock dividends paid	0	0	(138,985)
Contributions from noncontrolling interest	215,500	60,500	24,000
Distributions to noncontrolling interest	(16,520)	(3,653)	0
Net cash provided by financing activities	32,934	454,069	362,972
Net increase (decrease) in cash and cash equivalents	17,131	(9,870)	(37,983)
Cash and cash equivalents, beginning of the year	6,799	16,669	54,652
Cash and cash equivalents, end of the year	$ 23,930	$ 6,799	$ 16,669

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Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Pay vs Performance Disclosure
Net Income (Loss)	$ 395,611	$ (229,651)	$ 211,117

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

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Cybersecurity Risk Management, Strategy, and Governance Disclosure

12 Months Ended

Dec. 31, 2025

Cybersecurity Risk Management, Strategy, and Governance [Line Items]

Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]

ITEM 1C. CYBERSECURITY

We face various cybersecurity threats that could adversely affect our business, financial condition, and results of operations. We have implemented processes and procedures and engaged third-party service providers to assess, identify, and manage these risks, as well as to respond to and mitigate the impact of any potential or actual cybersecurity incidents to our information systems and the information residing therein.

Risk Management and Strategy

Our cybersecurity risk management processes have been integrated into our enterprise risk framework, which identifies, aggregates, and evaluates risks across the enterprise. We identify our enterprise risks through each member of our management team, along with counsel from our internal auditors and attorneys and we present an assessment of our enterprise risks to our board of directors on an annual basis. Our information technology management plays an integral part in the identification and communication of cybersecurity risks to our management team.

Our processes for assessing and identifying cybersecurity risks include, but are not limited to, the following elements:

•regular network security assessments and vulnerability scans performed by third parties;

•third-party audits of our information systems,

•third-party systems for monitoring and analysis of network activity and threat intelligence;

•systems for protecting our information technology, such as firewalls and anti-virus software;

•cybersecurity awareness training for our employees and contractors, including senior management;

•and processes to oversee and identify cybersecurity risks associated with our use of third-party service providers, such as conducting due diligence, reviewing contracts, and verifying compliance with security standards and best practices.

Despite our efforts, there is the ever-present risk that our systems and/or data will suffer a successful cyber incident such as unauthorized access, use, disclosure, modification, or destruction by hackers, cybercriminals, state-sponsored actors, insiders, or other malicious actors. We have experienced attempts to compromise our systems and/or data. These attempts included phishing attacks, malware infections, and unauthorized access attempts. We do not believe that these attempts, if successful, would have resulted in a material adverse effect on our business, financial condition, or results of operations. We continue to be diligent in preventing, detecting, and responding to cyber incidents. However, we cannot guarantee that we will not suffer cybersecurity incidents in the future. See Item 1A. Risk Factors "Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions."

Governance

The Audit Committee of our Board of Directors provides oversight over our cybersecurity risk management and strategy. The committee receives updates from our information technology management and external advisors on our cybersecurity posture, initiatives, and incidents on an annual or as needed basis. Our information technology department is responsible for assessing and managing our cybersecurity risks on a day-to-day basis and their processes for managing cybersecurity risks include implementing and maintaining security controls, policies, and procedures to protect our information systems and the information residing therein. They also provide periodic awareness notifications to our employees and contractors on cybersecurity best practices and their roles and responsibilities. In addition, we have established an incident response plan to coordinate our response to and recovery from any cybersecurity incidents. Our Director of Information Technology has over 20 years of experience in managing organizations in the energy and telecom industries. We also have a Certified Information Systems Security Professional, who has nine years of experience in cyber and information security.

Cybersecurity Risk Management Processes Integrated [Flag]

true

Cybersecurity Risk Management Processes Integrated [Text Block]

Our cybersecurity risk management processes have been integrated into our enterprise risk framework, which identifies, aggregates, and evaluates risks across the enterprise. We identify our enterprise risks through each member of our management team, along with counsel from our internal auditors and attorneys and we present an assessment of our enterprise risks to our board of directors on an annual basis. Our information technology management plays an integral part in the identification and communication of cybersecurity risks to our management team.

Cybersecurity Risk Management Third Party Engaged [Flag]

true

Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]

true

Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]

false

Cybersecurity Risk Board of Directors Oversight [Text Block]

Governance

The Audit Committee of our Board of Directors provides oversight over our cybersecurity risk management and strategy. The committee receives updates from our information technology management and external advisors on our cybersecurity posture, initiatives, and incidents on an annual or as needed basis. Our information technology department is responsible for assessing and managing our cybersecurity risks on a day-to-day basis and their processes for managing cybersecurity risks include implementing and maintaining security controls, policies, and procedures to protect our information systems and the information residing therein. They also provide periodic awareness notifications to our employees and contractors on cybersecurity best practices and their roles and responsibilities. In addition, we have established an incident response plan to coordinate our response to and recovery from any cybersecurity incidents. Our Director of Information Technology has over 20 years of experience in managing organizations in the energy and telecom industries. We also have a Certified Information Systems Security Professional, who has nine years of experience in cyber and information security.

Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]

The Audit Committee of our Board of Directors provides oversight over our cybersecurity risk management and strategy. The committee receives updates from our information technology management and external advisors on our cybersecurity posture, initiatives, and incidents on an annual or as needed basis.

Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]

The committee receives updates from our information technology management and external advisors on our cybersecurity posture, initiatives, and incidents on an annual or as needed basis.

Cybersecurity Risk Role of Management [Text Block]

Our information technology department is responsible for assessing and managing our cybersecurity risks on a day-to-day basis and their processes for managing cybersecurity risks include implementing and maintaining security controls, policies, and procedures to protect our information systems and the information residing therein. They also provide periodic awareness notifications to our employees and contractors on cybersecurity best practices and their roles and responsibilities. In addition, we have established an incident response plan to coordinate our response to and recovery from any cybersecurity incidents. Our Director of Information Technology has over 20 years of experience in managing organizations in the energy and telecom industries. We also have a Certified Information Systems Security Professional, who has nine years of experience in cyber and information security.

Cybersecurity Risk Management Positions or Committees Responsible [Flag]

true

Cybersecurity Risk Management Positions or Committees Responsible [Text Block]

Our information technology department is responsible for assessing and managing our cybersecurity risks on a day-to-day basis and their processes for managing cybersecurity risks include implementing and maintaining security controls, policies, and procedures to protect our information systems and the information residing therein.

Cybersecurity Risk Management Expertise of Management Responsible [Text Block]

Our Director of Information Technology has over 20 years of experience in managing organizations in the energy and telecom industries. We also have a Certified Information Systems Security Professional, who has nine years of experience in cyber and information security.

Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]

They also provide periodic awareness notifications to our employees and contractors on cybersecurity best practices and their roles and responsibilities. In addition, we have established an incident response plan to coordinate our response to and recovery from any cybersecurity incidents.

Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]

true

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

(1)Summary of Significant Accounting Policies

Accounting policies used by Comstock Resources, Inc. and subsidiaries reflect natural gas and oil industry practices and conform to accounting principles generally accepted in the United States of America.

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of Comstock Resources, Inc., its wholly owned or controlled subsidiaries and a variable interest entity for which Comstock is the primary beneficiary (collectively, "Comstock" or the "Company"). All significant intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its undivided interest in natural gas and oil properties using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are included in its financial statements. Net income (loss) and comprehensive income (loss) are the same in all periods presented. All adjustments are of a normal recurring nature unless otherwise disclosed. Certain amounts in prior period footnote disclosures have been reclassified to conform with current period presentation.

Comstock entered into an agreement with an affiliate of Quantum Capital Solutions ("Quantum"), in 2023 to form Pinnacle Gas Services, LLC ("PGS"), a midstream company in Comstock's Western Haynesville area. As part of the transaction, Comstock contributed a high-pressure pipeline and a natural gas treating plant. Quantum committed to contribute up to $300 million to fund future expansion costs. Quantum is entitled to a 12% dividend on its invested capital and 80% of any distributions from Pinnacle until an investment return hurdle is met. After the return hurdle is met, Quantum's ownership reduces to 30%. Comstock operates and manages PGS pursuant to a management services agreement. The Board of PGS is comprised of five members: three selected by Comstock and two selected by Quantum. PGS is considered a variable interest entity to Comstock.

Comstock has the power to direct the activities that most significantly impact the performance of PGS and has the obligation to absorb losses or right to receive benefits that could potentially be significant to PGS. Accordingly, Comstock is considered the primary beneficiary and consolidates the assets, liabilities and results of operations of PGS in the accompanying consolidated financial statements. PGS assets that cannot be used by Comstock include $363.9 million of other property and equipment as of December 31, 2025. Other PGS assets that cannot be used by Comstock and PGS liabilities for which creditors do not have recourse to Comstock's assets are not material to the Company's consolidated financial statements. The portion of PGS net income and stockholders' equity not attributable to Comstock's controlling interest are shown separately as noncontrolling interests in the accompanying consolidated statements of operations and statements of stockholders' equity.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from those estimates. Changes in the future estimated natural gas and oil reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analyses could have a significant impact on the future results of operations.

Concentration of Credit Risk, Accounts Receivable and Credit Losses

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative financial instruments. The Company places its cash with high credit quality financial institutions and its derivative financial instruments with financial institutions and other firms that management believes have high credit ratings. Substantially all of the Company's accounts receivable are due from either purchasers of natural gas and oil or participants in natural gas and oil wells for which the Company serves as the operator. Generally, operators of natural gas and oil wells have the right to offset future revenues against unpaid charges related to operated wells. Natural gas and oil sales are generally unsecured. The Company's policy is to assess the collectability of its receivables based upon their age, the credit quality of the purchaser or participant and the potential for revenue offset. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectible. Accordingly, no allowance for doubtful accounts has been recorded for the years ended December 31, 2025, 2024 and 2023, respectively.

Other Current Assets

Other current assets at December 31, 2025 and 2024 consist of the following:

	As of December 31,
	2025		2024
	(In thousands)
Prepaid drilling costs	$	53,134	$	58,136
Other receivables		9,929		4,140
Production tax refunds receivable		5,827		4,074
Income tax receivable		3,024		28,813
Prepaid expenses		2,968		2,361
Other		375		—
	$	75,257	$	97,524

Fair Value Measurements

The Company holds or has held certain financial assets and liabilities that are required to be measured at fair value in the financial statements. These include cash and cash equivalents held in bank accounts and derivative financial instruments. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. A three-level hierarchy is followed for disclosure to show the extent and level of judgment used to estimate fair value measurements:

Level 1 — Inputs used to measure fair value are unadjusted quoted prices that are available in active markets for the identical assets or liabilities as of the reporting date.

Level 2 — Inputs used to measure fair value, other than quoted prices included in Level 1, are either directly or indirectly observable as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.

Level 3 — Inputs used to measure fair value are unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management's estimates of market participant assumptions.

The following presents the carrying amounts and the fair values of the Company's financial instruments as of December 31, 2025 and 2024:

	As of December 31,
	2025				2024
	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets:	(In thousands)
Commodity-based derivatives (1)	$	19,206	$	19,206	$	4,865	$	4,865
Liabilities:
Commodity-based derivatives (1)		27,636		27,636		75,697		75,697
Bank credit facility (2)		260,000		260,000		415,000		415,000
6.75% senior notes due 2029 (3)		1,607,880		1,603,582		1,603,679		1,581,283
5.875% senior notes due 2030 (3)		965,000		931,225		965,000		899,863

(1)The Company's commodity-based derivatives are classified as Level 2 and measured at fair value using a market approach using third party pricing services and other active markets or broker quotes that are readily available in the public markets.

(2)The carrying value of our floating rate debt outstanding approximates fair value.

(3)The fair value of the Company's fixed rate debt was based on quoted prices as of December 31, 2025 and 2024, respectively, a Level 1 measurement.

Property and Equipment

The Company follows the successful efforts method of accounting for its natural gas and oil properties. Costs incurred to acquire natural gas and oil leasehold are capitalized. Acquisition costs for proved natural gas and oil properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related natural gas and oil reserves. Equivalent units are determined by converting oil to natural gas at the ratio of one barrel of oil for six thousand cubic feet of natural gas. This conversion ratio is not based on the price of oil or natural gas, and there may be a significant difference in price between an equivalent volume of oil versus natural gas.

Exploratory well costs are initially capitalized as proved property in the consolidated balance sheets but charged to exploration expense if and when the well is determined not to have found commercial proved natural gas and oil reserves. The changes in capitalized exploratory well costs are as follows:

	Year Ended December 31,
	2025			2024
	(in thousands)
Beginning capitalized exploratory project costs	$	68,223		$	96,233
Additions to exploratory well costs pending the determination of proved reserves		490,429			354,557
Determined to have found proved reserves		(348,525	)		(382,567	)
Ending capitalized exploratory well costs	$	210,127		$	68,223

As of December 31, 2025 and 2024, the Company had no exploratory wells for which costs have been capitalized greater than one year.

The estimated future costs of dismantlement, restoration, plugging and abandonment of natural gas and oil properties and related facilities disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense. Exploration expense includes geological and geophysical expenses and delay rentals related to exploratory natural gas and oil properties, costs of unsuccessful exploratory drilling and impairments of unproved properties. As of December 31, 2025 and 2024, the unproved properties primarily relate to future drilling locations that were not included in proved undeveloped reserves. Most of these future drilling locations are located on acreage where the reservoir is known to be productive but have been excluded from proved reserves due to uncertainty on whether the wells would be drilled within the next five years as required by SEC rules in order to be included in proved reserves. The costs of unproved properties are transferred to proved natural gas and oil properties when they are either drilled or they are reflected in proved undeveloped reserves and amortized on an equivalent unit-of-production basis. Costs associated with unevaluated exploratory acreage are periodically assessed for impairment on a property by property basis, and any impairment in value is included in exploration expense. Exploratory drilling costs are initially capitalized as proved property but charged to expense if and when the well is determined not to have found commercial proved natural gas and oil reserves. Exploratory drilling costs are evaluated within a one-year period after the completion of drilling.

The Company assesses the need for an impairment of the costs capitalized for its proved natural gas and oil properties when events or changes in circumstances, such as a significant drop in commodity prices, indicate that the Company may not be able to recover its capitalized costs. If impairment is indicated based on undiscounted expected future cash flows attributable to the property, then a provision for impairment is recognized to the extent that net capitalized costs exceed the estimated fair value of the property. The Company determines the fair values of its natural gas and oil properties using a discounted cash flow model and proved and risk-adjusted probable reserves. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included in the cash flow model include management's outlook for natural gas and oil prices, future natural gas and oil production, production costs, capital expenditures, and the total proved and risk-adjusted probable natural gas and oil reserves expected to be recovered. Management's natural gas and oil price outlook is developed based on multiple third-party longer-term price forecasts as of each measurement date. The expected future net cash flows are discounted using an appropriate discount rate in determining a property's fair value. The natural gas and oil prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of an average price based on the first day of each month of the preceding year. Unproved properties are evaluated for impairment based upon the results of drilling, planned future drilling and the terms of the natural gas and oil leases. In the fourth quarter of 2025, the Company measured the fair value of its Eagle Ford shale proved property using Level 3 unobservable inputs at $1.2 million and as a result, the Company recognized an impairment charge of $7.8 million. Comstock also recognized an impairment charge to its Eagle Ford shale unproved property of $21.3 million. This

charge primarily resulted from diminished activity in the area on its leasehold acreage by operators, low oil prices and the Company's capital allocation strategy, which prioritizes higher-return projects in the Haynesville and Bossier shales.

The Company's estimates of undiscounted future net cash flows attributable to its natural gas and oil properties may change in the future. The primary factors that may affect estimates of future cash flows include future adjustments, both positive and negative, to proved and appropriate risk-adjusted probable natural gas and oil reserves, results of future drilling activities, future prices for natural gas and oil, and increases or decreases in production and capital costs. As a result of these changes, there may be future impairments in the carrying values of our natural gas and oil properties.

Other property and equipment consists primarily of pipelines and natural gas treating plants ("midstream assets"), computer equipment, furniture and fixtures, office buildings and an airplane which are depreciated over estimated useful lives ranging from three to 50 years on a straight-line basis. The following table presents the balances of other property and equipment and accumulated depreciation as of December 31, 2025 and 2024:

	As of December 31,
	2025			2024
	(in thousands)
Midstream assets	$	363,855		$	140,263
Accumulated depreciation		(4,914	)		(1,976	)
Net midstream assets		358,941			138,287
Other property and equipment		22,801			9,760
Accumulated depreciation		(1,982	)		(3,063	)
Net other property and equipment		20,819			6,697
Total	$	379,760		$	144,984

The Company also assesses the need for an impairment of its midstream assets when events or changes in circumstances, such as a significant decline in natural gas volumes gathered and processed, indicate that the Company may not be able to recover its capitalized costs. If impairment is indicated based on undiscounted expected future cash flows attributable to the pipelines and natural gas treating plants, then impairment is recognized to the extent the capitalized costs of the pipelines and natural gas treating plants exceed their estimated fair value. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included in the cash flow model include management's outlook for future natural gas gathering and processing volumes, operation costs and capital expenditures and the expected future net cash flows are discounted at an appropriate rate to determine fair value.

Goodwill

The Company had goodwill of $335.9 million as of December 31, 2025 and 2024. Goodwill represents the excess of purchase price over fair value of net tangible and identifiable intangible assets in a business combination.

The Company is required to conduct an annual review of goodwill for impairment and performs the assessment of goodwill on October 1st of each year. If the carrying value of goodwill exceeds the fair value, an impairment charge would be recorded for the difference between fair value and carrying value. The Company performed its assessment of goodwill as of October 1, 2025 and determined there was no indication of impairment.

Leases

The Company had right-of-use lease assets of $94.7 million and $73.8 million as of December 31, 2025 and 2024, respectively, related to its corporate office lease, certain office equipment, vehicles and drilling rigs with corresponding short-term and long-term liabilities. The value of the lease assets and liabilities are determined based upon discounted future minimum cash flows contained within each of the respective contracts, including the effects of early termination provisions. The Company determines if contracts contain a lease at inception of the contract. Since most of the Company's lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate at the commencement date of the lease. To the extent that contract terms representing a lease are identified, leases are identified as being either an operating lease or a finance-type lease. Comstock currently has no finance-type leases. Right-of-use lease assets represent the Company's right to use an underlying asset for the lease term and the related lease liabilities represent its obligation to make lease payments under the terms of the contracts. Short-term leases that have an initial term of one year or less are not capitalized; however,

amounts paid for those leases are included as part of its lease cost disclosures. Short-term lease costs exclude expenses related to leases with a lease term of one month or less.

Comstock contracts for a variety of equipment used in its natural gas and oil exploration and development operations. Contract terms for this equipment vary broadly, including the contract duration, pricing, scope of services included along with the equipment, cancellation terms, and rights of substitution, among others. The Company's drilling and completion operations routinely change due to changes in commodity prices, demand for natural gas and oil, and the overall operating and economic environment. Accordingly, Comstock manages the terms of its contracts for drilling rigs and completion equipment so as to allow for maximum flexibility in responding to these changing conditions. The Company's hydraulic fracturing fleet contracts are on terms of less than one year and include rights of substitution. As of December 31, 2025, the Company had four drilling rig lease contracts with a three-year term with options to extend the term by mutual agreement at mutually acceptable terms or terminate the contracts at any time without default by the lessor. The Company's other drilling rig contracts are presently either for periods of one year or less, or they are on terms that provide for cancellation with 30 or 45 days advance notice without a specified expiration date. The costs associated with drilling and completion operations are accounted for under the successful efforts method, which generally require that these costs be capitalized as part of our proved natural gas and oil properties on our balance sheet unless they are incurred on exploration wells that are unsuccessful, in which case they are charged to exploration expense. For drilling rig leases, the Company has elected the practical expedient to not separate lease components from non-lease components in the determination of their lease asset and liability values.

Lease costs recognized during the years ended December 31, 2025, 2024 and 2023 were as follows:

	Year Ended December 31,
	2025		2024		2023
	(In thousands)
Operating lease cost included in general and administrative expense	$	1,700	$	1,686	$	1,768
Operating lease cost included in lease operating expense		2,326		2,208		2,060
Operating lease cost included in proved natural gas and oil properties		48,321		34,644		56,755
Variable lease cost (drilling and completion costs included in proved natural gas and oil properties)		8,221		2,555		28,406
Short-term lease cost (drilling costs included in proved natural gas and oil properties)		31,160		26,276		89,163
	$	91,728	$	67,369	$	178,152

Cash payments for operating leases associated with right-of-use assets included in cash provided by operating activities were $4.0 million, $3.9 million and $3.8 million for the years ended December 31, 2025, 2024 and 2023, respectively. Cash payments for operating leases associated with right-of-use assets included in cash used for investing activities were $87.7 million, $63.5 million and $174.3 million for the years ended December 31, 2025, 2024 and 2023, respectively.

As of December 31, 2025 and 2024, the operating leases had a weighted average remaining term of 2.4 years and 2.0 years, respectively, and the weighted-average discount rate used to determine the present value of future operating lease payments was 6.8% and 7.3%, respectively.

As of December 31, 2025, expected future payments related to contracts that contain operating leases were as follows:

	(In thousands)
2026	$	51,848
2027		29,113
2028		14,470
2029		7,430
Total lease payments		102,861
Imputed interest		(8,232	)
Total lease liability	$	94,629

Accrued Expenses

Accrued expenses at December 31, 2025 and 2024 consist of the following:

	As of December 31,
	2025		2024
	(In thousands)
Accrued interest payable	$	64,042	$	64,041
Accrued drilling costs		36,148		34,493
Accrued transportation costs		28,304		28,031
Accrued employee compensation		14,926		14,076
Accrued income and other taxes		4,000		1,350
Accrued lease operating expenses		3,744		2,630
Other		2,084		1,552
	$	153,248	$	146,173

Reserve for Future Abandonment Costs

The Company's asset retirement obligations relate to future plugging and abandonment costs of its natural gas and oil properties and related facilities disposal. The Company records a liability in the period in which an asset retirement obligation is incurred, in an amount equal to the estimated fair value of the obligation that is capitalized. Thereafter, this liability is accreted up to the final retirement cost. Accretion of the discount is included as part of depreciation, depletion and amortization in the accompanying consolidated statements of operations.

The following table summarizes the changes in the Company's total estimated liability:

	Year Ended December 31,
	2025			2024
	(In thousands)
Reserve for future abandonment costs at beginning of the year	$	33,996		$	30,773
New wells placed on production		193			136
Changes in estimates and timing		484			1,497
Liabilities settled		(155	)		(40	)
Divestitures		(15,471	)		(157	)
Accretion expense		1,740			1,787
Reserve for future abandonment costs at end of the year	$	20,787		$	33,996

Stock-based Compensation

The Company has stock-based employee compensation plans under which stock awards, comprised primarily of restricted stock and performance share units ("PSUs"), are issued to employees and non-employee directors. The Company follows the fair value-based method in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period. Forfeitures are recognized as they occur.

Segment Reporting

The Company presently operates in one business segment, the exploration and production of North American natural gas and oil, primarily in the Haynesville and Bossier shale. This is consistent with the internal reporting provided to the Company's Chief Executive Officer, who is the chief operating decision maker ("CODM"). The CODM evaluates the performance of the Company and allocates resources based on consolidated financial information.

The measure of segment profit or loss used by the CODM is consolidated net income, which is provided in the accompanying consolidated statements of operations. The significant segment expenses regularly provided to the CODM are operating expenses and certain significant non-operating items, such as gains or losses from derivative financial instruments, interest expense and income tax expense. These items are also detailed in the accompanying consolidated statements of operations.

Derivative Financial Instruments and Hedging Activities

The Company accounts for derivative financial instruments (including derivative instruments embedded in other contracts) as either an asset or liability measured at its fair value. Changes in the fair value of derivatives are recognized currently in earnings and in net cash flows from operating activities. The fair value of derivative contracts that expire in less than one year are recognized as current assets or liabilities. Those that expire in more than one year are recognized as long-term assets or liabilities.

Major Purchasers

In 2025, the Company had three major purchasers of its natural gas production that accounted for 18%, 11% and 10% of its total natural gas and oil sales. In 2024, the Company had two major purchasers of its natural gas production that accounted for 21% and 12% of its total natural gas and oil sales. In 2023, the Company had three major purchasers of its natural gas production that accounted for 20%, 17% and 10% of its total natural gas and oil sales. The loss of any of these purchasers would not have a material adverse effect on the Company as there is an available market for its natural gas and oil production from other purchasers.

Revenue Recognition and Gas Balancing

Comstock produces natural gas and oil and reports revenues separately for each of these two primary products in its statements of operations. Revenues are recognized upon the transfer of produced volumes to the Company's customers, who take control of the volumes and receive all the benefits of ownership upon delivery at designated sales points. Costs incurred to gather or transport each product prior to the transfer of control are recognized as operating expenses.

Gas services revenues represent sales of natural gas purchased for resale from unaffiliated third parties and fees received for gathering and treating services provided by PGS to third parties. Revenues are recognized upon completion of the gathering and treating of contracted natural gas volumes and delivery of purchased natural gas volumes to the Company's customers. Profits and losses earned in the gathering and treating of natural gas produced by the Company's natural gas wells are eliminated in consolidation. Revenues and expenses associated with natural gas purchased for resale are presented on a gross basis in the Company's consolidated statements of operations as the Company acts as the principal in the transaction by assuming the risks and rewards from ownership of the natural gas volumes purchased and the responsibility to deliver the natural gas volumes to their sales point.

All natural gas and oil and gas services revenues are subject to contracts that have commercial substance, contain specific pricing terms, and define the enforceable rights and obligations of both parties. These contracts typically provide for cash settlement within 25 days following each production month and are cancellable upon 30 days' notice by either party for oil and vary for natural gas based upon the terms set out in the confirmations between both parties. Prices for sales of natural gas and oil are generally based upon terms that are common in the natural gas and oil industry, including index or spot prices, location and quality differentials, as well as market supply and demand conditions. As a result, prices for natural gas and oil routinely fluctuate based on changes in these factors. Prices for gathering and treating services are generally fixed in nature but can vary due to the quality of the gas being treated. Each unit of production (thousand cubic feet of natural gas and barrel of crude oil ) represents a separate performance obligation under the Company's contracts since each unit has economic benefit on its own and each is priced separately according to the terms of the contracts.

Comstock has elected to exclude all taxes from the measurement of transaction prices, and its natural gas and oil revenues are reported net of royalties and exclude revenue interests owned by others because the Company acts as an agent when selling natural gas and oil, on behalf of royalty owners and working interest owners. Natural gas and oil sales revenue is recorded in the month of production based on an estimate of the Company's share of volumes produced and prices realized. Gas services revenue is recorded in the month the services are performed and purchased gas is sold based on an estimate of natural gas volumes and contract prices. The Company recognizes any differences between estimates and actual amounts received in the month when payment is received. Historically, differences between estimated revenues and actual revenues received have not been significant. The amount of natural gas or oil sold may differ from the amount to which the Company is entitled based on its revenue interests in the properties. The Company did not have any significant imbalance positions at December 31, 2025 or 2024.

The Company has recognized accounts receivable of $203.5 million and $145.4 million as of December 31, 2025 and 2024, respectively, from customers for contracts where performance obligations have been satisfied and an unconditional right to consideration exists.

General and Administrative Expenses

General and administrative expenses are reported net of reimbursements of overhead costs that are received from working interest owners of the natural gas and oil properties operated by the Company of $30.5 million, $30.7 million and $29.7 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Income Taxes

The Company accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the tax consequences attributable to the future utilization of existing net operating loss and other carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that the change in rate is enacted.

Earnings Per Share

Unvested restricted stock containing non-forfeitable rights to dividends are included in common stock outstanding and are considered to be participating securities and included in the computation of basic and diluted earnings per share pursuant to the two-class method. At December 31, 2025 and 2024, 1,957,381 and 2,091,087 shares of restricted stock, respectively, are included in common stock outstanding as such shares have a non-forfeitable right to participate in any dividends that might be declared and have the right to vote on matters submitted to the Company's shareholders.

Weighted average shares of unvested restricted stock outstanding were as follows:

	Year Ended December 31,
	2025		2024		2023
	(in thousands)
Unvested restricted stock		2,145		2,187		1,248

PSUs represent the right to receive a number of shares of the Company's common stock that may range from zero to up to two times the number of PSUs granted on the award date based on the achievement of certain performance measures during a performance period. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective period, assuming that date was the end of the performance period. The treasury stock method is used to measure the dilutive effect of PSUs.

	Year Ended December 31,
	2025		2024		2023
	(In thousands, except per unit amounts)
Weighted average PSUs		1,479		1,272		662
Weighted average grant date fair value per unit	$	19.46	$	13.21	$	15.92

None of the Company's participating securities participate in losses and as such are excluded from the computation of basic earnings per share during periods of net losses. For the year ended December 31, 2023, the weighted average shares of unvested restricted stock and PSUs were excluded from the computation of earnings per share because to include them would have been antidilutive to the calculation.

Basic and diluted income (loss) per share were determined as follows:

	Year Ended December 31,
	2025			2024			2023
	(In thousands, except per share amounts)
Net income (loss)	$	420,203		$	(218,754	)	$	211,894
Income allocable to unvested restricted stock		(3,077	)		—			(327	)
Basic net income (loss)	$	417,126		$	(218,754	)	$	211,567
Income allocable to unvested restricted stock		3,077			—			—
Diluted net income (loss)	$	420,203		$	(218,754	)	$	211,567
Basic weighted average shares outstanding		290,779			287,010			276,806
Effect of dilutive securities:
PSUs		2,170			—			—
Restricted stock		1,182			—			—
Diluted weighted average shares outstanding		294,131			287,010			276,806
Basic income (loss) per share	$	1.43		$	(0.76	)	$	0.76
Diluted income (loss) per share	$	1.43		$	(0.76	)	$	0.76

Supplementary Information with Respect to the Consolidated Statements of Cash Flows

For the purpose of the consolidated statements of cash flows, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Cash payments made for interest and income taxes and other non-cash investing and financing activities were as follows:

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
Cash payments for:
Interest	$	210,820		$	190,016		$	161,009
Income tax payments (refunds):
Federal	$	(31,000	)	$	—		$	24,700
State (1)	$	—		$	37		$	5,083
Non-cash investing activities include:
Increase (decrease) in accrued capital expenditures	$	1,655		$	(1,383	)	$	(18,562	)
Liabilities assumed in exchange for right-of-use lease assets	$	67,179		$	34,668		$	195,402

(1)State tax payments were made in Texas and Louisiana.

Recent Accounting Pronouncements

In December 2023, the FASB issued ASU 2023-09 "Improvements to Income Tax Disclosures". ASU 2023-09 requires additional disclosures around effective tax rates and cash income taxes paid and is effective for public entities for annual periods beginning after December 15, 2024. ASU 2023-09 was implemented retrospectively in this 2025 Annual Report. See (9) Income Taxes for the impact on the Company's disclosures.

In November 2024, the FASB issued ASU 2024-03 "Disaggregation of Income Statement Expenses". ASU 2024-03 requires additional disclosure, in the notes to the financial statements, of specified information about certain costs and expenses, including purchases of inventory, employee compensation, depreciation, intangible asset amortization and depreciation, depletion and amortization recognized as part of oil and gas-producing activities included in each relevant expense caption. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027 and will not have an impact on the Company's reported results of operations, financial position or liquidity but will have an impact on the Company's financial statement disclosures. The Company is still evaluating the impact of this standard on its financial statement disclosures.

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Acquisitions and Dispositions of Natural Gas and Oil Properties

12 Months Ended

Dec. 31, 2025

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

Acquisitions and Dispositions of Natural Gas and Oil Properties

(2)Acquisitions and Dispositions of Natural Gas and Oil Properties

Acquisitions

During 2025, 2024 and 2023, the Company spent $54.7 million, $106.4 million and $98.6 million on its leasing program to acquire 17,856, 265,290 and 79,741 net acres, respectively, of undeveloped acreage in the Western Haynesville area through direct leasing or through acquisitions of undeveloped rights from third-party operators.

Dispositions

On December 2, 2025, the Company sold its interest in its Shelby Trough assets in East Texas for net proceeds of $417.2 million. The assets sold included 163 (74.8 net) producing wells and 36,000 net leasehold acres in Nacogdoches, San Augustine and Sabine counties in Texas. The Company realized a $292.3 million pre-tax gain on the sale of the unproved property. The producing wells and associated proved undeveloped reserves were valued at $120.5 million and recorded as a retirement of the Company's proved property. The Company's reserve for future abandonment costs was reduced by $1.7 million as a result of the divestiture.

On September 2, 2025, the Company sold its interest in its Cotton Valley assets in East Texas and North Louisiana for net proceeds of $15.2 million. The assets sold included the Company's interest in 883 (770.9 net) producing wells and 46 (27.3 net) inactive wells. The Company incurred a $1.5 million pre-tax loss on the divestiture and the Company's reserve for future abandonment costs was reduced by $13.8 million.

The Company sold its interests in certain non-operated natural gas and oil properties for $1.2 million and $41.3 million in 2024 and 2023, respectively.

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Natural Gas and Oil Producing Activities

12 Months Ended

Dec. 31, 2025

Oil and Gas Disclosure [Abstract]

Natural Gas and Oil Producing Activities

(3)Natural Gas and Oil Producing Activities

Set forth below is certain information regarding the aggregate capitalized costs of natural gas and oil properties and costs incurred by the Company for its natural gas and oil property acquisition, development and exploration activities:

Capitalized Costs

	As of December 31,
	2025			2024
	(In thousands)
Proved properties:
Leasehold costs	$	3,194,699		$	3,244,996
Wells and related equipment and facilities		5,790,270			4,809,254
Accumulated depreciation depletion and amortization		(3,540,300	)		(2,935,493	)
		5,444,669			5,118,757
Unproved properties		391,065			424,648
	$	5,835,734		$	5,543,405

Costs Incurred

	Year Ended December 31,
	2025		2024		2023
	(In thousands)
Property acquisitions:
Unproved property	$	54,670	$	106,386	$	98,553
Exploration and development:
Developmental leasehold costs		14,562		13,461		27,905
Exploratory drilling and completion costs		490,429		354,557		244,129
Development drilling and completion costs		517,375		503,550		974,664
Other development costs		32,493		30,500		25,130
Asset retirement obligations		444		1,594		(19	)
Total capital expenditures	$	1,109,973	$	1,010,048	$	1,370,362

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Long-term Debt

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

Long-term Debt

(4)Long-term Debt

Long-term debt is comprised of the following:

	As of December 31,
	2025			2024
	(In thousands)
Bank Credit Facility	$	260,000		$	415,000
6.75% Senior Notes due 2029:
Principal		1,623,880			1,623,880
Discount, net of amortization		(16,000	)		(20,201	)
5.875% Senior Notes due 2030:
Principal		965,000			965,000
Debt issuance costs, net of amortization		(23,814	)		(31,589	)
	$	2,809,066		$	2,952,090

The discount and premium on the 6.75% senior notes due 2029 are being amortized over its life using the effective interest rate method. Debt issuance costs are amortized over the lives of the bank credit facility and senior notes on a straight-line basis which approximates the amortization that would be calculated using an effective interest rate method.

The following table summarizes Comstock's principal amount of debt as of December 31, 2025 by year of maturity:

	2026		2027		2028		2029		2030		Total
	(In thousands)
Bank Credit Facility	$	—	$	260,000	$	—	$	—	$	—	$	260,000
6.75% Senior Notes due 2029		—		—		—		1,623,880		—		1,623,880
5.875% Senior Notes due 2030		—		—		—		—		965,000		965,000
	$	—	$	260,000	$	—	$	1,623,880	$	965,000	$	2,848,880

As of December 31, 2025, the Company had $260.0 million outstanding under a bank credit facility. Aggregate commitments under the bank credit facility are $1.5 billion, which matures on November 15, 2027. Borrowings under the bank credit facility are subject to a borrowing base, which is currently set at $2.0 billion. The borrowing base is re-determined on a semi-annual basis and upon the occurrence of certain other events. Borrowings under the bank credit facility are secured by substantially all of the assets of the Company and its restricted subsidiaries and bear interest at the Company's option, at either adjusted SOFR plus 2.25% to 3.25% or an alternate base rate plus 1.25% to 2.25%, in each case depending on the unused portion of the committed borrowing base. The Company also pays a commitment fee of 0.375% to 0.5%, which is dependent on the utilization of the borrowing base. The weighted average interest rate on borrowings under the bank credit facility were 6.76% and 7.32% during the years ended December 31, 2025 and 2024, respectively. The bank credit facility places certain restrictions upon the Company's and its restricted subsidiaries' ability to, among other things, incur additional indebtedness, pay cash dividends, repurchase common stock, make certain loans, investments and divestitures and redeem the senior notes. The only financial covenants are the maintenance of a leverage ratio of less than 3.5 to 1.0 and an adjusted current ratio of at least 1.0 to 1.0. The Company was in compliance with the covenants as of December 31, 2025.

In April 2024, the Company issued $400.0 million principal amount of 6.75% senior notes due 2029 (the "New 2029 Notes") in a private placement and received net proceeds after offering costs and deducting the initial purchasers' discounts of $365.2 million, which were used to pay down the outstanding borrowings on the Company's bank credit facility. The New 2029 Notes have substantially identical terms as the Company's $1,223.9 million aggregate principal amount of 6.75% senior notes due 2029, which mature on March 1, 2029 and accrue interest at a rate of 6.75% per annum, payable semi-annually on March 1 and September 1 of each year.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

(5)Commitments and Contingencies

The Company has drilling rig contracts with terms ranging from less than one year to three years. The service contracts with terms less than one year are generally for terms ranging from 30 to 45 days. The Company has four drilling rigs under contract with initial terms of three years that were put into service in 2023, 2024 and 2025. These four rigs qualify as operating leases and their corresponding lease obligation is reflected on the Company's balance sheet as of December 31, 2025. In 2025, the Company took delivery of one additional drilling rig with a one-year term, which has a remaining commitment of $3.2 million.

The Company has natural gas transportation and gathering contracts which extend to 2035. Commitments under these contracts are $85.4 million for 2026, $84.2 million for 2027, $79.3 million for 2028, $67.6 million for 2029, $27.7 million for 2030 and $58.9 million for 2031 through 2035. During the years ended December 31, 2025, 2024 and 2023, expenditures under these contracts totaled $86.3 million, $92.8 million and $96.5 million, respectively.

From time to time, the Company is involved in certain litigation that arise in the normal course of its operations. The Company records a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. The Company does not believe the resolution of these matters will have a material adverse effect on the Company's financial position, results of operations or cash flows and no material amounts are accrued relative to these matters at December 31, 2025 or 2024.

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Stockholders' Equity

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

Stockholders' Equity

(6)Stockholders' Equity

The authorized capital of the Company is 405,000,000 shares, of which 400,000,000 shares are common stock, $0.50 par value per share, and 5,000,000 are preferred stock, $10.00 par value per share.

In March 2024, the Company issued 12,500,000 shares of common stock in a private placement to two entities controlled by Comstock's majority stockholder, receiving proceeds of $100.5 million. Following the issuance, Comstock's majority stockholder's beneficial ownership in the Company increased to 67%. As a result of open market purchases made by the Company's majority stockholder during the third quarter of 2024, beneficial ownership increased to 71%.

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Stock-based Compensation

12 Months Ended

Dec. 31, 2025

Share-Based Payment Arrangement [Abstract]

Stock-based Compensation

(7)Stock-based Compensation

The Company grants restricted shares of common stock and PSUs to key employees and directors as part of their compensation. Grants are made pursuant to the Company's 2019 Long-term Incentive Plan (the "2019 Plan"), which was approved by the Company's shareholders on May 31, 2019. Future authorized equity awards available under the 2019 Plan as of December 31, 2025 were 9,451,616 shares of common stock.

Stock-based compensation expense is included in general and administrative expenses. During the years ended December 31, 2025, 2024 and 2023 the Company had $21.2 million, $15.3 million and $9.9 million, respectively, in stock-based compensation expense.

Restricted Stock

The fair value of restricted stock grants is amortized over the vesting period, generally one year to three years, using the straight-line method. The fair value of each restricted share on the date of grant is equal to the market price of a share of the Company's stock.

A summary of restricted stock activity is presented below:

	Number of Restricted Shares			Weighted Average Grant Price
Outstanding at January 1, 2025		2,091,087		$	9.25
Granted		840,783		$	18.18
Vested		(962,854	)	$	10.53
Forfeitures		(11,635	)	$	12.25
Outstanding at December 31, 2025		1,957,381		$	12.44

	Year Ended December 31,
	2025		2024		2023
	(In thousands, except per share data)
Fair value of vested restricted stock	$	22,126	$	7,536	$	4,241
Grant date weighted average fair value	$	18.18	$	7.78	$	9.80
Compensation expense recognized for restricted stock grants	$	12,507	$	9,884	$	6,519
Unrecognized compensation expense related to unvested shares	$	15,389
Expected recognition period	1.7 years

Performance Share Units

The Company issues PSUs as part of its long-term equity incentive compensation. PSU awards can result in the issuance of common stock to the holder if certain performance criteria are met during a performance period. The performance periods consist of three years. The performance criteria for the PSUs are based on the Company's annualized total stockholder return ("TSR") for the performance period as compared with the TSR of certain peer companies for the performance period. The costs associated with PSUs are recognized as general and administrative expense over the performance periods of the awards.

The fair value of PSUs was measured at the grant date using the Geometric Brownian Motion Model. Significant assumptions used in this simulation include the Company's expected volatility and a risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the vesting periods, as well as the volatilities for each of the Company's peers. Assumptions regarding volatility included the historical volatility of each company's stock and the implied volatilities of publicly traded stock options.

Significant assumptions used to value PSUs included:

	Year Ended December 31,
	2025			2024			2023
Risk free interest rate		3.9	%		4.4	%		4.2	%
Range of implied volatility:
Minimum		29	%		33	%		38	%
Maximum		55	%		58	%		68	%

A summary of PSU activity is presented below:

	Number of PSUs			Weighted Average Grant Price
Outstanding at January 1, 2025		1,290,755		$	13.21
Granted		529,670		$	36.77
Earned		(216,509	)	$	24.50
Outstanding at December 31, 2025		1,603,916		$	19.46

	Year Ended December 31,
	2025		2024		2023
	(In thousands, except per unit data)
Number of PSUs granted		530		706		391
Grant date fair value	$	19,476	$	6,837	$	4,906
Grant date fair value per unit	$	36.77	$	9.69	$	13.64
Compensation expense recognized for PSUs	$	8,716	$	5,375	$	3,348
Unrecognized compensation expense related to unvested shares	$	19,105
Expected recognition period	2.0 years

The fair value of PSUs is amortized over the vesting period of three years, using the straight-line method. The final number of shares of common stock issued may vary depending upon the performance multiplier and can result in the issuance of zero to 3,207,832 shares of common stock based on the achieved performance ranges from zero to two hundred percent.

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Retirement Plan

12 Months Ended

Dec. 31, 2025

Retirement Benefits [Abstract]

Retirement Plan

(8)Retirement Plan

The Company has a 401(k) profit sharing plan which covers all of its employees. At its discretion, Comstock may match the employees' contributions to the plan. Matching contributions to the plan were approximately $2.2 million, $2.1 million and $1.9 million for the years ended December 31, 2025, 2024 and 2023, respectively.

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Income Taxes

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Income Taxes

(9)Income Taxes

Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates.

The following is an analysis of the consolidated income tax provision (benefit):

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
Current - Federal	$	(3,449	)	$	(24,200	)	$	(4,570	)
Current - State		—			44			(4,636	)
Deferred - Federal		94,461			(88,001	)		52,520
Deferred - State		(2,479	)		(36,918	)		(8,219	)
	$	88,533		$	(149,075	)	$	35,095

In recording deferred income tax assets, the Company considers whether it is more likely than not that its deferred income tax assets will be realized in the future. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that all of its deferred tax assets will be realized. As a result, the Company established valuation allowances for its deferred tax assets and U.S. federal and state net operating loss carryforwards that are not expected to be utilized due to the uncertainty of generating taxable income prior to the expiration of the carryforward periods. The Company will continue to assess the valuation allowances against deferred tax assets considering all available information obtained in future periods.

The tax effects of significant temporary differences representing the net deferred tax liabilities were as follows:

	As of December 31,
	2025			2024
	(In thousands)
Deferred tax assets:
Interest expense limitation	$	209,968		$	207,053
Net operating loss carryforwards		212,344			79,628
Research and development and other tax credits		28,688			17,411
Asset retirement obligation		7,654			6,991
Unrealized hedging losses		1,956			16,701
Other		7,209			4,731
		467,819			332,515
Valuation allowance on deferred tax assets		(52,693	)		(53,687	)
Deferred tax assets		415,126			278,828
Deferred tax liabilities:
Property and equipment		(850,365	)		(621,561	)
Other		(1,859	)		(2,383	)
Deferred tax liabilities		(852,224	)		(623,944	)
Net deferred tax liability	$	(437,098	)	$	(345,116	)

The difference between the customary rate of 21.0% and the effective tax rate on income (losses) is due to the following:

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
Tax at statutory rate	$	106,834		$	(77,244	)	$	51,868
Tax effect of:
Tax credits:
Research and development		(10,334	)		(32,414	)		—
Other income tax credits		(3,024	)		(1,586	)		—
Valuation allowance on deferred tax assets		—			(779	)		(968	)
State income taxes, net of federal benefit (1)		(2,479	)		(36,884	)		(11,881	)
Other		(2,464	)		(168	)		(3,924	)
Total	$	88,533		$	(149,075	)	$	35,095

	Year Ended December 31,
	2025			2024			2023
Tax at statutory rate		21.0	%		21.0	%		21.0	%
Tax effect of:
Tax credits:
Research and development		(2.0	)		8.8			—
Other income tax credits		(0.6	)		0.4			—
Valuation allowance on deferred tax assets		—			0.2			(0.4	)
State income taxes, net of federal benefit (1)		(0.5	)		10.0			(4.8	)
Other		(0.5	)		0.1			(1.6	)
Effective tax rate		17.4	%		40.5	%		14.2	%

(1)State taxes in Texas and Louisiana contributed to the tax effect of this category.

At December 31, 2025, Comstock had the following carryforwards available to reduce future income taxes:

Types of Carryforward	Years of Expiration Carryforward	Amount
		(In thousands)
Net operating loss – U.S. federal	2026-2037	$	740,631
Net operating loss – U.S. federal	Unlimited	$	634,990
Net operating loss – State	Unlimited	$	1,807,981
Interest expense – U.S. federal	Unlimited	$	818,854
Interest expense – State	Unlimited	$	874,763
Research and development tax credits – U.S. federal	2045-2046	$	17,653
Research and development tax credits – State	2043-2046	$	11,035

The Company's ability to use net operating losses ("NOLs") generated before its ownership change in 2018 to reduce taxable income is limited under IRC Section 382. NOLs that exceed the Section 382 limitation in any year continue to be allowed as carry forwards until they expire and can be used to offset taxable income for years within the carryover period subject to the limitation in each year. U.S. federal NOLs incurred prior to 2018 generally have a 20-year life until they expire. NOLs generated in 2018 and after would be carried forward indefinitely. NOLs arising after the date of an ownership change are not affected by the 382 limitation. If the Company does not generate a sufficient level of taxable income prior to the expiration of the pre-2018 NOL carry-forward periods, then it will lose the ability to apply those NOLs as offsets to future taxable income. The Company estimates that all of the U.S. federal NOL carryforwards expiring in 2037 and $1.2 billion of the estimated state NOL carryforwards will expire unused.

The Company's federal income tax returns for the years subsequent to December 31, 2021 remain subject to examination, with the Company's 2022 and 2023 federal income tax returns currently under examination with the United States Internal Revenue Service. The Company's income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to December 31, 2022. The Company is also currently under examination with the state of Louisiana. In both the federal and state examinations, the Company believes that its significant filing positions will be sustained under audit or the final resolution will not have a material effect on the consolidated financial statements. Therefore, the Company has not established any significant reserves for uncertain tax positions.

In July 2025, the One Big Beautiful Bill Act ("OBBBA") was signed into United States federal law. The Company is benefiting from certain provisions contained in the OBBBA, including increased interest expense deductions and bonus depreciation and has included these benefits in its income tax provision for the year ended December 31, 2025.

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Derivative Financial Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments and Hedging Activities

(10)Derivative Financial Instruments and Hedging Activities

Comstock generally uses commodity price swaps, basis swaps and collars to hedge natural gas prices to manage price risk. Swaps are settled monthly based on differences between the prices specified in the instruments and the settlement prices of futures contracts. Generally, when the applicable settlement price is less than the price specified in the contract, Comstock receives a settlement from the counterparty based on the difference multiplied by the volume or amounts hedged. Similarly, when the applicable settlement price exceeds the price specified in the contract, Comstock pays the counterparty based on the difference. Comstock generally receives a settlement from the counterparty for floors when the applicable settlement price is less than the price specified in the contract, which is based on the difference multiplied by the volumes hedged. For collars, generally Comstock receives a settlement from the counterparty when the settlement price is below the floor and pays a settlement to the counterparty when the settlement price exceeds the cap. No settlement occurs when the settlement price falls between the floor and cap.

All of the Company's derivative financial instruments are used for risk management purposes and, by policy, none are held for trading or speculative purposes. Comstock minimizes credit risk to counterparties of its derivative financial instruments through formal credit policies, monitoring procedures, and diversification. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the assets securing its bank credit facility. None of the Company's derivative financial instruments involve payment or receipt of premiums. The Company classifies the fair value amounts of derivative financial instruments as net current or noncurrent assets or liabilities, whichever the case may be, by commodity contract. None of the Company's derivative contracts are designated as fair value or cash flow hedges. The Company recognizes cash settlements and changes in the fair value of its derivative financial instruments as a single component of other income (expenses) in the consolidated statements of operations and as separate components within cash flows from operating activities in the consolidated statements of cash flows. All of Comstock's natural gas derivative financial instruments are tied to the Henry Hub-NYMEX price index.

The Company had the following outstanding natural gas price derivative financial instruments at December 31, 2025:

	Future Production Period Ending December 31, 2026
Natural Gas Price Swap Contracts:
Volume (MMBtu)	116,800,000
Average Price per MMBtu	$3.51
Natural Gas Price Collar Contracts:
Volume (MMBtu)	167,900,000
Price per MMBtu:
Average Ceiling	$4.35
Average Floor	$3.50

Subsequent to December 31, 2025, the Company entered into natural gas collar contracts to hedge an additional 58.4 Bcf of 2027 natural gas production at an average ceiling price of $4.37 per MMBtu and an average floor price of $3.50 per MMBtu.

The aggregate fair value of the Company's derivative financial instruments is presented on a gross basis in the accompanying consolidated balance sheets. The classification of derivative financial instruments between assets and liabilities consists of the following:

		As of December 31,
Type	Consolidated Balance Sheet Location	2025		2024
		(in thousands)
Asset Derivative Financial Instruments:
Natural gas price derivatives	Derivative Financial Instruments – current	$	19,206	$	4,865
Liability Derivative Financial Instruments:
Natural gas price derivatives	Derivative Financial Instruments – current	$	27,636	$	8,940
Natural gas price derivatives	Derivative Financial Instruments – long-term	$	—	$	66,757

The Company recognizes cash settlements and changes in the fair value of its derivative financial instruments as a single component of other income (expenses). Gains and losses related to cash settlements and changes in the fair value recognized on the Company's derivative contracts recognized in the consolidated statement of operations were as follows:

	Year Ended December 31,
Gain/(Loss) Recognized in Earnings on Derivatives	2025		2024		2023
	(In thousands)
Natural gas price derivatives	$	82,537	$	10,196	$	187,639

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Related Party Transactions

12 Months Ended

Dec. 31, 2025

Related Party Transactions [Abstract]

Related Party Transactions

(11)Related Party Transactions

The Company operates natural gas and oil properties held by partnerships owned by its majority stockholder. Comstock charges the partnership for the costs incurred to drill, complete and produce the wells, as well as drilling and operating overhead fees. Comstock also provides natural gas marketing services to the partnerships in return for a fee equal to $0.02 per Mcf for natural gas marketed. The Company received $1.1 million, $1.1 million and $1.3 million in 2025, 2024 and 2023, respectively, for operating and marketing services provided to the partnership. The fees received for the services are reflected as a reduction of general and administrative expenses in the accompanying consolidated statements of operations.

In connection with the operation of the wells, the Company had a $3.6 million and $5.5 million receivable from the partnerships at December 31, 2025 and 2024, respectively.

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Subsequent Event

12 Months Ended

Dec. 31, 2025

Subsequent Events [Abstract]

Subsequent Event

(12)Subsequent Event

In January 2026, PGS entered into an agreement with Quantum under which PGS agreed to redeem all of the outstanding Class B Units of PGS in exchange for cash consideration of $440 million plus any accrued but unpaid distributions. The redemption is expected to be completed in the first half of 2026.

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Natural Gas and Oil Reserves Information (Unaudited)

12 Months Ended

Dec. 31, 2025

Extractive Industries [Abstract]

Natural Gas and Oil Reserves Information (Unaudited)

(13)Natural Gas and Oil Reserves Information (Unaudited)

Set forth below is a summary of the Company's proved natural gas and oil reserves:

	Year Ended December 31,
	2025						2024						2023
	Oil (MBbls)			Natural Gas (MMcf)			Oil (MBbls)			Natural Gas (MMcf)			Oil (MBbls)			Natural Gas (MMcf)
Proved Reserves:
Beginning of period		331			3,762,098			548			4,940,226			549			6,697,570
Revisions of previous estimates		(8	)		(29,753	)		(49	)		(1,180,157	)		(47	)		(1,803,628	)
Extensions and discoveries		—			3,737,848		—				531,258			116			570,751
Sales of minerals in place		(88	)		(15,870	)		(118	)		(1,681	)		—			—
Production		(37	)		(450,202	)		(50	)		(527,548	)		(70	)		(524,467	)
End of period		198			7,004,121			331			3,762,098			548			4,940,226
Proved Developed Reserves:
Beginning of period		331			2,731,812			548			2,734,175			480			2,531,462
End of period		198			2,840,638			331			2,731,812			548			2,734,175
Proved Undeveloped Reserves:
Beginning of period		—			1,030,286			—			2,206,051			69			4,166,108
End of period		—			4,163,483			—			1,030,286			—			2,206,051

Revisions of previous estimates. Revisions of previous estimates in 2024 and 2023 were primarily attributable to the significantly lower natural gas and oil prices that were used to determine proved reserves at the end of each year, which resulted in many of the Company's proved undeveloped locations being excluded from reserves since they did not generate an adequate return at those lower prices.

Extensions and discoveries. Extensions and discoveries for 2025, 2024 and 2023 were primarily comprised of proved reserve additions attributable to the wells drilled in the current year that were not classified as proved undeveloped in prior years and additional proved undeveloped locations that are planned to be drilled in the Company's current development plan that were not included in the prior year's reserve estimates. 2025 extensions and discoveries include proved undeveloped reserves that were excluded in 2024 and 2023 due to low natural gas prices.

Sales of minerals in place. During 2025, the Company sold certain natural gas and oil properties for $432.4 million. During 2024, the Company sold its interest in certain non-operated wells for $1.2 million.

The following table sets forth the standardized measure of discounted future net cash flows relating to proved reserves:

	As of December 31,
	2025			2024			2023
	(In thousands)
Cash Flows Relating to Proved Reserves:
Future Cash Flows	$	21,515,086		$	6,959,475		$	11,829,623
Future Costs:
Production		(5,544,264	)		(2,760,616	)		(4,019,901	)
Development and Abandonment		(4,797,691	)		(1,014,446	)		(2,285,853	)
Future Income Taxes		(1,347,093	)		(22,990	)		(341,677	)
Future Net Cash Flows		9,826,038			3,161,423			5,182,192
10% Discount Factor		(5,958,964	)		(1,563,229	)		(2,807,562	)
Standardized Measure of Discounted Future Net Cash Flows	$	3,867,074		$	1,598,194		$	2,374,630

The following table sets forth the changes in the standardized measure of discounted future net cash flows relating to proved reserves:

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
Standardized Measure, Beginning of Year	$	1,598,194		$	2,374,630		$	12,609,636
Net change in sales price, net of production costs		1,833,985			(1,478,758	)		(14,069,134	)
Development costs incurred during the year which were previously estimated		438,081			452,533			1,004,650
Revisions of quantity estimates		(45,201	)		(693,905	)		(1,583,876	)
Accretion of discount		160,277			250,170			1,551,704
Changes in future development and abandonment costs		(456,583	)		764,629			1,095,844
Changes in timing and other		176,754			94,058			(374,087	)
Extensions and discoveries		1,853,922			380,544			215,249
Sales of minerals in place		(1,747	)		(3,542	)		—
Sales, net of production costs		(1,098,926	)		(664,653	)		(855,699	)
Net changes in income taxes		(591,682	)		122,488			2,780,343
Standardized Measure, End of Year	$	3,867,074		$	1,598,194		$	2,374,630

The standardized measure of discounted future net cash flows was determined based on the simple average of the first of month market prices for natural gas and oil for each year. Prices used in determining quantities of natural gas and oil reserves and future cash inflows from natural gas and oil reserves represent prices received at the Company's sales point. These prices have been adjusted from posted or index prices for both location and quality differences. Prices used in determining natural gas and oil reserves quantities and cash flows are as follows:

	Year Ended December 31,
	2025		2024		2023
Crude Oil: $/barrel	$	61.98	$	71.07	$	72.63
Natural Gas: $/Mcf	$	3.07	$	1.84	$	2.39

Proved reserve information utilized in the preparation of the financial statements were based on estimates prepared by the Company's petroleum engineering staff in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board, which require that reserve reports be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual agreement. All of the Company's reserves are located onshore in the continental United States of America. The Company retained an independent petroleum consultant to conduct an audit of the Company's 2025 reserve estimates. The purpose of this audit was to provide additional assurance on the reasonableness of internally prepared reserve estimates. The engineering firm was selected for their geographic expertise and their historical experience.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing proved natural gas and oil reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not reflect the impact of future operations.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

Basis of Presentation and Principles of Consolidation

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of Comstock Resources, Inc., its wholly owned or controlled subsidiaries and a variable interest entity for which Comstock is the primary beneficiary (collectively, "Comstock" or the "Company"). All significant intercompany accounts and transactions have been eliminated in consolidation. The Company accounts for its undivided interest in natural gas and oil properties using the proportionate consolidation method, whereby its share of assets, liabilities, revenues and expenses are included in its financial statements. Net income (loss) and comprehensive income (loss) are the same in all periods presented. All adjustments are of a normal recurring nature unless otherwise disclosed. Certain amounts in prior period footnote disclosures have been reclassified to conform with current period presentation.

Comstock entered into an agreement with an affiliate of Quantum Capital Solutions ("Quantum"), in 2023 to form Pinnacle Gas Services, LLC ("PGS"), a midstream company in Comstock's Western Haynesville area. As part of the transaction, Comstock contributed a high-pressure pipeline and a natural gas treating plant. Quantum committed to contribute up to $300 million to fund future expansion costs. Quantum is entitled to a 12% dividend on its invested capital and 80% of any distributions from Pinnacle until an investment return hurdle is met. After the return hurdle is met, Quantum's ownership reduces to 30%. Comstock operates and manages PGS pursuant to a management services agreement. The Board of PGS is comprised of five members: three selected by Comstock and two selected by Quantum. PGS is considered a variable interest entity to Comstock.

Comstock has the power to direct the activities that most significantly impact the performance of PGS and has the obligation to absorb losses or right to receive benefits that could potentially be significant to PGS. Accordingly, Comstock is considered the primary beneficiary and consolidates the assets, liabilities and results of operations of PGS in the accompanying consolidated financial statements. PGS assets that cannot be used by Comstock include $363.9 million of other property and equipment as of December 31, 2025. Other PGS assets that cannot be used by Comstock and PGS liabilities for which creditors do not have recourse to Comstock's assets are not material to the Company's consolidated financial statements. The portion of PGS net income and stockholders' equity not attributable to Comstock's controlling interest are shown separately as noncontrolling interests in the accompanying consolidated statements of operations and statements of stockholders' equity.

Use of Estimates in the Preparation of Financial Statements

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from those estimates. Changes in the future estimated natural gas and oil reserves or the estimated future cash flows attributable to the reserves that are utilized for impairment analyses could have a significant impact on the future results of operations.

Concentration of Credit Risk, Accounts Receivable and Credit Losses

Concentration of Credit Risk, Accounts Receivable and Credit Losses

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and cash equivalents, accounts receivable and derivative financial instruments. The Company places its cash with high credit quality financial institutions and its derivative financial instruments with financial institutions and other firms that management believes have high credit ratings. Substantially all of the Company's accounts receivable are due from either purchasers of natural gas and oil or participants in natural gas and oil wells for which the Company serves as the operator. Generally, operators of natural gas and oil wells have the right to offset future revenues against unpaid charges related to operated wells. Natural gas and oil sales are generally unsecured. The Company's policy is to assess the collectability of its receivables based upon their age, the credit quality of the purchaser or participant and the potential for revenue offset. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectible. Accordingly, no allowance for doubtful accounts has been recorded for the years ended December 31, 2025, 2024 and 2023, respectively.

Fair Value Measurements

Fair Value Measurements

The Company holds or has held certain financial assets and liabilities that are required to be measured at fair value in the financial statements. These include cash and cash equivalents held in bank accounts and derivative financial instruments. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. A three-level hierarchy is followed for disclosure to show the extent and level of judgment used to estimate fair value measurements:

Level 1 — Inputs used to measure fair value are unadjusted quoted prices that are available in active markets for the identical assets or liabilities as of the reporting date.

Level 2 — Inputs used to measure fair value, other than quoted prices included in Level 1, are either directly or indirectly observable as of the reporting date through correlation with market data, including quoted prices for similar assets and liabilities in active markets and quoted prices in markets that are not active. Level 2 also includes assets and liabilities that are valued using models or other pricing methodologies that do not require significant judgment since the input assumptions used in the models, such as interest rates and volatility factors, are corroborated by readily observable data from actively quoted markets for substantially the full term of the financial instrument.

Level 3 — Inputs used to measure fair value are unobservable inputs that are supported by little or no market activity and reflect the use of significant management judgment. These values are generally determined using pricing models for which the assumptions utilize management's estimates of market participant assumptions.

The following presents the carrying amounts and the fair values of the Company's financial instruments as of December 31, 2025 and 2024:

	As of December 31,
	2025				2024
	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets:	(In thousands)
Commodity-based derivatives (1)	$	19,206	$	19,206	$	4,865	$	4,865
Liabilities:
Commodity-based derivatives (1)		27,636		27,636		75,697		75,697
Bank credit facility (2)		260,000		260,000		415,000		415,000
6.75% senior notes due 2029 (3)		1,607,880		1,603,582		1,603,679		1,581,283
5.875% senior notes due 2030 (3)		965,000		931,225		965,000		899,863

(1)The Company's commodity-based derivatives are classified as Level 2 and measured at fair value using a market approach using third party pricing services and other active markets or broker quotes that are readily available in the public markets.

(2)The carrying value of our floating rate debt outstanding approximates fair value.

(3)The fair value of the Company's fixed rate debt was based on quoted prices as of December 31, 2025 and 2024, respectively, a Level 1 measurement.

Property and Equipment

Property and Equipment

The Company follows the successful efforts method of accounting for its natural gas and oil properties. Costs incurred to acquire natural gas and oil leasehold are capitalized. Acquisition costs for proved natural gas and oil properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related natural gas and oil reserves. Equivalent units are determined by converting oil to natural gas at the ratio of one barrel of oil for six thousand cubic feet of natural gas. This conversion ratio is not based on the price of oil or natural gas, and there may be a significant difference in price between an equivalent volume of oil versus natural gas.

Exploratory well costs are initially capitalized as proved property in the consolidated balance sheets but charged to exploration expense if and when the well is determined not to have found commercial proved natural gas and oil reserves. The changes in capitalized exploratory well costs are as follows:

	Year Ended December 31,
	2025			2024
	(in thousands)
Beginning capitalized exploratory project costs	$	68,223		$	96,233
Additions to exploratory well costs pending the determination of proved reserves		490,429			354,557
Determined to have found proved reserves		(348,525	)		(382,567	)
Ending capitalized exploratory well costs	$	210,127		$	68,223

As of December 31, 2025 and 2024, the Company had no exploratory wells for which costs have been capitalized greater than one year.

The estimated future costs of dismantlement, restoration, plugging and abandonment of natural gas and oil properties and related facilities disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense. Exploration expense includes geological and geophysical expenses and delay rentals related to exploratory natural gas and oil properties, costs of unsuccessful exploratory drilling and impairments of unproved properties. As of December 31, 2025 and 2024, the unproved properties primarily relate to future drilling locations that were not included in proved undeveloped reserves. Most of these future drilling locations are located on acreage where the reservoir is known to be productive but have been excluded from proved reserves due to uncertainty on whether the wells would be drilled within the next five years as required by SEC rules in order to be included in proved reserves. The costs of unproved properties are transferred to proved natural gas and oil properties when they are either drilled or they are reflected in proved undeveloped reserves and amortized on an equivalent unit-of-production basis. Costs associated with unevaluated exploratory acreage are periodically assessed for impairment on a property by property basis, and any impairment in value is included in exploration expense. Exploratory drilling costs are initially capitalized as proved property but charged to expense if and when the well is determined not to have found commercial proved natural gas and oil reserves. Exploratory drilling costs are evaluated within a one-year period after the completion of drilling.

The Company assesses the need for an impairment of the costs capitalized for its proved natural gas and oil properties when events or changes in circumstances, such as a significant drop in commodity prices, indicate that the Company may not be able to recover its capitalized costs. If impairment is indicated based on undiscounted expected future cash flows attributable to the property, then a provision for impairment is recognized to the extent that net capitalized costs exceed the estimated fair value of the property. The Company determines the fair values of its natural gas and oil properties using a discounted cash flow model and proved and risk-adjusted probable reserves. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included in the cash flow model include management's outlook for natural gas and oil prices, future natural gas and oil production, production costs, capital expenditures, and the total proved and risk-adjusted probable natural gas and oil reserves expected to be recovered. Management's natural gas and oil price outlook is developed based on multiple third-party longer-term price forecasts as of each measurement date. The expected future net cash flows are discounted using an appropriate discount rate in determining a property's fair value. The natural gas and oil prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows because the standardized measure requires the use of an average price based on the first day of each month of the preceding year. Unproved properties are evaluated for impairment based upon the results of drilling, planned future drilling and the terms of the natural gas and oil leases. In the fourth quarter of 2025, the Company measured the fair value of its Eagle Ford shale proved property using Level 3 unobservable inputs at $1.2 million and as a result, the Company recognized an impairment charge of $7.8 million. Comstock also recognized an impairment charge to its Eagle Ford shale unproved property of $21.3 million. This

charge primarily resulted from diminished activity in the area on its leasehold acreage by operators, low oil prices and the Company's capital allocation strategy, which prioritizes higher-return projects in the Haynesville and Bossier shales.

The Company's estimates of undiscounted future net cash flows attributable to its natural gas and oil properties may change in the future. The primary factors that may affect estimates of future cash flows include future adjustments, both positive and negative, to proved and appropriate risk-adjusted probable natural gas and oil reserves, results of future drilling activities, future prices for natural gas and oil, and increases or decreases in production and capital costs. As a result of these changes, there may be future impairments in the carrying values of our natural gas and oil properties.

Other property and equipment consists primarily of pipelines and natural gas treating plants ("midstream assets"), computer equipment, furniture and fixtures, office buildings and an airplane which are depreciated over estimated useful lives ranging from three to 50 years on a straight-line basis. The following table presents the balances of other property and equipment and accumulated depreciation as of December 31, 2025 and 2024:

	As of December 31,
	2025			2024
	(in thousands)
Midstream assets	$	363,855		$	140,263
Accumulated depreciation		(4,914	)		(1,976	)
Net midstream assets		358,941			138,287
Other property and equipment		22,801			9,760
Accumulated depreciation		(1,982	)		(3,063	)
Net other property and equipment		20,819			6,697
Total	$	379,760		$	144,984

The Company also assesses the need for an impairment of its midstream assets when events or changes in circumstances, such as a significant decline in natural gas volumes gathered and processed, indicate that the Company may not be able to recover its capitalized costs. If impairment is indicated based on undiscounted expected future cash flows attributable to the pipelines and natural gas treating plants, then impairment is recognized to the extent the capitalized costs of the pipelines and natural gas treating plants exceed their estimated fair value. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included in the cash flow model include management's outlook for future natural gas gathering and processing volumes, operation costs and capital expenditures and the expected future net cash flows are discounted at an appropriate rate to determine fair value.

Goodwill

Goodwill

The Company had goodwill of $335.9 million as of December 31, 2025 and 2024. Goodwill represents the excess of purchase price over fair value of net tangible and identifiable intangible assets in a business combination.

The Company is required to conduct an annual review of goodwill for impairment and performs the assessment of goodwill on October 1st of each year. If the carrying value of goodwill exceeds the fair value, an impairment charge would be recorded for the difference between fair value and carrying value. The Company performed its assessment of goodwill as of October 1, 2025 and determined there was no indication of impairment.

Leases

Leases

The Company had right-of-use lease assets of $94.7 million and $73.8 million as of December 31, 2025 and 2024, respectively, related to its corporate office lease, certain office equipment, vehicles and drilling rigs with corresponding short-term and long-term liabilities. The value of the lease assets and liabilities are determined based upon discounted future minimum cash flows contained within each of the respective contracts, including the effects of early termination provisions. The Company determines if contracts contain a lease at inception of the contract. Since most of the Company's lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate at the commencement date of the lease. To the extent that contract terms representing a lease are identified, leases are identified as being either an operating lease or a finance-type lease. Comstock currently has no finance-type leases. Right-of-use lease assets represent the Company's right to use an underlying asset for the lease term and the related lease liabilities represent its obligation to make lease payments under the terms of the contracts. Short-term leases that have an initial term of one year or less are not capitalized; however,

amounts paid for those leases are included as part of its lease cost disclosures. Short-term lease costs exclude expenses related to leases with a lease term of one month or less.

Comstock contracts for a variety of equipment used in its natural gas and oil exploration and development operations. Contract terms for this equipment vary broadly, including the contract duration, pricing, scope of services included along with the equipment, cancellation terms, and rights of substitution, among others. The Company's drilling and completion operations routinely change due to changes in commodity prices, demand for natural gas and oil, and the overall operating and economic environment. Accordingly, Comstock manages the terms of its contracts for drilling rigs and completion equipment so as to allow for maximum flexibility in responding to these changing conditions. The Company's hydraulic fracturing fleet contracts are on terms of less than one year and include rights of substitution. As of December 31, 2025, the Company had four drilling rig lease contracts with a three-year term with options to extend the term by mutual agreement at mutually acceptable terms or terminate the contracts at any time without default by the lessor. The Company's other drilling rig contracts are presently either for periods of one year or less, or they are on terms that provide for cancellation with 30 or 45 days advance notice without a specified expiration date. The costs associated with drilling and completion operations are accounted for under the successful efforts method, which generally require that these costs be capitalized as part of our proved natural gas and oil properties on our balance sheet unless they are incurred on exploration wells that are unsuccessful, in which case they are charged to exploration expense. For drilling rig leases, the Company has elected the practical expedient to not separate lease components from non-lease components in the determination of their lease asset and liability values.

Lease costs recognized during the years ended December 31, 2025, 2024 and 2023 were as follows:

	Year Ended December 31,
	2025		2024		2023
	(In thousands)
Operating lease cost included in general and administrative expense	$	1,700	$	1,686	$	1,768
Operating lease cost included in lease operating expense		2,326		2,208		2,060
Operating lease cost included in proved natural gas and oil properties		48,321		34,644		56,755
Variable lease cost (drilling and completion costs included in proved natural gas and oil properties)		8,221		2,555		28,406
Short-term lease cost (drilling costs included in proved natural gas and oil properties)		31,160		26,276		89,163
	$	91,728	$	67,369	$	178,152

Cash payments for operating leases associated with right-of-use assets included in cash provided by operating activities were $4.0 million, $3.9 million and $3.8 million for the years ended December 31, 2025, 2024 and 2023, respectively. Cash payments for operating leases associated with right-of-use assets included in cash used for investing activities were $87.7 million, $63.5 million and $174.3 million for the years ended December 31, 2025, 2024 and 2023, respectively.

As of December 31, 2025 and 2024, the operating leases had a weighted average remaining term of 2.4 years and 2.0 years, respectively, and the weighted-average discount rate used to determine the present value of future operating lease payments was 6.8% and 7.3%, respectively.

As of December 31, 2025, expected future payments related to contracts that contain operating leases were as follows:

	(In thousands)
2026	$	51,848
2027		29,113
2028		14,470
2029		7,430
Total lease payments		102,861
Imputed interest		(8,232	)
Total lease liability	$	94,629

Reserve for Future Abandonment Costs

Reserve for Future Abandonment Costs

The Company's asset retirement obligations relate to future plugging and abandonment costs of its natural gas and oil properties and related facilities disposal. The Company records a liability in the period in which an asset retirement obligation is incurred, in an amount equal to the estimated fair value of the obligation that is capitalized. Thereafter, this liability is accreted up to the final retirement cost. Accretion of the discount is included as part of depreciation, depletion and amortization in the accompanying consolidated statements of operations.

The following table summarizes the changes in the Company's total estimated liability:

	Year Ended December 31,
	2025			2024
	(In thousands)
Reserve for future abandonment costs at beginning of the year	$	33,996		$	30,773
New wells placed on production		193			136
Changes in estimates and timing		484			1,497
Liabilities settled		(155	)		(40	)
Divestitures		(15,471	)		(157	)
Accretion expense		1,740			1,787
Reserve for future abandonment costs at end of the year	$	20,787		$	33,996

Stock-based Compensation

Stock-based Compensation

The Company has stock-based employee compensation plans under which stock awards, comprised primarily of restricted stock and performance share units ("PSUs"), are issued to employees and non-employee directors. The Company follows the fair value-based method in accounting for equity-based compensation. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized on a straight-line basis over the award vesting period. Forfeitures are recognized as they occur.

Segment Reporting

Segment Reporting

The Company presently operates in one business segment, the exploration and production of North American natural gas and oil, primarily in the Haynesville and Bossier shale. This is consistent with the internal reporting provided to the Company's Chief Executive Officer, who is the chief operating decision maker ("CODM"). The CODM evaluates the performance of the Company and allocates resources based on consolidated financial information.

The measure of segment profit or loss used by the CODM is consolidated net income, which is provided in the accompanying consolidated statements of operations. The significant segment expenses regularly provided to the CODM are operating expenses and certain significant non-operating items, such as gains or losses from derivative financial instruments, interest expense and income tax expense. These items are also detailed in the accompanying consolidated statements of operations.

Derivative Financial Instruments and Hedging Activities

Derivative Financial Instruments and Hedging Activities

The Company accounts for derivative financial instruments (including derivative instruments embedded in other contracts) as either an asset or liability measured at its fair value. Changes in the fair value of derivatives are recognized currently in earnings and in net cash flows from operating activities. The fair value of derivative contracts that expire in less than one year are recognized as current assets or liabilities. Those that expire in more than one year are recognized as long-term assets or liabilities.

Revenue Recognition and Gas Balancing

Revenue Recognition and Gas Balancing

Comstock produces natural gas and oil and reports revenues separately for each of these two primary products in its statements of operations. Revenues are recognized upon the transfer of produced volumes to the Company's customers, who take control of the volumes and receive all the benefits of ownership upon delivery at designated sales points. Costs incurred to gather or transport each product prior to the transfer of control are recognized as operating expenses.

Gas services revenues represent sales of natural gas purchased for resale from unaffiliated third parties and fees received for gathering and treating services provided by PGS to third parties. Revenues are recognized upon completion of the gathering and treating of contracted natural gas volumes and delivery of purchased natural gas volumes to the Company's customers. Profits and losses earned in the gathering and treating of natural gas produced by the Company's natural gas wells are eliminated in consolidation. Revenues and expenses associated with natural gas purchased for resale are presented on a gross basis in the Company's consolidated statements of operations as the Company acts as the principal in the transaction by assuming the risks and rewards from ownership of the natural gas volumes purchased and the responsibility to deliver the natural gas volumes to their sales point.

All natural gas and oil and gas services revenues are subject to contracts that have commercial substance, contain specific pricing terms, and define the enforceable rights and obligations of both parties. These contracts typically provide for cash settlement within 25 days following each production month and are cancellable upon 30 days' notice by either party for oil and vary for natural gas based upon the terms set out in the confirmations between both parties. Prices for sales of natural gas and oil are generally based upon terms that are common in the natural gas and oil industry, including index or spot prices, location and quality differentials, as well as market supply and demand conditions. As a result, prices for natural gas and oil routinely fluctuate based on changes in these factors. Prices for gathering and treating services are generally fixed in nature but can vary due to the quality of the gas being treated. Each unit of production (thousand cubic feet of natural gas and barrel of crude oil ) represents a separate performance obligation under the Company's contracts since each unit has economic benefit on its own and each is priced separately according to the terms of the contracts.

Comstock has elected to exclude all taxes from the measurement of transaction prices, and its natural gas and oil revenues are reported net of royalties and exclude revenue interests owned by others because the Company acts as an agent when selling natural gas and oil, on behalf of royalty owners and working interest owners. Natural gas and oil sales revenue is recorded in the month of production based on an estimate of the Company's share of volumes produced and prices realized. Gas services revenue is recorded in the month the services are performed and purchased gas is sold based on an estimate of natural gas volumes and contract prices. The Company recognizes any differences between estimates and actual amounts received in the month when payment is received. Historically, differences between estimated revenues and actual revenues received have not been significant. The amount of natural gas or oil sold may differ from the amount to which the Company is entitled based on its revenue interests in the properties. The Company did not have any significant imbalance positions at December 31, 2025 or 2024.

The Company has recognized accounts receivable of $203.5 million and $145.4 million as of December 31, 2025 and 2024, respectively, from customers for contracts where performance obligations have been satisfied and an unconditional right to consideration exists.

General and Administrative Expenses

General and Administrative Expenses

General and administrative expenses are reported net of reimbursements of overhead costs that are received from working interest owners of the natural gas and oil properties operated by the Company of $30.5 million, $30.7 million and $29.7 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Income Taxes

Income Taxes

The Company accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis, as well as the tax consequences attributable to the future utilization of existing net operating loss and other carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that the change in rate is enacted.

Earnings Per Share

Earnings Per Share

Unvested restricted stock containing non-forfeitable rights to dividends are included in common stock outstanding and are considered to be participating securities and included in the computation of basic and diluted earnings per share pursuant to the two-class method. At December 31, 2025 and 2024, 1,957,381 and 2,091,087 shares of restricted stock, respectively, are included in common stock outstanding as such shares have a non-forfeitable right to participate in any dividends that might be declared and have the right to vote on matters submitted to the Company's shareholders.

Weighted average shares of unvested restricted stock outstanding were as follows:

	Year Ended December 31,
	2025		2024		2023
	(in thousands)
Unvested restricted stock		2,145		2,187		1,248

PSUs represent the right to receive a number of shares of the Company's common stock that may range from zero to up to two times the number of PSUs granted on the award date based on the achievement of certain performance measures during a performance period. The number of potentially dilutive shares related to PSUs is based on the number of shares, if any, which would be issuable at the end of the respective period, assuming that date was the end of the performance period. The treasury stock method is used to measure the dilutive effect of PSUs.

	Year Ended December 31,
	2025		2024		2023
	(In thousands, except per unit amounts)
Weighted average PSUs		1,479		1,272		662
Weighted average grant date fair value per unit	$	19.46	$	13.21	$	15.92

None of the Company's participating securities participate in losses and as such are excluded from the computation of basic earnings per share during periods of net losses. For the year ended December 31, 2023, the weighted average shares of unvested restricted stock and PSUs were excluded from the computation of earnings per share because to include them would have been antidilutive to the calculation.

Basic and diluted income (loss) per share were determined as follows:

	Year Ended December 31,
	2025			2024			2023
	(In thousands, except per share amounts)
Net income (loss)	$	420,203		$	(218,754	)	$	211,894
Income allocable to unvested restricted stock		(3,077	)		—			(327	)
Basic net income (loss)	$	417,126		$	(218,754	)	$	211,567
Income allocable to unvested restricted stock		3,077			—			—
Diluted net income (loss)	$	420,203		$	(218,754	)	$	211,567
Basic weighted average shares outstanding		290,779			287,010			276,806
Effect of dilutive securities:
PSUs		2,170			—			—
Restricted stock		1,182			—			—
Diluted weighted average shares outstanding		294,131			287,010			276,806
Basic income (loss) per share	$	1.43		$	(0.76	)	$	0.76
Diluted income (loss) per share	$	1.43		$	(0.76	)	$	0.76

Supplementary Information With Respect to the Consolidated Statements of Cash Flows

Supplementary Information with Respect to the Consolidated Statements of Cash Flows

For the purpose of the consolidated statements of cash flows, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Cash payments made for interest and income taxes and other non-cash investing and financing activities were as follows:

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
Cash payments for:
Interest	$	210,820		$	190,016		$	161,009
Income tax payments (refunds):
Federal	$	(31,000	)	$	—		$	24,700
State (1)	$	—		$	37		$	5,083
Non-cash investing activities include:
Increase (decrease) in accrued capital expenditures	$	1,655		$	(1,383	)	$	(18,562	)
Liabilities assumed in exchange for right-of-use lease assets	$	67,179		$	34,668		$	195,402

(1)State tax payments were made in Texas and Louisiana.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

In December 2023, the FASB issued ASU 2023-09 "Improvements to Income Tax Disclosures". ASU 2023-09 requires additional disclosures around effective tax rates and cash income taxes paid and is effective for public entities for annual periods beginning after December 15, 2024. ASU 2023-09 was implemented retrospectively in this 2025 Annual Report. See (9) Income Taxes for the impact on the Company's disclosures.

In November 2024, the FASB issued ASU 2024-03 "Disaggregation of Income Statement Expenses". ASU 2024-03 requires additional disclosure, in the notes to the financial statements, of specified information about certain costs and expenses, including purchases of inventory, employee compensation, depreciation, intangible asset amortization and depreciation, depletion and amortization recognized as part of oil and gas-producing activities included in each relevant expense caption. ASU 2024-03 is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027 and will not have an impact on the Company's reported results of operations, financial position or liquidity but will have an impact on the Company's financial statement disclosures. The Company is still evaluating the impact of this standard on its financial statement disclosures.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2025

Accounting Policies [Abstract]

Schedule of Other Current Assets

Other current assets at December 31, 2025 and 2024 consist of the following:

	As of December 31,
	2025		2024
	(In thousands)
Prepaid drilling costs	$	53,134	$	58,136
Other receivables		9,929		4,140
Production tax refunds receivable		5,827		4,074
Income tax receivable		3,024		28,813
Prepaid expenses		2,968		2,361
Other		375		—
	$	75,257	$	97,524

Summary of Carrying Amounts and Fair Values of Financial Instruments

The following presents the carrying amounts and the fair values of the Company's financial instruments as of December 31, 2025 and 2024:

	As of December 31,
	2025				2024
	Carrying Value		Fair Value		Carrying Value		Fair Value
Assets:	(In thousands)
Commodity-based derivatives (1)	$	19,206	$	19,206	$	4,865	$	4,865
Liabilities:
Commodity-based derivatives (1)		27,636		27,636		75,697		75,697
Bank credit facility (2)		260,000		260,000		415,000		415,000
6.75% senior notes due 2029 (3)		1,607,880		1,603,582		1,603,679		1,581,283
5.875% senior notes due 2030 (3)		965,000		931,225		965,000		899,863

(1)The Company's commodity-based derivatives are classified as Level 2 and measured at fair value using a market approach using third party pricing services and other active markets or broker quotes that are readily available in the public markets.

(2)The carrying value of our floating rate debt outstanding approximates fair value.

(3)The fair value of the Company's fixed rate debt was based on quoted prices as of December 31, 2025 and 2024, respectively, a Level 1 measurement.

Capitalized Exploratory Well Costs

The changes in capitalized exploratory well costs are as follows:

	Year Ended December 31,
	2025			2024
	(in thousands)
Beginning capitalized exploratory project costs	$	68,223		$	96,233
Additions to exploratory well costs pending the determination of proved reserves		490,429			354,557
Determined to have found proved reserves		(348,525	)		(382,567	)
Ending capitalized exploratory well costs	$	210,127		$	68,223

Summary of Balances of Other Property and Equipment and Accumulated Depreciation

The following table presents the balances of other property and equipment and accumulated depreciation as of December 31, 2025 and 2024:

	As of December 31,
	2025			2024
	(in thousands)
Midstream assets	$	363,855		$	140,263
Accumulated depreciation		(4,914	)		(1,976	)
Net midstream assets		358,941			138,287
Other property and equipment		22,801			9,760
Accumulated depreciation		(1,982	)		(3,063	)
Net other property and equipment		20,819			6,697
Total	$	379,760		$	144,984

Summary of Lease Cost Recognized

Lease costs recognized during the years ended December 31, 2025, 2024 and 2023 were as follows:

	Year Ended December 31,
	2025		2024		2023
	(In thousands)
Operating lease cost included in general and administrative expense	$	1,700	$	1,686	$	1,768
Operating lease cost included in lease operating expense		2,326		2,208		2,060
Operating lease cost included in proved natural gas and oil properties		48,321		34,644		56,755
Variable lease cost (drilling and completion costs included in proved natural gas and oil properties)		8,221		2,555		28,406
Short-term lease cost (drilling costs included in proved natural gas and oil properties)		31,160		26,276		89,163
	$	91,728	$	67,369	$	178,152

Summary of Liabilities Under Contracts Contain Operating Leases

As of December 31, 2025, expected future payments related to contracts that contain operating leases were as follows:

	(In thousands)
2026	$	51,848
2027		29,113
2028		14,470
2029		7,430
Total lease payments		102,861
Imputed interest		(8,232	)
Total lease liability	$	94,629

Summary of Accrued Expenses

Accrued expenses at December 31, 2025 and 2024 consist of the following:

	As of December 31,
	2025		2024
	(In thousands)
Accrued interest payable	$	64,042	$	64,041
Accrued drilling costs		36,148		34,493
Accrued transportation costs		28,304		28,031
Accrued employee compensation		14,926		14,076
Accrued income and other taxes		4,000		1,350
Accrued lease operating expenses		3,744		2,630
Other		2,084		1,552
	$	153,248	$	146,173

Summary of Changes in Total Estimated Asset Retirement Obligation Liability

The following table summarizes the changes in the Company's total estimated liability:

	Year Ended December 31,
	2025			2024
	(In thousands)
Reserve for future abandonment costs at beginning of the year	$	33,996		$	30,773
New wells placed on production		193			136
Changes in estimates and timing		484			1,497
Liabilities settled		(155	)		(40	)
Divestitures		(15,471	)		(157	)
Accretion expense		1,740			1,787
Reserve for future abandonment costs at end of the year	$	20,787		$	33,996

Weighted Average Shares of Unvested Restricted Stock

Weighted average shares of unvested restricted stock outstanding were as follows:

	Year Ended December 31,
	2025		2024		2023
	(in thousands)
Unvested restricted stock		2,145		2,187		1,248

Common Stock and Convertible Stock Dilutive in Weighted average unearned PSUs outstanding

The treasury stock method is used to measure the dilutive effect of PSUs.

	Year Ended December 31,
	2025		2024		2023
	(In thousands, except per unit amounts)
Weighted average PSUs		1,479		1,272		662
Weighted average grant date fair value per unit	$	19.46	$	13.21	$	15.92

Schedule of Basic and Diluted Income (Loss) Per Share

Basic and diluted income (loss) per share were determined as follows:

	Year Ended December 31,
	2025			2024			2023
	(In thousands, except per share amounts)
Net income (loss)	$	420,203		$	(218,754	)	$	211,894
Income allocable to unvested restricted stock		(3,077	)		—			(327	)
Basic net income (loss)	$	417,126		$	(218,754	)	$	211,567
Income allocable to unvested restricted stock		3,077			—			—
Diluted net income (loss)	$	420,203		$	(218,754	)	$	211,567
Basic weighted average shares outstanding		290,779			287,010			276,806
Effect of dilutive securities:
PSUs		2,170			—			—
Restricted stock		1,182			—			—
Diluted weighted average shares outstanding		294,131			287,010			276,806
Basic income (loss) per share	$	1.43		$	(0.76	)	$	0.76
Diluted income (loss) per share	$	1.43		$	(0.76	)	$	0.76

Cash Payments Made for Interest and Income Taxes

Cash payments made for interest and income taxes and other non-cash investing and financing activities were as follows:

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
Cash payments for:
Interest	$	210,820		$	190,016		$	161,009
Income tax payments (refunds):
Federal	$	(31,000	)	$	—		$	24,700
State (1)	$	—		$	37		$	5,083
Non-cash investing activities include:
Increase (decrease) in accrued capital expenditures	$	1,655		$	(1,383	)	$	(18,562	)
Liabilities assumed in exchange for right-of-use lease assets	$	67,179		$	34,668		$	195,402

(1)State tax payments were made in Texas and Louisiana.

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Natural Gas and Oil Producing Activities (Tables)

12 Months Ended

Dec. 31, 2025

Oil and Gas Disclosure [Abstract]

Capitalized Costs Related to Oil and Natural Gas Property Acquisition Exploration and Development Activities

Set forth below is certain information regarding the aggregate capitalized costs of natural gas and oil properties and costs incurred by the Company for its natural gas and oil property acquisition, development and exploration activities:

Capitalized Costs

	As of December 31,
	2025			2024
	(In thousands)
Proved properties:
Leasehold costs	$	3,194,699		$	3,244,996
Wells and related equipment and facilities		5,790,270			4,809,254
Accumulated depreciation depletion and amortization		(3,540,300	)		(2,935,493	)
		5,444,669			5,118,757
Unproved properties		391,065			424,648
	$	5,835,734		$	5,543,405

Costs Incurred Related to Oil and Natural Gas Property Acquisition Exploration and Development Activities

Costs Incurred

	Year Ended December 31,
	2025		2024		2023
	(In thousands)
Property acquisitions:
Unproved property	$	54,670	$	106,386	$	98,553
Exploration and development:
Developmental leasehold costs		14,562		13,461		27,905
Exploratory drilling and completion costs		490,429		354,557		244,129
Development drilling and completion costs		517,375		503,550		974,664
Other development costs		32,493		30,500		25,130
Asset retirement obligations		444		1,594		(19	)
Total capital expenditures	$	1,109,973	$	1,010,048	$	1,370,362

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Long-term Debt (Tables)

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

Long-term Debt

Long-term debt is comprised of the following:

	As of December 31,
	2025			2024
	(In thousands)
Bank Credit Facility	$	260,000		$	415,000
6.75% Senior Notes due 2029:
Principal		1,623,880			1,623,880
Discount, net of amortization		(16,000	)		(20,201	)
5.875% Senior Notes due 2030:
Principal		965,000			965,000
Debt issuance costs, net of amortization		(23,814	)		(31,589	)
	$	2,809,066		$	2,952,090

Principal Amount of Debt by Year of Maturity

The following table summarizes Comstock's principal amount of debt as of December 31, 2025 by year of maturity:

	2026		2027		2028		2029		2030		Total
	(In thousands)
Bank Credit Facility	$	—	$	260,000	$	—	$	—	$	—	$	260,000
6.75% Senior Notes due 2029		—		—		—		1,623,880		—		1,623,880
5.875% Senior Notes due 2030		—		—		—		—		965,000		965,000
	$	—	$	260,000	$	—	$	1,623,880	$	965,000	$	2,848,880

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Stock-based Compensation (Tables)

12 Months Ended

Dec. 31, 2025

Share-Based Payment Arrangement [Abstract]

Summary of Restricted Stock Activity

A summary of restricted stock activity is presented below:

	Number of Restricted Shares			Weighted Average Grant Price
Outstanding at January 1, 2025		2,091,087		$	9.25
Granted		840,783		$	18.18
Vested		(962,854	)	$	10.53
Forfeitures		(11,635	)	$	12.25
Outstanding at December 31, 2025		1,957,381		$	12.44

	Year Ended December 31,
	2025		2024		2023
	(In thousands, except per share data)
Fair value of vested restricted stock	$	22,126	$	7,536	$	4,241
Grant date weighted average fair value	$	18.18	$	7.78	$	9.80
Compensation expense recognized for restricted stock grants	$	12,507	$	9,884	$	6,519
Unrecognized compensation expense related to unvested shares	$	15,389
Expected recognition period	1.7 years

Summary of Significant Assumptions Used to Value PSUs

Significant assumptions used to value PSUs included:

	Year Ended December 31,
	2025			2024			2023
Risk free interest rate		3.9	%		4.4	%		4.2	%
Range of implied volatility:
Minimum		29	%		33	%		38	%
Maximum		55	%		58	%		68	%

Summary of PSU Activity

A summary of PSU activity is presented below:

	Number of PSUs			Weighted Average Grant Price
Outstanding at January 1, 2025		1,290,755		$	13.21
Granted		529,670		$	36.77
Earned		(216,509	)	$	24.50
Outstanding at December 31, 2025		1,603,916		$	19.46

	Year Ended December 31,
	2025		2024		2023
	(In thousands, except per unit data)
Number of PSUs granted		530		706		391
Grant date fair value	$	19,476	$	6,837	$	4,906
Grant date fair value per unit	$	36.77	$	9.69	$	13.64
Compensation expense recognized for PSUs	$	8,716	$	5,375	$	3,348
Unrecognized compensation expense related to unvested shares	$	19,105
Expected recognition period	2.0 years

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Consolidated Income Tax Provision (Benefit)

The following is an analysis of the consolidated income tax provision (benefit):

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
Current - Federal	$	(3,449	)	$	(24,200	)	$	(4,570	)
Current - State		—			44			(4,636	)
Deferred - Federal		94,461			(88,001	)		52,520
Deferred - State		(2,479	)		(36,918	)		(8,219	)
	$	88,533		$	(149,075	)	$	35,095

Tax Effects of Significant Temporary Differences Representing Net Deferred Tax Asset and Liability

The tax effects of significant temporary differences representing the net deferred tax liabilities were as follows:

	As of December 31,
	2025			2024
	(In thousands)
Deferred tax assets:
Interest expense limitation	$	209,968		$	207,053
Net operating loss carryforwards		212,344			79,628
Research and development and other tax credits		28,688			17,411
Asset retirement obligation		7,654			6,991
Unrealized hedging losses		1,956			16,701
Other		7,209			4,731
		467,819			332,515
Valuation allowance on deferred tax assets		(52,693	)		(53,687	)
Deferred tax assets		415,126			278,828
Deferred tax liabilities:
Property and equipment		(850,365	)		(621,561	)
Other		(1,859	)		(2,383	)
Deferred tax liabilities		(852,224	)		(623,944	)
Net deferred tax liability	$	(437,098	)	$	(345,116	)

Difference Between Customary Rate and Effective Tax Rate on Income Before Income Taxes Due

The difference between the customary rate of 21.0% and the effective tax rate on income (losses) is due to the following:

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
Tax at statutory rate	$	106,834		$	(77,244	)	$	51,868
Tax effect of:
Tax credits:
Research and development		(10,334	)		(32,414	)		—
Other income tax credits		(3,024	)		(1,586	)		—
Valuation allowance on deferred tax assets		—			(779	)		(968	)
State income taxes, net of federal benefit (1)		(2,479	)		(36,884	)		(11,881	)
Other		(2,464	)		(168	)		(3,924	)
Total	$	88,533		$	(149,075	)	$	35,095

	Year Ended December 31,
	2025			2024			2023
Tax at statutory rate		21.0	%		21.0	%		21.0	%
Tax effect of:
Tax credits:
Research and development		(2.0	)		8.8			—
Other income tax credits		(0.6	)		0.4			—
Valuation allowance on deferred tax assets		—			0.2			(0.4	)
State income taxes, net of federal benefit (1)		(0.5	)		10.0			(4.8	)
Other		(0.5	)		0.1			(1.6	)
Effective tax rate		17.4	%		40.5	%		14.2	%

(1)State taxes in Texas and Louisiana contributed to the tax effect of this category.

Carryforwards Available to Reduce Future Income Taxes

At December 31, 2025, Comstock had the following carryforwards available to reduce future income taxes:

Types of Carryforward	Years of Expiration Carryforward	Amount
		(In thousands)
Net operating loss – U.S. federal	2026-2037	$	740,631
Net operating loss – U.S. federal	Unlimited	$	634,990
Net operating loss – State	Unlimited	$	1,807,981
Interest expense – U.S. federal	Unlimited	$	818,854
Interest expense – State	Unlimited	$	874,763
Research and development tax credits – U.S. federal	2045-2046	$	17,653
Research and development tax credits – State	2043-2046	$	11,035

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Derivative Financial Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Outstanding Natural Gas Price Derivative Financial Instruments

The Company had the following outstanding natural gas price derivative financial instruments at December 31, 2025:

	Future Production Period Ending December 31, 2026
Natural Gas Price Swap Contracts:
Volume (MMBtu)	116,800,000
Average Price per MMBtu	$3.51
Natural Gas Price Collar Contracts:
Volume (MMBtu)	167,900,000
Price per MMBtu:
Average Ceiling	$4.35
Average Floor	$3.50

Schedule of Derivative Instruments

The aggregate fair value of the Company's derivative financial instruments is presented on a gross basis in the accompanying consolidated balance sheets. The classification of derivative financial instruments between assets and liabilities consists of the following:

		As of December 31,
Type	Consolidated Balance Sheet Location	2025		2024
		(in thousands)
Asset Derivative Financial Instruments:
Natural gas price derivatives	Derivative Financial Instruments – current	$	19,206	$	4,865
Liability Derivative Financial Instruments:
Natural gas price derivatives	Derivative Financial Instruments – current	$	27,636	$	8,940
Natural gas price derivatives	Derivative Financial Instruments – long-term	$	—	$	66,757

Schedule of Gains and Losses from Derivative Financial Instruments

Gains and losses related to cash settlements and changes in the fair value recognized on the Company's derivative contracts recognized in the consolidated statement of operations were as follows:

	Year Ended December 31,
Gain/(Loss) Recognized in Earnings on Derivatives	2025		2024		2023
	(In thousands)
Natural gas price derivatives	$	82,537	$	10,196	$	187,639

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Natural Gas and Oil Reserves Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2025

Extractive Industries [Abstract]

Summary of Changes in Net Quantities of Proved Natural Gas and Oil Reserves

Set forth below is a summary of the Company's proved natural gas and oil reserves:

	Year Ended December 31,
	2025						2024						2023
	Oil (MBbls)			Natural Gas (MMcf)			Oil (MBbls)			Natural Gas (MMcf)			Oil (MBbls)			Natural Gas (MMcf)
Proved Reserves:
Beginning of period		331			3,762,098			548			4,940,226			549			6,697,570
Revisions of previous estimates		(8	)		(29,753	)		(49	)		(1,180,157	)		(47	)		(1,803,628	)
Extensions and discoveries		—			3,737,848		—				531,258			116			570,751
Sales of minerals in place		(88	)		(15,870	)		(118	)		(1,681	)		—			—
Production		(37	)		(450,202	)		(50	)		(527,548	)		(70	)		(524,467	)
End of period		198			7,004,121			331			3,762,098			548			4,940,226
Proved Developed Reserves:
Beginning of period		331			2,731,812			548			2,734,175			480			2,531,462
End of period		198			2,840,638			331			2,731,812			548			2,734,175
Proved Undeveloped Reserves:
Beginning of period		—			1,030,286			—			2,206,051			69			4,166,108
End of period		—			4,163,483			—			1,030,286			—			2,206,051

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following table sets forth the standardized measure of discounted future net cash flows relating to proved reserves:

	As of December 31,
	2025			2024			2023
	(In thousands)
Cash Flows Relating to Proved Reserves:
Future Cash Flows	$	21,515,086		$	6,959,475		$	11,829,623
Future Costs:
Production		(5,544,264	)		(2,760,616	)		(4,019,901	)
Development and Abandonment		(4,797,691	)		(1,014,446	)		(2,285,853	)
Future Income Taxes		(1,347,093	)		(22,990	)		(341,677	)
Future Net Cash Flows		9,826,038			3,161,423			5,182,192
10% Discount Factor		(5,958,964	)		(1,563,229	)		(2,807,562	)
Standardized Measure of Discounted Future Net Cash Flows	$	3,867,074		$	1,598,194		$	2,374,630

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following table sets forth the changes in the standardized measure of discounted future net cash flows relating to proved reserves:

	Year Ended December 31,
	2025			2024			2023
	(In thousands)
Standardized Measure, Beginning of Year	$	1,598,194		$	2,374,630		$	12,609,636
Net change in sales price, net of production costs		1,833,985			(1,478,758	)		(14,069,134	)
Development costs incurred during the year which were previously estimated		438,081			452,533			1,004,650
Revisions of quantity estimates		(45,201	)		(693,905	)		(1,583,876	)
Accretion of discount		160,277			250,170			1,551,704
Changes in future development and abandonment costs		(456,583	)		764,629			1,095,844
Changes in timing and other		176,754			94,058			(374,087	)
Extensions and discoveries		1,853,922			380,544			215,249
Sales of minerals in place		(1,747	)		(3,542	)		—
Sales, net of production costs		(1,098,926	)		(664,653	)		(855,699	)
Net changes in income taxes		(591,682	)		122,488			2,780,343
Standardized Measure, End of Year	$	3,867,074		$	1,598,194		$	2,374,630

Summary of Prices Used in Determining Natural Gas and Oil Reserves Quantities and Cash Flows

Prices used in determining natural gas and oil reserves quantities and cash flows are as follows:

	Year Ended December 31,
	2025		2024		2023
Crude Oil: $/barrel	$	61.98	$	71.07	$	72.63
Natural Gas: $/Mcf	$	3.07	$	1.84	$	2.39

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Summary of Significant Accounting Policies - Narrative (Detail)	3 Months Ended		12 Months Ended
	Dec. 31, 2025 USD ($) shares	Dec. 31, 2023 USD ($)	Dec. 31, 2025 USD ($) Contract Product Customer Segment shares	Dec. 31, 2024 USD ($) Customer shares	Dec. 31, 2023 USD ($) Customer
Operations And Summary Of Significant Accounting Policies [Line Items]
Allowance for doubtful accounts	$ 0	$ 0	$ 0	$ 0	$ 0
Impairment charge of proved and unproved property			29,071,000	0	0
Goodwill	335,897,000		335,897,000	335,897,000
Operating lease right-of-use assets	$ 94,733,000		94,733,000	73,777,000
Cash payments for operating leases associated with right-of-use assets			4,000,000	3,900,000	3,800,000
Cash payments for operating leases associated with ROU assets used for investing activities			$ 87,700,000	$ 63,500,000	$ 174,300,000
Operating lease, weighted average remaining lease term	2 years 4 months 24 days		2 years 4 months 24 days	2 years
Operating lease, weighted average discount rate, percent	6.80%		6.80%	7.30%
Number of operating segments | Segment			1
Segment Reporting, CODM, Individual Title and Position or Group Name [Extensible Enumeration]			srt:ChiefExecutiveOfficerMember
Segment Reporting, CODM, Profit (Loss) Measure, How Used, Description			The measure of segment profit or loss used by the CODM is consolidated net income, which is provided in the accompanying consolidated statements of operations.
Segment Reporting, Expense Information Used by CODM, Description			The significant segment expenses regularly provided to the CODM are operating expenses and certain significant non-operating items, such as gains or losses from derivative financial instruments, interest expense and income tax expense. These items are also detailed in the accompanying consolidated statements of operations.
Number of major customer of oil and gas sales | Customer			3	2	3
Number of primary products | Product			2
Contract cash settlement max days			25 days
Contract cancellable notice term			30 days
Natural gas and oil sales and gas services	$ 203,549,000		$ 203,549,000	$ 145,398,000
Reimbursements of overhead costs			$ 30,500,000	$ 30,700,000	$ 29,700,000
Performance multiplier, minimum			0.00%
Performance multiplier, maximum			200.00%
Change in Accounting Principle, Accounting Standards Update, Adopted [true false]	true		true
Accounting Standards Update [Extensible Enumeration]			us-gaap:AccountingStandardsUpdate202309RetrospectiveMember
Eagle Ford Shale Proved Property | Level 3
Operations And Summary Of Significant Accounting Policies [Line Items]
Property plant and equipment, fair value	$ 1,200,000		$ 1,200,000
Impairment charge of proved and unproved property	7,800,000
Eagle Ford Shale Unproved Property | Level 3
Operations And Summary Of Significant Accounting Policies [Line Items]
Impairment charge of proved and unproved property	$ 21,300,000
PGS
Operations And Summary Of Significant Accounting Policies [Line Items]
Initially committed to contribute		$ 300,000,000			$ 300,000,000
Dividend percentage		12.00%
Distributions percentage		80.00%
Reduction of ownership percentage		30.00%
Property, plant and equipment, additions			$ 363,900,000
Drilling Rig Contract [Member]
Operations And Summary Of Significant Accounting Policies [Line Items]
Operating lease, term of contract	3 years		3 years
Operating lease, number of contract | Contract			4
Restricted Stock
Operations And Summary Of Significant Accounting Policies [Line Items]
Shares of unvested restricted stock outstanding (in shares) | shares	1,957,381		1,957,381	2,091,087
Major Oil And Natural Gas Purchaser One | Revenue Benchmark | Customer Concentration Risk
Operations And Summary Of Significant Accounting Policies [Line Items]
Percentage of total revenue			18.00%	21.00%	20.00%
Major Oil And Natural Gas Purchaser Two | Revenue Benchmark | Customer Concentration Risk
Operations And Summary Of Significant Accounting Policies [Line Items]
Percentage of total revenue			11.00%	12.00%	17.00%
Major Oil And Natural Gas Purchaser Three | Revenue Benchmark | Customer Concentration Risk
Operations And Summary Of Significant Accounting Policies [Line Items]
Percentage of total revenue			10.00%		10.00%
Minimum
Operations And Summary Of Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	3 years		3 years
Prior advance notice period for cancellation of rig contracts			30 days
Maximum
Operations And Summary Of Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	50 years		50 years
Prior advance notice period for cancellation of rig contracts			45 days

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Summary of Significant Accounting Policies - Other Current Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Accounting Policies [Abstract]
Prepaid drilling costs	$ 53,134	$ 58,136
Other receivables	9,929	4,140
Production tax refunds receivable	5,827	4,074
Income tax receivable	3,024	28,813
Prepaid expenses	2,968	2,361
Other	375	0
Other current assets	$ 75,257	$ 97,524

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Summary of Significant Accounting Policies - Summary of Carrying Amounts and Fair Values of Financial Instruments (Detail) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024	Apr. 30, 2024
Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]
Derivative financial instruments	$ 19,206	$ 4,865
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Derivative financial instruments	$ 27,636	8,940
Interest rate on debt instrument			6.75%
6.75% Senior Notes due 2029:
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Interest rate on debt instrument	6.75%		6.75%
5.875% Senior Notes due 2030:
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Interest rate on debt instrument	5.875%
Bank Credit Facility:
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, carrying value	$ 260,000	415,000
Long-term debt, fair value	260,000	415,000
Level 2 and Level 3
Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]
Derivative financial instruments	19,206	4,865
Derivative financial asset, fair value	19,206	4,865
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Derivative financial instruments	27,636	75,697
Derivative financial liabilities, fair value	27,636	75,697
Level 1 | 6.75% Senior Notes due 2029:
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, carrying value	1,607,880	1,603,679
Long-term debt, fair value	1,603,582	1,581,283
Level 1 | 5.875% Senior Notes due 2030:
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, carrying value	965,000	965,000
Long-term debt, fair value	$ 931,225	$ 899,863

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Summary of Significant Accounting Policies - Exploratory Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Oil and Gas, Capitalized Exploratory Well Cost [Roll Forward]
Beginning capitalized exploratory project costs	$ 68,223	$ 96,233
Additions to exploratory well costs pending the determination of proved reserves	490,429	354,557
Determined to have found proved reserves	(348,525)	(382,567)
Ending capitalized exploratory well costs	$ 210,127	$ 68,223

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Summary of Significant Accounting Policies - Summary of Balances of Other Property and Equipment and Accumulated Depreciation (Details) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Property, Plant and Equipment [Line Items]
Accumulated depreciation	$ (3,547,196)	$ (2,940,532)
Net property and equipment	6,215,494	5,688,389
Other property and equipment	386,656	150,023
Total	379,760	144,984
Midstream Assets
Property, Plant and Equipment [Line Items]
Gross property and equipment	363,855	140,263
Accumulated depreciation	(4,914)	(1,976)
Net property and equipment	358,941	138,287
Other Property and Equipment
Property, Plant and Equipment [Line Items]
Other property and equipment	22,801	9,760
Accumulated depreciation	(1,982)	(3,063)
Net other property and equipment	$ 20,819	$ 6,697

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Summary of Significant Accounting Policies - Summary of Lease Cost Recognized (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Operations And Summary Of Significant Accounting Policies [Line Items]
Operating lease cost	$ 91,728	$ 67,369	$ 178,152
Operating lease cost included in general and administrative expense
Operations And Summary Of Significant Accounting Policies [Line Items]
Operating lease cost	1,700	1,686	1,768
Operating lease cost included in lease operating expense
Operations And Summary Of Significant Accounting Policies [Line Items]
Operating lease cost	2,326	2,208	2,060
Operating lease cost included in natural gas and oil properties
Operations And Summary Of Significant Accounting Policies [Line Items]
Operating lease cost	48,321	34,644	56,755
Variable lease cost (drilling and completion costs included in proved natural gas and oil properties)
Operations And Summary Of Significant Accounting Policies [Line Items]
Variable lease cost	8,221	2,555	28,406
Short-term lease cost (drilling costs included in proved natural gas and oil properties)
Operations And Summary Of Significant Accounting Policies [Line Items]
Operating lease cost	$ 31,160	$ 26,276	$ 89,163

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Summary of Significant Accounting Policies - Summary of Liabilities Under Contract Contain Operating Leases (Detail) $ in Thousands	Dec. 31, 2025 USD ($)
Accounting Policies [Abstract]
2026	$ 51,848
2027	29,113
2028	14,470
2029	7,430
Total lease payments	102,861
Imputed interest	(8,232)
Total lease liability	$ 94,629

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Summary of Significant Accounting Policies - Summary of Accrued Expenses (Detail) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Accounting Policies [Abstract]
Accrued interest payable	$ 64,042	$ 64,041
Accrued drilling costs	36,148	34,493
Accrued transportation costs	28,304	28,031
Accrued employee compensation	14,926	14,076
Accrued income and other taxes	4,000	1,350
Accrued lease operating expenses	3,744	2,630
Other	2,084	1,552
Total accrued expenses	$ 153,248	$ 146,173

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Summary of Significant Accounting Policies - Summary of Changes in Reserve for Future Abandonment Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Reserve for future abandonment costs at beginning of the year	$ 33,996	$ 30,773
New wells placed on production	193	136
Changes in estimates and timing	484	1,497
Liabilities settled	(155)	(40)
Divestitures	(15,471)	(157)
Accretion expense	1,740	1,787
Reserve for future abandonment costs at end of the year	$ 20,787	$ 33,996

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Summary of Significant Accounting Policies - Weighted Average Shares of Unvested Restricted Stock (Detail) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Accounting Policies [Abstract]
Unvested restricted stock (in shares)	2,145	2,187	1,248

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Summary of Significant Accounting Policies - Common Stock and Convertible Stock Dilutive in Computation of Earning Per Share (Detail) - Performance Share Units (PSU) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted average PSUs (in shares)	1,479	1,272	662
Weighted average grant date fair value per unit (in dollars per share)	$ 19.46	$ 13.21	$ 15.92

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Summary of Significant Accounting Policies - Basic and Diluted Income (Loss) Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net income (loss)	$ 420,203	$ (218,754)	$ 211,894
Income allocable to unvested restricted stock	(3,077)	0	(327)
Basic net income (loss)	417,126	(218,754)	211,567
Income allocable to unvested restricted stock	3,077	0	0
Diluted net income (loss)	$ 420,203	$ (218,754)	$ 211,567
Basic weighted average shares outstanding (in shares)	290,779	287,010	276,806
Effect of dilutive securities:
Diluted weighted average shares outstanding	294,131	287,010	276,806
Basic (in dollars per share)	$ 1.43	$ (0.76)	$ 0.76
Diluted (in dollars per share)	$ 1.43	$ (0.76)	$ 0.76
Performance Share Units (PSU)
Effect of dilutive securities:
Dilutive effect of share-based payment arrangements (in shares)	2,170	0	0
Restricted Stock
Effect of dilutive securities:
Dilutive effect of share-based payment arrangements (in shares)	1,182	0	0

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Summary of Significant Accounting Policies - Supplementary Information of Consolidated Statements of Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Cash payments for:
Interest	$ 210,820	$ 190,016	$ 161,009
Income tax payments (refunds):
Federal	(31,000)		24,700
State		37	5,083
Non-cash investing activities include:
Increase (decrease) in accrued capital expenditures	1,655	(1,383)	(18,562)
Liabilities assumed in exchange for right-of-use lease assets	$ 67,179	$ 34,668	$ 195,402

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Acquisitions and Dispositions of Natural Gas and Oil Properties - Additional Information (Detail) $ in Millions			12 Months Ended
	Dec. 02, 2025 USD ($) a Well Wells	Sep. 02, 2025 USD ($) Well Wells	Dec. 31, 2025 USD ($) a	Dec. 31, 2024 USD ($) a	Dec. 31, 2023 USD ($) a
Business Acquisition [Line Items]
Proceeds from the sales of assets			$ 432.4	$ 1.2
Disposal Group, Not Discontinued Operations
Business Acquisition [Line Items]
Proceeds from the sales of assets				$ 1.2	$ 41.3
Oil and Gas Properties | Western Haynesville
Business Acquisition [Line Items]
Oil and gas properties, net acres | a			17,856	265,290	79,741
Asset acquisition, consideration transferred			$ 54.7	$ 106.4	$ 98.6
Shelby Trough Assets | East Texas | Disposal Group, Not Discontinued Operations
Business Acquisition [Line Items]
Proceeds from the sales of assets	$ 417.2
Shelby Trough Assets | Nacogdoches, San Augustine and Sabine, Texas
Business Acquisition [Line Items]
Number of producing wells on sold property gross | Wells	163
Shelby Trough Assets | Nacogdoches, San Augustine and Sabine, Texas | Disposal Group, Not Discontinued Operations
Business Acquisition [Line Items]
Number of producing wells on sold properties net | Well	74.8
Net leasehold acres sold | a	36,000
Gain (loss) on sale of oil and gas properties	$ 292.3
Producing wells and proved undeveloped reserves	120.5
Reduction of reserve for future abandonment costs	$ 1.7
Cotton Valley Assets | East Texas and North Louisiana
Business Acquisition [Line Items]
Number of producing wells on sold property gross | Wells		883
Number of inactive wells on sold properties gross | Wells		46
Number of inactive wells on sold properties net | Well		27.3
Cotton Valley Assets | East Texas and North Louisiana | Disposal Group, Not Discontinued Operations
Business Acquisition [Line Items]
Proceeds from the sales of assets		$ 15.2
Number of producing wells on sold properties net | Well		770.9
Gain (loss) on sale of oil and gas properties		$ (1.5)
Reduction of reserve for future abandonment costs		$ 13.8

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Natural Gas and Oil Producing Activities - Capitalized Costs Related to Oil and Natural Gas Property Acquisition Exploration and Development Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Proved properties:
Leasehold costs	$ 3,194,699	$ 3,244,996
Wells and related equipment and facilities	5,790,270	4,809,254
Accumulated depreciation depletion and amortization	(3,540,300)	(2,935,493)
Proved properties	5,444,669	5,118,757
Unproved properties	391,065	424,648
Capitalized costs, oil and gas producing activities, net, total	$ 5,835,734	$ 5,543,405

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Natural Gas and Oil Producing Activities - Costs Incurred Related to Oil and Natural Gas Property Acquisition Exploration and Development Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Property acquisitions:
Unproved property	$ 54,670	$ 106,386	$ 98,553
Exploration and development:
Developmental leasehold costs	14,562	13,461	27,905
Exploratory drilling and completion costs	490,429	354,557	244,129
Development drilling and completion costs	517,375	503,550	974,664
Other development costs	32,493	30,500	25,130
Asset retirement obligations	444	1,594	(19)
Total capital expenditures	$ 1,109,973	$ 1,010,048	$ 1,370,362

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Long-term Debt - Long-term Debt (Detail) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024	Apr. 30, 2024
Debt Instrument [Line Items]
Principal	$ 2,848,880		$ 1,223,900
Debt issuance costs, net of amortization	(23,814)	$ (31,589)
Long-term debt	2,809,066	2,952,090
Interest rate on debt instrument			6.75%
Bank Credit Facility:
Debt Instrument [Line Items]
Principal	260,000	415,000
6.75% Senior Notes due 2029:
Debt Instrument [Line Items]
Principal	1,623,880	1,623,880
Discount, net of amortization	$ (16,000)	(20,201)
Interest rate on debt instrument	6.75%		6.75%
5.875% Senior Notes due 2030:
Debt Instrument [Line Items]
Principal	$ 965,000	$ 965,000
Interest rate on debt instrument	5.875%

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Long-term Debt - Principal Amount of Debt by Year of Maturity (Detail) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024	Apr. 30, 2024
Debt Instrument [Line Items]
2026	$ 0
2027	260,000
2028	0
2029	1,623,880
2030	965,000
Long-term debt, gross	2,848,880		$ 1,223,900
Interest rate on debt instrument			6.75%
Bank Credit Facility [Member]
Debt Instrument [Line Items]
2026	0
2027	260,000
2028	0
2029	0
2030	0
Long-term debt, gross	260,000
6.75% Senior Notes due 2029:
Debt Instrument [Line Items]
2026	0
2027	0
2028	0
2029	1,623,880
2030	0
Long-term debt, gross	$ 1,623,880	$ 1,623,880
Interest rate on debt instrument	6.75%		6.75%
5.875% Senior Notes due 2030:
Debt Instrument [Line Items]
2026	$ 0
2027	0
2028	0
2029	0
2030	965,000
Long-term debt, gross	$ 965,000	$ 965,000
Interest rate on debt instrument	5.875%

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Long-term Debt - Additional Information (Detail) - USD ($)	1 Months Ended	12 Months Ended
	Apr. 30, 2024	Dec. 31, 2025	Dec. 31, 2024
Debt Instrument [Line Items]
Interest rate on debt instrument	6.75%
Long-term debt, gross	$ 1,223,900,000	$ 2,848,880,000
Maturity date	Mar. 01, 2029
Frequency of periodic payment	semi-annually
Line of Credit
Debt Instrument [Line Items]
Borrowing base		1,500,000,000
Long-term debt, gross		$ 260,000,000	$ 415,000,000
Minimum | Line of Credit
Debt Instrument [Line Items]
Commitment fee on unused borrowing base		0.375%
Maximum | Line of Credit
Debt Instrument [Line Items]
Commitment fee on unused borrowing base		0.50%
Secured Overnight Financing Rate (SOFR) | Minimum | Line of Credit
Debt Instrument [Line Items]
Spread rate for interest rate on credit facility		2.25%
Secured Overnight Financing Rate (SOFR) | Maximum | Line of Credit
Debt Instrument [Line Items]
Spread rate for interest rate on credit facility		3.25%
Base Rate | Minimum | Line of Credit
Debt Instrument [Line Items]
Spread rate for interest rate on credit facility		1.25%
Base Rate | Maximum | Line of Credit
Debt Instrument [Line Items]
Spread rate for interest rate on credit facility		2.25%
Bank Credit Facility
Debt Instrument [Line Items]
Long-term debt, gross		$ 260,000,000
Bank Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Borrowing base		$ 2,000,000,000
Weighted average interest rate on borrowings		6.76%	7.32%
Leverage ratio		3.50%
Bank Credit Facility | Minimum | Revolving Credit Facility
Debt Instrument [Line Items]
Current ratio		1.00%
6.75% Senior Notes due 2029:
Debt Instrument [Line Items]
Interest rate on debt instrument	6.75%	6.75%
Long-term debt, gross		$ 1,623,880,000	$ 1,623,880,000
Debt instrument, face amount	$ 400,000,000
Proceeds of issued senior notes	$ 365,200,000

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Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Natural Gas Transportation and Gathering Contracts
Commitments And Contingencies [Line Items]
Other commitment, to be paid, year one	$ 85.4
Other commitment, to be paid, year two	84.2
Other commitment, to be paid, year three	79.3
Other commitment, to be paid, year four	67.6
Other commitment, to be paid, year five	27.7
Other commitment, to be paid, after year five	58.9
Purchase obligations expenditures	86.3	$ 92.8	$ 96.5
Drill and Rig Contracts
Commitments And Contingencies [Line Items]
Other commitment, to be paid, year one	$ 3.2
Other commitment, period	3 years	3 years	3 years
Drilling Rigs One
Commitments And Contingencies [Line Items]
Other commitment, period	1 year
Minimum | Drilling Rig Short Term Contracts
Commitments And Contingencies [Line Items]
Other commitment, period	30 days
Maximum | Drill and Rig Contracts
Commitments And Contingencies [Line Items]
Other commitment, period	3 years
Maximum | Drilling Rig Short Term Contracts
Commitments And Contingencies [Line Items]
Other commitment, period	45 days

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Stockholders' Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	12 Months Ended
	Mar. 31, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Sep. 30, 2024	Jul. 16, 2019
Investment Company, Change in Net Assets [Line Items]
Authorized capital stock (in shares)						405,000,000
Common stock, shares authorized (in shares)		400,000,000	400,000,000			400,000,000
Common stock, par value (in dollars per share)		$ 0.5	$ 0.5			$ 0.5
Preferred stock, authorized capital stock (in shares)						5,000,000
Preferred stock, par value (in dollars per share)						$ 10
Proceeds from issuance of common stock, net of issuance costs		$ 0	$ 100,450	$ 0
Majority Stockholder
Investment Company, Change in Net Assets [Line Items]
Common issued in private placement	12,500,000
Proceeds from issuance of common stock, net of issuance costs	$ 100,500
Common stock ownership percentage	67.00%				71.00%

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Stock-based Compensation - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Long-term incentive plan shares available for future awards of performance share units, restricted stock grants or other equity awards (in shares)	9,451,616
Stock-based compensation expense recognized	$ 21,222	$ 15,261	$ 9,867
Minimum final number of shares of common stock issuable based on performance multiplier (in shares)	0
Maximum final number of shares of common stock issuable based on performance multiplier (in shares)	3,207,832
Performance multiplier, minimum	0.00%
Performance multiplier, maximum	200.00%
Performance Share Units (PSU)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Amortized vesting period of awards	3 years
Minimum | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Amortized vesting period of awards	1 year
Maximum | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Amortized vesting period of awards	3 years
General and Administrative Expense
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense recognized	$ 21,200	$ 15,300	$ 9,900

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Stock-based Compensation - Summary of Restricted Stock Activity (Detail) - Restricted Stock - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Beginning balance, shares outstanding (in shares)	2,091,087
Number of shares, granted (in shares)	840,783
Vested (in shares)	(962,854)
Forfeitures (in shares)	(11,635)
Ending balance, shares outstanding (in shares)	1,957,381	2,091,087
Weighted-Average
Beginning balance, weighted average grant price, outstanding (in dollars per share)	$ 9.25
Granted (in dollars per share)	18.18	$ 7.78	$ 9.80
Vested (in dollars per share)	10.53
Forfeitures (in dollars per share)	12.25
Ending balance, weighted average grant price, outstanding (in dollars per share)	$ 12.44	$ 9.25
Fair value of vested restricted stock	$ 22,126	$ 7,536	$ 4,241
Grant date weighted average fair value (in dollars per share)	$ 18.18	$ 7.78	$ 9.80
Compensation expense recognized for restricted stock grants	$ 12,507	$ 9,884	$ 6,519
Unrecognized compensation expense related to unvested shares	$ 15,389
Expected recognition period	1 year 8 months 12 days

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Stock-based Compensation - Summary of Significant Assumptions Used to Value PSUs (Detail) - Performance Share Units (PSU)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk free interest rate	3.90%	4.40%	4.20%
Minimum	29.00%	33.00%	38.00%
Maximum	55.00%	58.00%	68.00%

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Stock-based Compensation - Summary of PSU Activity (Detail) (Potential Performance Shares (PSU)) - Performance Share Units (PSU)	12 Months Ended
	Dec. 31, 2025 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Beginning balance, shares outstanding (in shares) | shares	1,290,755
Granted (in shares) | shares	529,670
Earned (in shares) | shares	(216,509)
Ending balance, shares outstanding (in shares) | shares	1,603,916
Weighted-Average
Beginning balance, weighted average grant price, outstanding (in dollars per share) | $ / shares	$ 13.21
Granted (in dollars per share) | $ / shares	36.77
Earned (in dollars per share) | $ / shares	24.5
Ending balance, weighted average grant price, outstanding (in dollars per share) | $ / shares	$ 19.46

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Stock-based Compensation - Summary of PSU Activity (Detail) - Performance Share Units (PSU) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of PSUs granted (in shares)	530	706	391
Grant date fair value	$ 19,476	$ 6,837	$ 4,906
Grant date fair value (in dollars per share)	$ 36.77	$ 9.69	$ 13.64
Compensation expense recognized for PSUs	$ 8,716	$ 5,375	$ 3,348
Unrecognized compensation expense related to unvested shares	$ 19,105
Expected recognition period	2 years

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Retirement Plan - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Retirement Benefits [Abstract]
Matching contributions to the plan	$ 2.2	$ 2.1	$ 1.9

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Income Taxes - Consolidated Income Tax Provision (Benefit) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Current - Federal	$ (3,449)	$ (24,200)	$ (4,570)
Current - State	0	44	(4,636)
Deferred - Federal	94,461	(88,001)	52,520
Deferred - State	(2,479)	(36,918)	(8,219)
Total	$ 88,533	$ (149,075)	$ 35,095

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Income Taxes - Additional Information (Detail) - U.S. Federal $ in Billions	12 Months Ended
	Dec. 31, 2025 USD ($)
Income Taxes [Line Items]
Net operating loss expiration period	20 years
Net operating loss carryforwards expiring year	2037
Estimated NOL carryforwards to expire unused	$ 1.2

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Income Taxes - Tax Effects of Significant Temporary Differences Representing Net Deferred Tax Asset and Liability (Detail) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Deferred tax assets:
Interest expense limitation	$ 209,968	$ 207,053
Net operating loss carryforwards	212,344	79,628
Research and development and other tax credits	28,688	17,411
Asset retirement obligation	7,654	6,991
Unrealized hedging losses	1,956	16,701
Other	7,209	4,731
Noncurrent deferred tax assets	467,819	332,515
Valuation allowance on deferred tax assets	(52,693)	(53,687)
Deferred tax assets	415,126	278,828
Deferred tax liabilities:
Property and equipment	(850,365)	(621,561)
Other	(1,859)	(2,383)
Deferred tax liabilities	(852,224)	(623,944)
Net deferred tax liability	$ (437,098)	$ (345,116)

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Income Taxes - Income Tax Expense Benefit Income Tax Reconciliation (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Tax at statutory rate	$ 106,834	$ (77,244)	$ 51,868
Tax effect of:
Research and development, tax credits	(10,334)	(32,414)
Other income tax credits, tax credits	(3,024)	(1,586)
Valuation allowance on deferred tax assets		(779)	(968)
State income taxes, net of federal benefit	$ (2,479)	$ (36,884)	$ (11,881)
Effective Income Tax Rate Reconciliation, State and Local Jurisdiction, Contribution Greater than 50 Percent, Tax Effect [Extensible Enumeration]	stpr:LA, TEXAS	stpr:LA, TEXAS	stpr:LA, TEXAS
Other	$ (2,464)	$ (168)	$ (3,924)
Total	$ 88,533	$ (149,075)	$ 35,095

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Income Taxes - Difference Between Customary Rate and Effective Tax Rate on Income Before Income Taxes Due (Detail)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Tax at statutory rate	21.00%	21.00%	21.00%
Tax effect of:
Research and development, tax credits	(2.00%)	8.80%
Other income tax credits, tax credits	(0.60%)	0.40%
Valuation allowance on deferred tax assets		0.20%	(0.40%)
State income taxes, net of federal benefit	(0.50%)	10.00%	(4.80%)
Effective Income Tax Rate Reconciliation, State and Local Jurisdiction, Contribution Greater than 50 Percent, Tax Effect [Extensible Enumeration]	stpr:LA, TEXAS	stpr:LA, TEXAS	stpr:LA, TEXAS
Other	(0.50%)	0.10%	(1.60%)
Effective tax rate	17.40%	40.50%	14.20%

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Income Taxes - Carryforwards Available to Reduce Future Income Taxes (Detail) $ in Thousands	Dec. 31, 2025 USD ($)
U.S. Federal
Carryforward Available To Reduce Future Income Taxes [Line Items]
Net operating loss, tax credit carryforward, amount	$ 740,631
Research and development tax credits, tax credit carryforward, amount	17,653
State
Carryforward Available To Reduce Future Income Taxes [Line Items]
Net operating loss, tax credit carryforward, amount	1,807,981
Interest expense, tax credit carryforward, amount	874,763
Research and development tax credits, tax credit carryforward, amount	11,035
Years Of Expiration Carryforward Unlimited
Carryforward Available To Reduce Future Income Taxes [Line Items]
Net operating loss, tax credit carryforward, amount	634,990
Interest expense, tax credit carryforward, amount	$ 818,854

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Derivative Financial Instruments and Hedging Activities (Additional Information) (Details) - Natural Gas Price Collar Contracts - Subsequent Event	Feb. 18, 2026 Bcf $ / Mcf
Derivative [Line Items]
Derivative Average Ceiling Price	4.37
Derivative, Average Floor Price	3.5
Collar Contract for 2027
Derivative [Line Items]
Derivative Nonmonetary Notional Amount Additional Energy Measure | Bcf	58.4

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Derivative Financial Instruments and Hedging Activities - Schedule of Derivative Contracts Volume and Prices (Detail)	12 Months Ended
	Dec. 31, 2025 MMBTU $ / Mcf
Natural Gas Swap Contracts | Swap Contracts for 2026
Derivative [Line Items]
Volume (in MMBTU) | MMBTU	116,800,000
Average price (in dollars per MMBtu)	3.51
Natural Gas Price Collar Contracts | Collar Contracts for 2026
Derivative [Line Items]
Volume (in MMBTU) | MMBTU	167,900,000
Average ceiling (dollars per unit)	4.35
Average floor (dollars per MMBtu)	3.5

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Derivative Financial Instruments and Hedging Activities - Schedule of Derivative Instruments (Detail) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024
Asset Derivative Financial Instruments:
Derivative Financial Instruments - Current Asset	$ 19,206	$ 4,865
Liability Derivative Financial Instruments:
Derivative Financial Instruments - Current Liability	27,636	8,940
Derivative Financial Instruments - Long Term Liability	0	66,757
Natural Gas Price Derivatives - Derivative Financial Instruments - Current Asset
Asset Derivative Financial Instruments:
Derivative Financial Instruments - Current Asset	19,206	4,865
Natural Gas Price Derivatives - Derivative Financial Instruments - Current Liability
Liability Derivative Financial Instruments:
Derivative Financial Instruments - Current Liability	27,636	8,940
Natural Gas Price Derivatives - Derivative Financial Instruments - Long Term Liability
Liability Derivative Financial Instruments:
Derivative Financial Instruments - Long Term Liability	$ 0	$ 66,757

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Derivative Financial Instruments and Hedging Activities - Schedule of Gains and Losses from Derivative Financial Instruments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Derivative [Line Items]
Gain/(Loss) Recognized in Earnings on Derivatives	$ 82,537	$ 10,196	$ 187,639
Natural gas price derivatives
Derivative [Line Items]
Gain/(Loss) Recognized in Earnings on Derivatives	$ 82,537	$ 10,196	$ 187,639

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Related Party Transactions - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2025 USD ($) $ / Mcf	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Related Party Transaction [Line Items]
Revenues	$ 2,220,289	$ 1,254,455	$ 1,565,234
From affiliates	$ 3,596	5,492
Partnerships owned by majority stockholder
Related Party Transaction [Line Items]
Related party revenue, fee (in USD per Mcf) | $ / Mcf	0.02
From affiliates	$ 3,600	5,500
Partnerships owned by majority stockholder | Partnership costs to drill and operating wells and overhead fees
Related Party Transaction [Line Items]
Revenues	$ 1,100	$ 1,100	$ 1,300

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Subsequent Event - Additional Information (Details) $ in Millions	1 Months Ended
	Jan. 31, 2026 USD ($)
PGS | Class B Units | Subsequent Event
Subsequent Event [Line Items]
Redemption of class B units for cash consideration	$ 440

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Natural Gas and Oil Reserves Information (Unaudited) - Summary of Changes in Net Quantities of Natural Gas and Crude Oil Reserves (Detail)	12 Months Ended
	Dec. 31, 2025 MMcf MMBbls	Dec. 31, 2024 MMBbls MMcf	Dec. 31, 2023 MMcf MMBbls	Dec. 31, 2022 MMBbls MMcf
Oil (MBbls)
Proved Reserves:
Beginning of period | MMBbls	331	548	549
Revisions of previous estimates | MMBbls	(8)	(49)	(47)
Extensions and discoveries | MMBbls	0	0	116
Sales of minerals in place | MMBbls	(88)	(118)	0
Production | MMBbls	(37)	(50)	(70)
End of period | MMBbls	198	331	548
Proved Developed Reserves:
Proved developed reserves | MMBbls	198	331	548	480
Proved Undeveloped Reserves:
Proved undeveloped reserves | MMBbls	0	0	0	69
Natural Gas (MMcf)
Proved Reserves:
Beginning of period | MMcf	3,762,098	4,940,226	6,697,570
Revisions of previous estimates | MMcf	(29,753)	(1,180,157)	(1,803,628)
Extensions and discoveries | MMcf	3,737,848	531,258	570,751
Sales of minerals in place | MMcf	(15,870)	(1,681)	0
Production | MMcf	(450,202)	(527,548)	(524,467)
End of period | MMcf	7,004,121	3,762,098	4,940,226
Proved Developed Reserves:
Proved developed reserves | MMcf	2,840,638	2,731,812	2,734,175	2,531,462
Proved Undeveloped Reserves:
Proved undeveloped reserves | MMcf	4,163,483	1,030,286	2,206,051	4,166,108

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Natural Gas and Oil Reserves Information (Unaudited) - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Extractive Industries [Abstract]
Sales of non-operated wells	$ 432.4	$ 1.2

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Natural Gas and Oil Reserves Information (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves (Detail) - USD ($) $ in Thousands	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Cash Flows Relating to Proved Reserves:
Future Cash Flows	$ 21,515,086	$ 6,959,475	$ 11,829,623
Future Costs:
Production	(5,544,264)	(2,760,616)	(4,019,901)
Development and Abandonment	(4,797,691)	(1,014,446)	(2,285,853)
Future Income Taxes	(1,347,093)	(22,990)	(341,677)
Future Net Cash Flows	9,826,038	3,161,423	5,182,192
10% Discount Factor	(5,958,964)	(1,563,229)	(2,807,562)
Standardized Measure of Discounted Future Net Cash Flows	$ 3,867,074	$ 1,598,194	$ 2,374,630	$ 12,609,636

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Natural Gas and Oil Reserves Information (Unaudited) - Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized Measure, Beginning of Year	$ 1,598,194	$ 2,374,630	$ 12,609,636
Net change in sales price, net of production costs	1,833,985	(1,478,758)	(14,069,134)
Development costs incurred during the year which were previously estimated	438,081	452,533	1,004,650
Revisions of quantity estimates	(45,201)	(693,905)	(1,583,876)
Accretion of discount	160,277	250,170	1,551,704
Changes in future development and abandonment costs	(456,583)	764,629	1,095,844
Changes in timing and other	176,754	94,058	(374,087)
Extensions and discoveries	1,853,922	380,544	215,249
Sales of minerals in place	(1,747)	(3,542)	0
Sales, net of production costs	(1,098,926)	(664,653)	(855,699)
Net changes in income taxes	(591,682)	122,488	2,780,343
Standardized Measure, End of Year	$ 3,867,074	$ 1,598,194	$ 2,374,630

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Natural Gas and Oil Reserves Information (Unaudited) - Summary of Prices Used in Determining Natural Gas and Oiil Reserves Quantities and Cash Flows (Detail)	12 Months Ended
	Dec. 31, 2025 $ / Mcf $ / bbl	Dec. 31, 2024 $ / Mcf $ / bbl	Dec. 31, 2023 $ / bbl $ / Mcf
Oil and Condensate [Member]
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Average sales prices | $ / bbl	61.98	71.07	72.63
Natural Gas Per Thousand Cubic Feet
Oil and Gas, Average Sale Price and Production Cost Per Unit [Line Items]
Average sales prices | $ / Mcf	3.07	1.84	2.39