What changed in this filing

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Item 1. Business

2026-02-19 compared with 2025-02-21 · 190 added, 171 removed, 666 unchanged (35% of the section changed)

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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 under the symbol "CRK".

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.

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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 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.

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 and the petrochemical industry due to its geographic proximity.

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 has been substantially delineated since commercial operations started in 2008 and the consistent and successful results of our first eighteen wells in our Western Haynesville area indicate substantial upside to our extension of the Haynesville and Bossier shale plays.

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.

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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 eighteen successful wells turned to sales through the end of 2024.

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 .

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Our management and operating teams are instrumental in developing and optimizing some of the most effective completion techniques in the Haynesville and Bossier shales and such completion techniques have resulted in a substantial improvement in initial production rates and recoverable reserves, which has resulted in some of the highest single well rates of return when compared to results from other natural gas basins in North America.

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• 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

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producers in other regions.

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, 2024, the Pinnacle system included a gas treating plant in Bethel, Texas and 246 miles of high-pressure pipelines.

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 five years we have acquired a total of approximately 517,624 net undeveloped acres prospective for the Haynesville and Bossier shales.

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 $902.1 million on exploration and development activities in 2024, almost exclusively in the Haynesville and Bossier shale.

We spent $858.1 million on drilling and completion activities and an additional $44.0 million on other development costs.

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.

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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

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We have an extensive inventory of de-risked, high-return drilling locations prospective for the Haynesville and Bossier shales.

As of December 31, 2024, we have identified 2,658 drilling locations (1,350 net to us) which gives us decades of drilling activity.

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.

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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 is 9,603 feet.

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 expand our acreage holdings and delineate our emerging Western Haynesville and Bossier shale plays in East Texas.

Our first seven exploratory wells turned to sales in 2022 and 2023 have been successful.

In 2024, we turned an additional eleven Haynesville and Bossier shale wells in this play to sales.

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.

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We also plan to continue to acquire prospective acreage with an active leasing program.

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• Maintain disciplined financial strategy.

Given the current natural gas price outlook, we intend to maintain a conservative operating plan in 2025 with the primary goal of protecting our balance sheet.

Our current plan is to fund our exploration and development activity with operating cash flow that we generate.

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.

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.

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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

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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.

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.

Beginning in 2025, we also have access to gas storage in Western Haynesville that will allow us greater operational flexibility and take advantage of seasonal natural gas pricing.

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 2024, we added 265,290 net acres to our Western Haynesville area through acquisitions and an active 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.

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.

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After the return hurdles are met, Quantum's ownership reduces to 30%.

In 2024 and 2023, Quantum contributed $60.5 million and $24.0 million, respectively, to fund Pinnacle's capital expansion.

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 2024, 2023 and 2022 we sold our working interest in certain non-strategic, non-operated properties for $1.2 million, $41.3 million and $4.1 million, respectively.

In 2025, we sold our Shelby Trough assets in Nacogdoches, San Augustine and Sabine counties of Texas and our Cotton Valley assets in East Texas and North Louisiana for aggregate net proceeds after selling expenses of $432.4 million.

In 2024 and 2023, we sold our working interest in certain non-strategic, non-operated properties for $1.2 million and $41.3 million, respectively.

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Natural Gas and Oil Reserves

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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%.

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

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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.

All of our proved reserves are in the Haynesville and Bossier shales in North Louisiana and East Texas.

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.

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These prices have been adjusted from index prices for both location and quality differences.

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

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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 (including Western Haynesville and Bossier) properties where our 2025 drilling program is focused.

Our natural gas and oil proved undeveloped reserves decreased by 1.2 Tcf during 2024 due to low natural gas prices used to determine the proved

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reserves as 83 proved undeveloped reserve locations previously included in our proved reserves no longer generate an economic return using the prescribed SEC natural gas and oil prices.

During 2024, 21 proved undeveloped locations included in our 2023 reserves were converted to proved developed reserves.

As of December 31, 2023, our proved undeveloped reserves were comprised of 2.2 Tcf of natural gas, all of which were associated with our Haynesville and Bossier shales (including Western Haynesville and Bossier) properties.

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.

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Ending Balance

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

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(in millions)

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

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Total as of December 31, 2025

Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2024 of $891.5 million decreased by $1.3 billion from our estimated future capital costs of $2.2 billion as of December 31, 2023.

Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2023 of $2.2 billion decreased by $1.9 billion from our estimated future capital costs of $4.1 billion as of December 31, 2022.

These decreases were attributable to the lower number of future proved undeveloped locations expected to generate an economic return as a result of lower natural gas prices.

Given the low reference natural gas price prescribed by the SEC rules of $1.84 per Mcf for the year ended December 31, 2024, we performed an analysis to compare our proved reserve estimates as of December 31, 2024, to proved reserve estimates using a $3.26 per Mcf natural gas price and a $59.10 per Bbl oil price, which represents the NYMEX futures market prices as of December 31, 2024, adjusted for basis differentials ("alternative price case"), to show the sensitivity of our proved reserve estimates to price fluctuations.

The alternative price case includes proved undeveloped locations that we intend to drill that do not generate an economic return using the SEC prescribed prices.

This sensitivity analysis is only 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 estimated future capital costs to develop proved undeveloped reserves as of December 31, 2025 of $4.7 billion increased by $3.8 billion from our estimated future capital costs of $0.9 billion as of December 31, 2024.

This increase was attributable to the increase in future proved undeveloped locations included in the 2025 proved reserves with the higher natural gas prices in 2025.

Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2024 of $0.9 billion decreased by $1.3 billion from our estimated future capital costs of $2.2 billion as of December 31, 2023 due to a lower number of future proved undeveloped locations expected to generate an economic return as a result of lower natural gas prices.

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We performed an analysis to compare our proved reserve estimates as of December 31, 2025, to proved reserve estimates using year-end market prices of $3.23 per Mcf natural gas price and a $56.82 per Bbl oil price, which represents the NYMEX futures market prices as of December 31, 2025, adjusted for basis differentials ("alternative price case"), to show the sensitivity of our proved reserve estimates to price fluctuations.

This sensitivity analysis is meant to demonstrate the impact that changing natural gas and oil prices may have on our proved reserve estimates and the related PV 10 Value and there is no assurance this outcome will be realized.

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

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Proved reserve information in this report is based on estimates prepared by our petroleum engineering staff and is the responsibility of management.

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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.

Throughout the year, our technical team meets periodically with representatives of our independent petroleum consultants to

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review properties and discuss methods and assumptions.

We provide historical information to our consultants for our largest producing properties such as ownership interest, production, well test data, commodity prices and operating and development costs.

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Production and ad valorem taxes

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Drilling Activity Summary

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

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Producing Well Summary

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We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.

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

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The natural gas and oil industry also competes with other industries in supplying the energy and fuel requirements of industrial, residential and commercial consumers along with electric generator customers.

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Our natural gas production is primarily sold under contracts with various terms and priced on first of the month index prices or on daily spot market prices or fixed prices.

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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 and Venture Global LNG, Inc.

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.

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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

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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.

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.

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therefore, there is no assurance that the less stringent regulatory approach pursued by the FERC, Congress and state regulatory authorities will continue.

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Federal leases.

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The regulations provide that each year the Commission will publish the oil pipeline index after the PPI-FG becomes available.

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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.

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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.

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capital expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas.

The Biden administration has made, and the Trump administration may also make additional changes to applicable regulations.

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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

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impact on our operating costs, as well as the natural gas and oil industry in general.

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.

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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.

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In January 2023, the EPA and the U.S.

Army Corps of Engineers issued a new rule that revises the definition of "waters of the United States" ("WOTUS").

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.

Further, the EPA has adopted regulations requiring certain natural gas and oil exploration and production

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facilities to obtain permits for storm water discharges.

Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.

The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the cost of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.

We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution and that the requirements, including those under the 2023 WOTUS rule, are not any more burdensome to us than to other similarly situated companies involved in natural gas and oil exploration and production activities.

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.

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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

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operations by placing restrictions on the use of injection wells and hydraulic fracturing and/or causing us to incur increased operating expenses.

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.

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This order has the potential to adversely affect our operations by restricting areas in which we may carry out future exploration and development projects and/or causing us to incur increased operating expenses.

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Certain flora and fauna that have officially been classified as "threatened" or "endangered" are protected by the Endangered Species Act.

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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.

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has not passed legislation to expressly regulate GHG emissions;

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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.

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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.

Further, the United States has made additional commitments with respect to GHG emissions through the United Nations Climate Change Conference,

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including with respect to reducing methane emissions.

It is difficult to predict the timing and certainty of any future government action and the effect on our operations.

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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.

In general, 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.

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.

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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.

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state statutes limit the rate at which natural gas and oil can be produced from our properties.

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.

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We have an option to terminate the lease on December 31, 2028.

We also own production offices and pipe yard facilities near Carthage, Franklin, Nacogdoches, Marshall, Marquez and Tennessee Colony in Texas and Bossier City, Grand Cane, Greenwood, Homer, Mansfield and Logansport in Louisiana.

We also own production offices and pipe yard facilities near Carthage, Franklin, Marshall, Marquez and Tennessee Colony in Texas and Bossier City, Grand Cane, Greenwood, Homer, Mansfield and Logansport in Louisiana.

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Human Capital

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Chief Operating Officer

Clifford "Trey" D.

Chief Commercial Officer and Vice President of Corporate Development

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Vice President of Financial Reporting

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

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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.

Prior to 2005, he worked in various petroleum engineering operations management positions for

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several independent oil and gas exploration and development companies.

Harrison received a B.S.

Degree in Petroleum Engineering from the Louisiana State University in 1985.

Newell has been our Chief Commercial Officer and Vice President of Corporate Development since December 2022.

Newell has over 15 years of experience in commercial, marketing and operations experience in the midstream energy industry.

Clifford "Trey" D.

Newell has been our Chief Commercial Officer and Vice President of Corporate Development since 2022.

Newell has over two decades of experience in commercial, marketing and operations experience in the midstream energy industry.

Prior to joining us, Mr.

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Sanders is a Certified Professional Landman and became the nation's first Certified Professional Lease and Title Analyst in 1990.

Claunch has been our Vice President of Financial Reporting since June 2021.

Claunch joined the Company in June 2020 as Director of Financial Reporting.

Claunch has been our Vice President of Financial Reporting since 2021.

Claunch joined the Company in 2020 as Director of Financial Reporting.

Prior to joining Comstock, Mr.

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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.

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Outside Directors

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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.

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.

Foster currently serves as Chairman of Stagecoach Properties Inc., a real estate holding corporation with properties in Salado, Houston

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and College Station, Texas and Carmel, California and as a member of the Board of Regents of Texas A&M University.

In addition, Mr.

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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.

Turner is past-Chairman and currently serves on the Board of Trustees of Baylor Scott and White Health, the largest not-for-profit healthcare system in the State of Texas, where he also serves as Chairman of the Finance Committee and as a member of the Executive Committee.

He is a Director of Crown Holdings where he also serves as Chairman of the Compensation Committee and as a member of the Nominating and Governance Committee.

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.

Turner is former Chairman of Dean Foods Company where he also served as Chairman of the Compensation Committee.

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

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The prices we receive for our natural gas production depend on numerous factors beyond our control, including the following:

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• the domestic and foreign supply of natural gas;

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• 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, and acts of terrorism or sabotage;

• 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;

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• overall U.S.

and global economic and political conditions, including inflationary pressures, further increases in interest rates, a general economic slowdown or recession, political tensions and war (including future developments in the ongoing Russia-Ukraine and Israel-Hamas conflicts).

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

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Lower natural gas prices will adversely affect:

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Furthermore, while our revenues may increase if prevailing natural gas and oil prices increase significantly, our finding costs for additional reserves could also increase.

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

A prospect is a property in which we own an interest, or have operating rights to, and that has what our geoscientists believe, based on available seismic and geological information, to be an indication of potential oil or natural gas.

Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional evaluation and interpretation.

There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable.

The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in commercial quantities.

The analysis that we perform using data from other wells, more fully explored prospects and/or producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling prospects.

If we drill additional unsuccessful wells, our drilling success rate may decline and we may not achieve our targeted rate of return.

Further, unsuccessful drilling may impact our ability to fulfill our firm transportation commitments.

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

Market conditions or the unavailability of satisfactory natural gas transportation arrangements may hinder our access to natural gas markets or delay our production.

The availability of a ready market for our natural gas production depends on a number of factors, including the demand for and supply of natural gas and the proximity of reserves to pipelines and processing facilities.

Our ability to market our production depends in a substantial part on the availability and capacity of gathering systems, pipelines and processing facilities, which, in some cases, may be owned and operated by third parties.

Our failure to obtain such services on acceptable terms, if at all, could materially harm our business.

We may be required to shut in wells due to a lack of market demand or because of the inadequacy or unavailability of pipelines or gathering system capacity.

If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.

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Some of our undeveloped leasehold acreage is subject to leases that will expire unless production is established on units containing the acreage.

Failure to administer lease acquisitions, lease contracting, lease maintenance and timely lease payments could lead to loss of leased land.

A large portion of our undeveloped leasehold acreage is subject to leases with primary terms that expire prior to 2028 unless we establish and maintain production on units containing these leases during their terms or we renew them before their expiration.

The cost to renew such leases could increase significantly and we may not be able to renew such leases on economically beneficial terms or at all.

If our leases expire or we are unable to renew such leases, we will lose our right to develop such leasehold acreage and our exploration and development activities could materially differ from our current expectations, which could adversely affect our business.

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

When drilling and completion activity in the United States or a particular operating area increases, associated costs also increase, including costs associated with drilling rigs, completion equipment, drill pipe, casing and other tubular goods, sand and other proppants, personnel and other related services.

If these costs increase, we may not be able to obtain necessary equipment, supplies and services or obtain them at economically beneficial terms.

Such increases in cost could result in delays in our drilling or completion activities, which could limit our ability to establish and replace reserves, or should we choose to incur higher costs, could negatively impact our business.

Substantial exploration and development activities could require significant outside capital, which could dilute the value of our common shares and restrict our activities.

Also, we may not be able to obtain needed capital or financing on satisfactory terms, which could lead to a limitation of our future business opportunities and a decline in our natural gas and oil reserves.

We expect to expend substantial capital in the acquisition of, exploration for and development of natural gas 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.

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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.

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.

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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.

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 oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities.

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.

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.

We may be subject to physical and financial risks associated with climate change.

Changing climate 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, many climate models indicate that global warming is likely to result in rising sea ‎levels and increased frequency ‎and severity of weather events, which 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.‎

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 change.

To the extent financial markets view climate change and GHG emissions as a financial risk, this ‎could ‎negatively impact our cost of and access to capital.

Increasing scrutiny and changing 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 increasing scrutiny from stakeholders related to their ‎environmental, social and ‎governance ("ESG") practices.

Investor advocacy groups, certain ‎institutional investors, investment funds and other influential ‎investors are also increasingly ‎focused on ESG practices and in recent years have placed increasing importance on the ‎implications ‎and social cost of their investments.

Regardless of the industry, investors' increased ‎focus and activism related to ESG and similar ‎matters may hinder access to capital, as investors ‎may decide to reallocate capital or to not commit capital as a result of their ‎assessment of a ‎company's 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.‎

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We face pressures from our stockholders, who are increasingly focused on climate change, to ‎prioritize sustainable energy ‎practices, reduce our carbon footprint and promote sustainability.

‎Our stockholders may require us to implement new ESG procedures or ‎standards in order to continue ‎engaging with us, to remain invested in us or before they may make further investments in us.

‎‎Additionally, we may face reputational challenges in the event our ESG procedures or standards ‎do not meet the standards set by certain constituencies.

We have adopted certain practices and ‎metrics as highlighted on our website, including with respect to air emissions, land use, ‎environmental, health and safety management and corporate governance.

It is possible, ‎however, that our stockholders might not be satisfied with our sustainability efforts or the ‎speed ‎of their adoption.

If we do not meet our stockholders' expectations, our business, ability to ‎access capital, and/or our stock price ‎could be harmed.‎

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

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• recoverable reserves;

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• exploration potential;

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While our current operations are focused in Texas and Louisiana, we may pursue acquisitions or properties located in other geographic areas.

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.

Our failure to obtain such services on acceptable terms, if at all, could materially harm our business.

We may be required to shut in wells due to a lack of market demand or because of the inadequacy or unavailability of pipelines or gathering system capacity.

If that were to occur, then we would be unable to realize revenue from those wells until arrangements were made to deliver our production to market.

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

We had $3.0 billion principal amount of debt as of December 31, 2024.

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;

• 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;

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

We are subject to stringent federal, state and local laws.

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.

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

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

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• abnormally pressured formations;

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We could also incur substantial losses as a result of:

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• injury or loss of life;

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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, malicious software, 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.

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.

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

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

• Compromise or corruption of our data or systems integrity;

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• Reputational harm or loss of customer trust or confidence;

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• 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.

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As such, there can be no assurance that material cost and liabilities will not be incurred in the future.

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

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

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

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

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

Future acquisitions or development activities may require us to alter our capitalization significantly.

These changes in capitalization may significantly increase our debt.

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;

• 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.

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These transactions could result in both realized and unrealized hedging losses.

Further, these hedges may be inadequate to protect us from continuing and prolonged declines in the price of natural gas.

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.

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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

If our actual future production is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution in our profitability and

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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.

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• 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.

UNRES OLVED STAFF COMMENTS

CYBERSECURITY

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We face various cybersecurity threats that could adversely affect our business, financial condition, and results of operations.

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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

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cybersecurity best practices and their roles and responsibilities.

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 eight years of experience in cyber and information security.

We also have a Certified Information Systems Security Professional, who has nine years of experience in cyber and information security.

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What changed 10-K

Item 1. Business