What changed in this filing

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Item 1. Business

2025-02-21 compared with 2024-02-16 · 170 added, 175 removed, 667 unchanged (34% of the section changed)

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 markets.

As of December 31, 2023, 99% of our proved reserves were in the Haynesville and Bossier shale play.

We are focused on creating value through the development of our substantial inventory of highly economic and low-risk drilling opportunities in the Haynesville and Bossier shales and through our exploration activities in our Western Haynesville play.

As of December 31, 2024, 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 under the symbol "CRK".

Our operations are primarily concentrated in Louisiana and Texas.

Our natural gas and oil properties are estimated to have proved reserves of 4.9 Tcfe with a PV 10 Value of $2.5 billion as of December 31, 2023 based on SEC prices and 6.6 Tcfe with a PV 10 Value of $5.2 billion based on our alternative price case.

Our proved reserves are principally natural gas, which are 56% developed as of December 31, 2023 with an average reserve life of approximately 9 years.

Our operations are concentrated in Louisiana and Texas.

Our natural gas and oil properties are estimated to have proved reserves of 3.8 Tcfe with a PV 10 Value of $1.6 billion as of December 31, 2024 based on SEC prices.

Our proved reserves are principally natural gas, which were 73% developed as of December 31, 2024 with an average reserve life of approximately 7 years.

Using NYMEX futures market natural gas and oil prices as of December 31, 2024, proved reserves are estimated at 7.0 Tcfe with a PV 10 Value of $5.7 billion.

Using these prices, our proved reserves were 41% developed as of December 31, 2024, with an average reserve life of approximately 13 years.

High Quality Properties .

As of December 31, 2023, we had 717,875 acres (552,712 net) in the Haynesville and Bossier shale plays, located in North Louisiana and East Texas, including our Western Haynesville area.

As of December 31, 2024, we have 1,099,090 acres (819,489 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 longer horizontal lateral length and substantially larger well stimulations.

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.

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 positions are located in one of the premier North American natural gas basins and have access to the growing Gulf Coast market demand 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 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 shale plays have been substantially delineated since 2008.

We believe that these shale plays represent some of the most consistent and economic natural gas drilling opportunities in North America.

• Management and operating team with extensive experience in developing the Haynesville and Bossier shale .

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.

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 and Bossier shales with strong results to date.

We have drilled and completed 471 operated Haynesville and Bossier shale wells from 2015 through 2023.

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.

We have also drilled some of the longest lateral wells in the basin.

We successfully drilled 27 wells with laterals of approximately 15,000 feet from 2021 through 2023.

We successfully drilled 31 wells with laterals of 15,000 feet or greater from 2021 through 2024.

• Attractive economic returns .

The Haynesville and Bossier shales offer highly economic and low-risk drilling opportunities through application of advanced drilling and completion technologies, including the use of longer laterals, and high intensity fracture stimulation using tighter frac stages and higher proppant loading.

Our management and operating team have been 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.

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 the extensive midstream infrastructure with lower cost, flexible gas marketing arrangements.

Value-Added Leasehold Acquisitions.

Over the last four years we have acquired a total of approximately 252,564 net undeveloped acres prospective for the Haynesville and Bossier shales through acquisitions and an active leasing program.

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.

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.

• 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.

• 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.

• Successful Drilling Program.

We spent $1.3 billion on exploration and development activities in 2023, almost exclusively in the Haynesville and Bossier shale.

We spent $1.2 billion on drilling and completion activities and an additional $53.0 million on other development costs.

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 drilled 50 (42.9 net) wells in 2024, which had an average lateral length of approximately 10,759 feet.

Our drilling program in 2023 replaced 109% of our 2023 production.

The results included five successful wells in our Western Haynesville play.

Our drilling program in 2024 replaced 101% of our 2024 production based on proved reserves added in our SEC price case and 170% based on proved reserves added in our alternative price case.

• Efficient Operator.

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As of December 31, 2024, we have identified 2,658 drilling locations (1,350 net to us) 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 113 horseshoe locations with superior economics compared to the 226 short lateral locations they replaced.

The average lateral length of our drilling location inventory is 9,603 feet.

• Grow reserve base through active exploration program.

We are investing a part of our annual capital budget to expand our acreage holdings and delineate the emerging Western Haynesville and Bossier shale play in East Texas.

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 currently intend to drill an additional ten Haynesville and Bossier shale wells in this play.

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

In 2025, we currently intend to drill an additional 20 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 shale to continue to pursue acquisition opportunities in our region and to successfully execute and integrate acreage acquisitions that will add to our drilling 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.

Given the current low natural gas prices, we intend to maintain a conservative operating plan in 2024 with the primary goal of protecting our balance sheet.

Our current plan is to fund our exploration and development activity with operating cash flow and borrowings under our bank credit facility as necessary.

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.

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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 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

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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.

• 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.

Property Acquisitions

In 2023, we added 79,741 net acres in the Western Haynesville through an active leasing program at a cost of $98.6 million.

In 2022, we added 104,314 net Haynesville and Bossier shale acres in Western Haynesville through acquisitions and direct leasing for $54.4 million.

In 2021, we acquired approximately 17,500 net acres of predominantly undeveloped Haynesville shale acreage in East Texas, which also included interests in 37 producing wells for $34.7 million.

We also leased 32,556 net acres in the Western Haynesville for $22.9 million.

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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 2022, we added 104,314 net Haynesville and Bossier shale acres in Western Haynesville for $54.4 million.

Western Haynesville Midstream Venture

To support the development of the Western Haynesville acreage, we entered into a partnership on October 31, 2023 with Quantum Capital Solutions ("Quantum") 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 drill on our acreage.

Pinnacle Gas Services LLC ("Pinnacle") was formed by the contribution of a 145-mile high pressure pipeline and natural gas treating plant which we acquired in 2022.

We had invested $30.0 million in these midstream assets including the initial acquisition costs.

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.

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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.

Property Dispositions

In 2023, we sold our working interests in 55 (6.7 net) non-operated wells for $41.3 million.

In 2022, we sold our interests in certain nonstrategic, non-operated properties for $4.1 million, which included working interests in 575 (56.3 net) wells producing approximately 2.7 MMcfe of natural gas per day.

In 2021, we sold our non-operated properties in the Bakken shale for $138.1 million after selling expenses.

The Bakken shale properties sold included non-operated working interests in 442 producing wells (68.3 net) producing approximately 4,500 barrels of oil equivalent per day.

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.

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.

99% of our proved reserves are in the Haynesville and Bossier shales in North Louisiana and East Texas.

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 19,000 feet.

All of our proved undeveloped reserves represent wells to be drilled in the next five years on our Haynesville and Bossier shale acreage.

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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.

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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 2.0 Tcf during 2023 due to low natural gas prices used to determine the proved reserves as 164 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.

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, 2022, our proved undeveloped reserves were comprised of 4.2 Tcf of natural gas, all of which were associated with our Haynesville and Bossier shale (including Western Haynesville and Bossier) properties.

Our natural gas proved undeveloped reserves increased by 294 Bcf during 2022.

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.

Our natural gas proved undeveloped reserves decreased by 2.0 Tcf during 2023.

During 2023, 67 proved undeveloped locations were converted to proved developed reserves.

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The following table presents the changes in our estimated proved undeveloped natural gas and oil reserves for the years ended December 31, 2024, 2023 and 2022:

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Total as of December 31, 2024

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.

This decrease was attributable to the lower number of future proved undeveloped locations expected to generate an economic return as a result of lower natural gas prices.

Our estimated future capital costs to develop proved undeveloped reserves as of December 31, 2022 of $4.1 billion increased by $1.4 billion from our estimated future capital costs of $2.7 billion as of December 31, 2021.

We performed an analysis to compare our proved reserve estimates as of December 31, 2023 to natural gas and oil reserves using a $3.24 per Mcf natural gas price and a $69.39 per Bbl oil price, which represents our expected realized prices based on a $3.50 per Mcf NYMEX index natural gas price and a $75.00 per Bbl NYMEX index oil price ("Alternative Prices") to show the sensitivity of our natural gas and oil reserves to price fluctuations.

All factors other than the natural gas and oil price assumptions have been held constant with the average first of the month pricing for the last twelve months ("SEC Prices"), including the number of proved undeveloped locations, drill schedules and operating cost assumptions.

This sensitivity analysis is only meant to demonstrate the impact that changing natural gas and oil prices may have on our proved natural gas and oil reserves 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 Alternative Prices are as follows:

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

SEC Price Case

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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.

Remaining differences are not resolved due to the limited cost benefit of continuing such analysis.

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.

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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.

Bartlett holds a Bachelor of Science degree in Petroleum Engineering and Geoscience from the University of Texas at Austin and has eleven years of engineering experience in the oil and gas industry.

Bartlett holds a Bachelor of Science degree in Petroleum Engineering and Geoscience from the University of Texas at Austin and has 12 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, 2024 to any federal authority or agency, other than the SEC.

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Net Production Volumes:

Natural gas - Mcf

Natural gas - MMcf

Average Prices:

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Producing Well Summary

The following table sets forth the gross and net producing natural gas and oil wells in which we owned an interest at December 31, 2023:

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, 2024:

We operate 1,747 of the 2,427 producing wells presented in the above table.

As of December 31, 2024, 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.

The following table summarizes our developed and undeveloped leasehold acreage at December 31, 2023, all of which is onshore in the continental United States.

The following table summarizes our developed and undeveloped leasehold acreage as of December 31, 2024, 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.

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As of December 31, 2024, our undeveloped acreage expires as follows:

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.

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.

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

We target selling approximately 80% of our natural gas on first of month index price, with the remaining 20% on daily spot market pricing.

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, Southwest Energy L.P.

and Venture Global LNG, Inc.

accounted for 20%.

17% and 10%, respectively, of our total 2023 sales.

Enterprise Products Operating and its subsidiaries and Venture Global LNG, Inc.

accounted for 21% and 12%, respectively, of our total 2024 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.

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To the extent we are not able to deliver the contracted natural gas volumes, we may be responsible for the transportation costs.

Our production available to deliver under these agreements is expected to exceed the firm transportation arrangements we have in place.

In addition, any marketing company managing the firm transportation is required to use reasonable efforts to supplement our deliveries should we have a shortfall during the term of the agreements.

The natural gas and oil industry is highly competitive.

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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

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

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regulations binding upon the natural gas and oil industry and its individual members.

The Federal Energy Regulatory Commission, or "FERC", regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938, or "NGA", and the Natural Gas Policy Act of 1978, or "NGPA".

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.

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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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 ("BOEMRE"), through its Minerals Revenue Management Program, which is responsible for the management of revenues from both onshore and offshore leases.

The Company's operations located on federal natural gas and oil leases are insignificant to its total operations and any Executive Orders related to federal natural gas and oil leases issued by the Biden administration are not expected to adversely affect our business, financial position and results of operations.

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.

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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

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(PPI-FG) plus 1.3 percent for the period July 1, 2006 through June 30, 2011.

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.

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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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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 is expected to make additional changes to applicable regulations, and in each case we expect changes to be more stringent than those of the prior administration.

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.

The Comprehensive Environmental Response, Compensation and Liability Act;

or "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.

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.

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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, or "RCRA", regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites.

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.

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wastes handled at exploration and production sites or used in the course of providing well services may not fall within this exclusion.

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.

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.

The impact of future revisions to environmental laws and regulations cannot be predicted.

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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, or "CAA", and comparable state and local 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.

Between 2012 and 2014, the EPA promulgated new emission standards for the natural gas and oil industry, and made revisions that imposed further requirements with respect to volatile organic compounds ("VOCs") and methane.

In September 2020, the EPA published a rule that revised the VOC requirements and rescinded the methane requirements, as well as revised its interpretation of the CAA, such that, in order to impose the methane emission requirements, it would need to first make a Significant Contribution Finding for each particular pollutant for the specific source.

Since that time, the US has passed a law that repeals the 2020 rules, and the EPA issued a new proposed rule as of November 2021 and supplemented the proposed rule in December 2022.

EPA issued its final new rule on December 2, 2023.

The rule has a number of provisions intended to reduce methane emissions from natural gas and oil 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.

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, or the "Clean Water Act", imposes restrictions and controls on the discharge of produced waters and other wastes into navigable waters.

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.

Recent judicial interpretations have caused certain water features to be considered jurisdictional when they were not previously.

Additionally, in January 2023,the EPA and the US Army Corps of Engineers issued a new rule that revises the definition of "waters of the United States" ("WOTUS").

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").

The new rule has been challenged by several states and industry groups.

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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

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or suspend operations.

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 US 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 United States 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 United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Texas, Colorado, Oklahoma, Kansas, New Mexico, and Arkansas.

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.

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.

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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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

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emissions of greenhouse gases ("GHG").

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, or CO2e.

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.

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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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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.

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 VOC and methane generation from natural gas and oil operations.

Additional regulations may still be forthcoming.

Similarly, the Bureau of Land Management ("BLM") has proposed to suspend and revise a 2016 rule relating to methane venting, flaring, and leaks from natural gas and oil production on public lands that was being challenged by multiple western states and energy companies.

In September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule.

The 2018 rule was challenged in federal court, and was vacated in 2020, but the court stayed its vacatur of the 2018 rule to allow for challenges to the 2016 rule to proceed.

BLM did not defend the 2016 rule, and it was vacated.

This decision may be further appealed, leaving the final outcome uncertain.

In November 2022, the BLM proposed a new rule that would establish new requirements designed to reduce waste of natural gas from venting, flaring and leaks.

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.

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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, the Biden administration has reinstated the United States' participation.

Further, the US has made additional commitments with respect to GHG emissions through the United Nations Climate Change Conference, including with respect to reducing methane emissions.

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.

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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 2010, the BLM began implementation of a proposed natural gas and oil gas leasing reform that would increase environmental review requirements and was expected to have the effect of reducing the amount of new federal lands made available for lease, increasing the competition for and cost of available parcels.

This leasing reform initiative was replaced by

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a new BLM policy, dated January 31, 2018, which is expected to remove the additional environmental review created under the 2010 initiative and streamline the leasing process.

Additionally, on December 28, 2017, the BLM rescinded a rule the BLM adopted in 2015 concerning hydraulic fracturing on federal land.

The 2015 rule would have required increased well integrity testing, increased requirements for the managing of fluids, and the disclosure of chemicals used in fracturing.

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.

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.

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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.

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

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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 lease office space in Frisco, Texas covering 66,382 square feet.

This lease expires on December 31, 2031, with an early termination provision at the end of the fourth year.

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, Nacogdoches, Marshall, Marquez and Tennessee Colony in Texas and Bossier City, Grand Cane, Greenwood, Homer, Mansfield and Logansport in Louisiana.

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As of December 31, 2024, we had 256 employees and utilized contract employees for certain of our drilling, completion and production operations.

We seek to attract a qualified and diverse 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 obtain our goals of operational excellence and an injury free workplace, we maintain a strong health and safety management system.

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.

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We hold our contractors accountable to the highest performance standards through our contractor onboarding and continuous auditing process.

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Directors and Executive Officers

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Chief Operating Officer

Vice President of Corporate Development and Chief Commercial Officer

Chief Commercial Officer and Vice President of Corporate Development

Vice President of Operations

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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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degrees from the University of Mississippi in 1982 and is a Certified Public Accountant.

Harrison became our Chief Operating Officer in July 2019 and served as Vice President of Operations since 2017.

Harrison has been our Chief Operating Officer since 2019 and served as Vice President of Operations since 2017.

Harrison has been with us since 2008 and served in various engineering and operations management positions of increasing responsibility during that time.

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

Newell became our Vice President of Corporate Development and Chief Commercial Officer in December 2022.

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

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.

Prior to joining us, Mr.

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He also received his Master of Energy Business from the University of Tulsa in 2015.

McGough became our Vice President of Operations in July 2019 following our acquisition of Covey Park Energy, LLC.

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.

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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.

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Mills became our Vice President of Finance and Investor Relations in August 2019.

Mills has been our Vice President of Finance and Investor Relations since 2019.

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 became our Vice President of Financial Reporting in June 2021.

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

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

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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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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 in 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 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.

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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

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information that is electronically filed with the SEC.

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.

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

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

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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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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.

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‎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

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duration and ‎magnitude of any changes.

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.

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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 river banks, and facilities situated in hurricane-prone ‎and rain-susceptible regions.

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.

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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.

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Further, we cannot assure you that future acquisitions by us will be integrated successfully into our operations or will increase our profits.

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

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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 could materially harm our business.

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.

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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 effected on a timely basis or on satisfactory terms or that these actions would enable us to continue to satisfy our capital requirements.

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.

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• pay dividends.

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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.

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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 SOFR or an alternate base rate, at our option.

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.

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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 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

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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, 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.

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.

If any of these events were to materialize, either to the Company or a third party upon which we rely, they could lead to:

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;

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

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Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions.

In addition, the Biden administration has made, and is expected to make additional changes to applicable regulations, and in each case we expect changes to be more stringent than those of the prior administration.

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.

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Our hedging transactions could result in financial losses or could reduce our income.

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

To the extent that the natural gas prices remain at current levels or declines 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.

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.

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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 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.

If our actual future production is lower than the nominal amount that is subject to our derivative financial

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

We have implemented processes and procedures 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.

Our processes for assessing and identifying cybersecurity risks include regular network security assessments, vulnerability scans, penetration tests, and audits of our information systems, as well as monitoring and analysis of network activity and threat intelligence.

We engage third-party service providers to assist us with some of these activities.

We also have 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.

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.

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Our information technology management plays an integral part in the identification and communication of cybersecurity risks to our management team.

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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.

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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 a cyber incident.

However, we cannot guarantee that we will not suffer cybersecurity incidents in the future, which could result in:

• 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;

• Other negative consequences.

Any of these outcomes could have 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.

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

The Audit Committee of our Board of Directors provides oversight over our cybersecurity risk management and strategy.

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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 cybersecurity best practices and their roles and responsibilities.

They also provide periodic awareness notifications to our employees and contractors on

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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.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business