Comstock Resources Inc: Form 10-K for the period ended Dec 31, 2025

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.
• 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.
• 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.

Natural Gas and Oil Reserves

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

(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:

(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.

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

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:

10

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

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:

(in millions)

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)

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.

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:

(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 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:

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:

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.

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:

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.

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

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.

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.

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 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 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.

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, 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.

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.

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 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 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 (http://www.sec.gov). We also make available free of charge on our website (www.comstockresources.com (http://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.

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).

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.

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;
• 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:

• 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;
• 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.

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 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.

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.

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.

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.

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:

(In thousands except per unit amounts)

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:

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 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.

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:

(in thousands)

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.

Our capital expenditures are summarized in the following table:

(in thousands)

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.

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.

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.

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.

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.

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