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BKV Corp

BKV CorpBKVEarnings & Financial Report

NYSE · Energy · Crude Petroleum & Natural Gas

BKV Corp is a North American independent energy company focused on sustainable natural gas exploration, production, and distribution, with core operating assets located in the Appalachian Basin. It serves utility, industrial, and commercial customers across the region, and invests in low-carbon technologies including carbon capture to reduce operational emissions.

What changed in BKV Corp's 10-K — 2024 vs 2025

Top changes in BKV Corp's 2025 10-K

819 paragraphs added · 747 removed · 560 edited across 7 sections

Item 1. Business

Business — how the company describes what it does

199 edited+61 added−63 removed207 unchanged
CCUS Projects Currently, we have one operational CCUS project and are pursuing additional potential CCUS projects that we believe are commercially viable based on economics supported by enhanced Section 45Q tax credits and that we believe can be completed by the late 2030s.
Currently, we have one operational CCUS project and are pursuing additional potential CCUS projects that we believe are commercially viable based on economics supported by enhanced Section 45Q tax credits and that we believe can be completed by the late 2030s.
Ultimately, we will be able to apply only such portion of the sequestered emissions to offset our own GHG emissions that corresponds to the percentage of environmental attributes BKV receives (and retains) or purchases.
Ultimately, we will be able to apply only such portion of the sequestered emissions to offset our own GHG emissions that corresponds to the percentage of environmental attributes BKV receives (and retains) or purchases.
In addition, lower oil and natural gas prices may cause our proved undeveloped reserves to become uneconomic to develop, which would cause us to remove them from their respective reserves category.
In addition, lower oil and natural gas prices may cause our proved undeveloped reserves to become uneconomic to develop, which would cause us to remove them from their respective reserves category.
The EPA has issued the “Final Mandatory Reporting of Greenhouse Gases” Rule and a series of revisions to it, which requires operators of oil and gas production, natural gas processing, transmission, distribution and storage facilities and other stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report annually their GHG emissions occurring in the prior calendar year on a facility-by-facility basis.
The EPA issued the “Final Mandatory Reporting of Greenhouse Gases” Rule and a series of revisions to it, which requires operators of oil and gas production, natural gas processing, transmission, distribution and storage facilities and other stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report annually their GHG emissions occurring in the prior calendar year on a facility-by-facility basis.
For CCUS facilities placed in service after December 31, 2022, Section 45Q of the Code generally provides the capturing parties a tax credit of $85 per ton for CO 2 directly stored in geologic formations, subject to satisfaction or non-application of certain prevailing wage and apprenticeship requirements (or $17 per ton if such prevailing wage and apprenticeship requirements are not satisfied), with adjustments for inflation after 2026.
For CCUS facilities placed in service after December 31, 2022, Section 45Q of the Code generally provides the capturing parties a tax credit of $85.00 per ton for CO 2 directly stored in geologic formations, subject to satisfaction or non-application of certain prevailing wage and apprenticeship requirements (or $17.00 per ton if such prevailing wage and apprenticeship requirements are not satisfied), with adjustments for inflation after 2026.
However, we have not secured external financing, reached FID or entered into the definitive agreements necessary to execute any of the pre-FID projects identified above, and there can be no guarantee that we will be able to execute and operate any of the potential CCUS projects we have identified (or any other CCUS projects) with sufficient volumes of CO 2e sequestration to achieve our Scope 1, 2, and 3 emissions goals on the timelines we anticipate.
However, we have not secured external financing, reached FID, or entered into the definitive agreements necessary to execute any of the pre-FID projects identified above, and there can be no guarantee that we will be able to execute and operate any of the potential CCUS projects we have identified (or any other CCUS projects) with sufficient volumes of CO 2 sequestration to achieve our Scope 1, 2, and 3 emissions goals on the timelines we anticipate.
This aspiration to offset the Scope 3 emissions of our owned and operated upstream and natural gas midstream businesses by the late 2030s is limited to our Category 11 (Use of Sold Product) emissions, which we believe represents a significant portion of the overall Scope 3 emissions from our owned and operated upstream and natural gas midstream businesses.
This aspiration to offset the Scope 3 emissions of our owned and operated upstream and natural gas midstream businesses by the late 2030s is primarily limited to our Category 11 (Use of Sold Product) emissions, which we believe represents a significant portion of the overall Scope 3 emissions from our owned and operated upstream and natural gas midstream businesses.
We have engaged third parties to analyze and report the CO 2 injection volumes and environmental attributes of our sequestration projects, and we are working with the ACR to certify and register the environmental attributes associated with our CCUS projects as tradeable carbon credits.
We have engaged third parties to analyze and report the CO 2 injection volumes and environmental attributes of our sequestration projects, and we are working with the ACR and Verra to certify and register the environmental attributes associated with our CCUS projects as tradeable carbon credits.
We expect our CCUS business to contribute in significant part to our goals to fully offset our Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses by the early 2030s, and our Scope 1, 2, and 3 emissions from our owned and operated upstream and natural gas midstream businesses by the late 2030s.
We expect our CCUS business to contribute in significant part to our goals to fully offset our Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses during the early 2030s, and our Scope 1, 2, and 3 emissions from our owned and operated upstream and natural gas midstream businesses by the late 2030s.
(2) Proved undeveloped reserves as of December 31, 2024 and 2023 are part of a development plan that has been adopted by management indicating that such locations are scheduled to be drilled within five years.
(2) Proved undeveloped reserves as of December 31, 2025, 2024, and 2023 are part of a development plan that has been adopted by management indicating that such locations are scheduled to be drilled within five years.
In the Barnett, we have several firm transportation contracts specific to the Devon Barnett Acquisition to transport natural gas volumes out of the Barnett to premium markets, including 200,000 MMBtu/d to the Katy area, 200,000 MMBtu/d of intra-basin aggregation transport, which feeds 175,000 MMBtu/d of interstate transport to Transco Zone 4 Station 85, and 60,000 MMBtu/d to NGPL-TxOk with term end dates ranging through 2025 and 2029.
In the Barnett, we have several firm transportation contracts specific to the Devon Barnett Acquisition to transport natural gas volumes out of the Barnett to premium markets, including 200,000 MMBtu/d to the Katy area, 200,000 MMBtu/d of intra-basin aggregation transport, which feeds 175,000 MMBtu/d of interstate transport to Transco Zone 4 Station 85, and 60,000 MMBtu/d to NGPL-TxOk with term end dates ranging through 2026 and 2029.
As a result of technical evaluation of geologic and engineering data, it can be estimated with reasonable certainty that reserves from these locations are commercially recoverable in accordance with SEC guidelines. Management 24 Table of Contents considers the availability of local infrastructure, drilling support assets, state and local regulations, and other factors it deems relevant in determining such locations.
As a result of technical evaluation of geologic and engineering data, it can be estimated with reasonable certainty that reserves from these locations are commercially recoverable in accordance with SEC guidelines. Management 26 Table of Contents considers the availability of local infrastructure, drilling support assets, state and local regulations, and other factors it deems relevant in determining such locations.
As of December 31, 2024, we have multiple contracts for firm transportation services including a combined 61,000 MMBtu/d to various locations on Tennessee Gas Pipeline and 27,500 MMBtu/d on Millennium Pipeline, which provide access to premium markets in New England (Algonquin), the Northeast and Gulf Coast areas.
As of December 31, 2025, we have multiple contracts for firm transportation services including a combined 61,000 MMBtu/d to various locations on Tennessee Gas Pipeline and 27,500 MMBtu/d on Millennium Pipeline, which provide access to premium markets in New England (Algonquin), the Northeast, and Gulf Coast areas.
As it relates to the Temple Plants, in addition to 2,812,500 MMBtu of storage at Energy Transfer’s Bammel storage facility which expires in late 2027, the Temple Plants hold a combined 200,000 MMBtu/d of firm transport with Atmos and Energy Transfer and its subsidiaries which supports receipt of gas from the Katy Area with delivery to the Temple Facility and expires in late 2027.
As it relates to the Temple Plants, in addition to 2,812,500 MMBtu of storage at Energy Transfer’s Bammel storage facility which expires in December 2027, the Temple Plants hold a combined 200,000 MMBtu/d of firm transport with Atmos and Energy Transfer and its subsidiaries which supports receipt of gas from the Katy Area with delivery to the Temple Facility and expires in December 2027.
Some of our competitors not only engage in the acquisition, exploration, development, and production of oil and gas reserves and electricity generation, but also carry-on refining operations and the marketing of refined products. In addition, the oil and gas industry in general competes with other industries supplying energy and fuel to industrial, commercial, and individual consumers, including alternative energy sources.
Some of our competitors not only engage in the acquisition, exploration, development, and production of oil and gas reserves and electricity generation, but also in refining operations and the marketing of refined products. In addition, the oil and gas industry in general competes with other industries supplying energy and fuel to industrial, commercial, and individual consumers, including alternative energy sources.
Our Chief Corporate Development Officer, Ethan Ngo, is primarily responsible for overseeing the independent reserves engineers during the process. Mr. Ngo has over 16 years of conventional and unconventional experience on and offshore across the lower 48 states with a major oil and gas company, independent oil and gas companies, and a private-equity-backed oil and gas company. Mr.
Our Chief Corporate Development Officer, Ethan Ngo, is primarily responsible for overseeing the independent reserves engineers during the process. Mr. Ngo has over 17 years of conventional and unconventional experience on and offshore across the lower 48 states with a major oil and gas company, independent oil and gas companies, and a private-equity-backed oil and gas company. Mr.
In the Barnett Zero Project, EnLink transports our natural gas produced in the Barnett to its natural gas processing plant in Bridgeport, Texas, where the CO 2 waste stream is captured, compressed and then disposed of, and sequestered via our nearby Class II injection well that complies with standards applicable to Class VI wells.
In the Barnett Zero Project, ONEOK transports our natural gas produced in the Barnett to its natural gas processing plant in Bridgeport, Texas, where the CO 2 waste stream is captured, compressed, and then disposed of, and sequestered via our nearby Class II injection well that complies with standards applicable to Class VI wells.
While we may consider alternatives to offset our owned and operated upstream and natural gas midstream emissions (including the purchase of verified offset credits) in order to meet our Scope 1 and 2 emissions goals, ultimately, we may not be able to achieve our goals of net zero Scope 1 and 2 emissions from our owned and operated upstream businesses and natural gas midstream by the early 2030s.
While we may consider alternatives to offset our owned and operated upstream and natural gas midstream emissions (including the purchase of verified offset credits) in order to meet our Scope 1 and 2 emissions goals, ultimately, we may not be able to achieve our goals of net zero Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses during the early 2030s.
Our estimated reserves based on NYMEX futures were otherwise prepared on the same basis as our SEC reserves for the comparable period. Actual future prices may vary significantly from the NYMEX strip prices on December 31, 2024. Actual revenue and value generated may be more or less than the amounts disclosed.
Our estimated reserves based on NYMEX futures were otherwise prepared on the same basis as our SEC reserves for the comparable period. Actual future prices may vary significantly from the NYMEX strip prices on December 31, 2025. Actual revenue and value generated may be more or less than the amounts disclosed.
We have included this information in order to provide an additional method of presentation of the fair value of our assets and the cash flows that we expect to generate from those assets based on the market’s forward-looking pricing expectations as of December 31, 2024.
We have included this information in order to provide an additional method of presentation of the fair value of our assets and the cash flows that we expect to generate from those assets based on the market’s forward-looking pricing expectations as of December 31, 2025.
Estimated Reserves at NYMEX Strip Pricing The following table provides our total estimated proved reserves information prepared by Ryder Scott as of December 31, 2024, using NYMEX strip prices as of market close on December 31, 2024 and PV-10 Value and the Standardized Measure for such period.
Estimated Reserves at NYMEX Strip Pricing The following table provides our total estimated proved reserves information prepared by Ryder Scott as of December 31, 2025, using NYMEX strip prices as of market close on December 31, 2025 and PV-10 Value and the Standardized Measure for such period.
If we are not able to complete CCUS projects having a sufficient forecasted volume of carbon capture to offset our Scope 1, 2, and 3 annual emissions on the timeline and upon terms that we believe are obtainable, we may not be able to achieve our goal of net zero Scope 1, 2, and 3 emissions from our owned and operated upstream and natural gas midstream businesses by the late 2030s.
If we are 22 Table of Contents not able to complete CCUS projects having a sufficient forecasted volume of carbon capture to offset our Scope 1, 2, and 3 annual emissions on the timeline and upon terms that we believe are obtainable, we may not be able to achieve our goal of net zero Scope 1, 2, and 3 emissions from our owned and operated upstream and natural gas midstream businesses by the late 2030s.
We believe that carbon emissions within the United States can be reduced substantially through carbon capture on natural gas production, power plants, processing facilities, and other energy and industrial infrastructure. As such, in addition to lowering emissions in our owned and operated upstream and natural gas midstream businesses, CCUS for third parties has become a focus of our business plan.
We believe that carbon emissions within the United States can be reduced substantially through carbon capture on natural gas production, power plants, processing facilities, and other energy and industrial infrastructure. As such, in addition to lowering emissions in our owned and operated upstream and natural gas midstream businesses, CCUS for third parties is a focus of our business plan.
However, we may not receive 100% of the environmental attributes associated with CCUS projects funded in whole or in part by third parties, and, in such cases, we expect to have the right to purchase such environmental attributes BKV would not otherwise receive.
However, we may not receive 100% of the environmental attributes associated with CCUS projects funded in whole or in part by third parties, and, in such cases, we expect to have the ability to purchase such environmental attributes BKV would not otherwise receive.
Summary of Our Reserves Estimates Ryder Scott, our independent petroleum engineers, prepared estimates of our natural gas, NGL, and oil reserves as of December 31, 2024, 2023, and 2022. These reserves estimates were prepared in accordance with the rules and regulations of the SEC regarding oil and natural gas reserves reporting.
Summary of Our Reserves Estimates Ryder Scott, our independent petroleum engineers, prepared estimates of our natural gas, NGL, and oil reserves as of December 31, 2025, 2024, and 2023. These reserves estimates were prepared in accordance with the rules and regulations of the SEC regarding oil and natural gas reserves reporting.
The decrease in proved reserves was primarily attributable to decreased commodity pricing and changes in our planned drilling activity, which resulted in total downward revisions of 714.9 Bcfe. In addition, in June 2024, we sold our wholly-owned subsidiary, Chaffee and certain of our non-operated upstream assets in BKV Chelsea, LLC (“Chelsea”) decreasing reserves by 150.0 Bcfe.
The decrease in proved reserves was primarily attributable to decreased commodity pricing and changes in our planned drilling activity, which resulted in total downward revisions of 714.9 Bcfe. In addition, in June 2024, we sold our wholly-owned subsidiary, Chaffee and certain of our non-operated upstream assets in Chelsea, decreasing reserves by 150.0 Bcfe.
For more information about potential risks that could affect us, see “ Risk Factors — Risks Related to Our Business Generally — Our business is subject to operating hazards that could result in substantial losses or liabilities for which we may not have adequate insurance coverage .” Other Facilities Our corporate headquarters are located at 1200 17th Street, Suite 2100, Denver, Colorado 80202, and our telephone number at such address is (720) 375-9680.
For more information about potential risks that could affect us, see “ Risk Factors — Risks Related to Our Business Generally — Our business is subject to operating hazards that could result in substantial losses or liabilities for which we may not have adequate insurance coverage. ” Other Facilities 40 Table of Contents Our corporate headquarters are located at 1200 17th Street, Suite 2100, Denver, Colorado 80202, and our telephone number at such address is (720) 375-9680.
Although we commenced commercial operations with the initial injection of CO 2 waste at the Barnett Zero Project in November 2023, and have reached FID and entered into definitive agreements with respect to the Cotton Cove Project and the Eagle Ford Project, we have not reached FID with respect to or entered into the definitive agreements necessary to execute any of the other projects identified above.
Although we commenced commercial operations with the initial injection of CO 2 waste at the Barnett Zero Project in November 2023, reached FID, and entered into definitive agreements with respect to the Eagle Ford Project, the Cotton Cove Project, and the East Texas Project, we have not reached FID for, or entered into the definitive agreements necessary to execute, any of the other projects identified above.
We have multiple pore space opportunities for CO 2 injection, and we estimate the Cotton Cove Project will geologically sequester up to approximately 32,000 metric tons of CO 2 per year. The Cotton Cove Project is held through the BKV-BPP Cotton Cove Joint Venture, which is owned 51% by BKV dCarbon Ventures and 49% by BPPUS.
We have secured pore space for CO 2 injection, and we estimate the Cotton Cove Project will geologically sequester up to approximately 32,000 metric tons of CO 2 per year. The Cotton Cove Project is held through the BKV-BPP Cotton Cove Joint Venture, which is owned 51% by BKV dCarbon Ventures and 49% by BPPUS.
The following table provides our estimated proved reserves information prepared by Ryder Scott as of December 31, 2024, 2023, and 2022 and PV-10 Value and the Standardized Measure for each period.
The following table provides our estimated proved reserves information prepared by Ryder Scott as of December 31, 2025, 2024, and 2023 and PV-10 Value and the Standardized Measure for each period.
There can be no guarantee that we will be able to execute and complete any of these identified CCUS projects and there can be no guarantee that we will be able to achieve our net zero Scope 1, 2, and 3 emissions goals.
There can be no guarantee that we will be able to execute and complete any identified CCUS projects and there can be no guarantee that we will be able to achieve our net zero Scope 1, 2, and 3 emissions goals.
Ownership by our Directors and Officers in Other Entities Most of our directors now own, or our officers and other directors may own in the future, stock and options to purchase stock in one or more of Banpu or its related companies.
Ownership by our Directors and Officers in Other Entities Most of our non-independent directors now own, or our officers and other directors may own in the future, stock and options to purchase stock in one or more of Banpu or its related companies.
Our “Pad of the Future” program, which includes conversion of natural gas-powered instrument pneumatics to compressed air or electric power instruments on existing pads, combined with emission and leak surveys, is expected to significantly reduce our annual GHG emissions and improve pad efficiencies and operating revenue.
Our Pad of the Future program, which includes conversion of natural gas-powered instrument pneumatics to compressed air or electric power instruments on existing pads, combined with emission and leak surveys, is expected to significantly reduce our annual GHG emissions and improve pad efficiencies and operating revenue.
Our emissions estimates presented in this Form 10-K are based on information with respect to our owned and operated upstream and natural gas midstream businesses in the Barnett and NEPA through fiscal year 2023 and reported by BKV pursuant to the requirements of the federal Clean Air Act GHG reporting program regulations for petroleum and natural gas systems, Subpart C and Subpart W, as applicable.
Our emissions estimates presented in this Annual Report on Form 10-K are based on information with respect to our owned and operated upstream and natural gas midstream businesses in the Barnett and NEPA through fiscal year 2024 and reported by BKV pursuant to the requirements of the federal Clean Air Act GHG reporting program regulations for petroleum and natural gas systems, Subpart C and Subpart W, as applicable.
We believe our approach to reducing the emissions from our owned and operated upstream and natural gas midstream operations is repeatable and scalable in connection with future growth through continued investment and expansion of our “Pad of the Future” program and our emissions and leak surveys, as well as additional CCUS and solar projects.
We believe our approach to reducing the emissions from our owned and operated upstream and natural gas midstream operations is repeatable and scalable in connection with future growth through continued investment and expansion of our Pad of the Future program and our emissions and leak surveys, as well as additional CCUS and solar projects.
This study and other studies that may be undertaken by the EPA or other federal or state agencies could spur initiatives to further regulate hydraulic fracturing under the SDWA, the Toxic Substances Control Act, or other statutory and/or regulatory mechanisms, which could lead to operational delays, increased operating and compliance costs, and additional regulatory burdens that could make it more difficult or commercially impracticable for us 34 Table of Contents to perform hydraulic fracturing.
This study and other studies that may be undertaken by the EPA or other federal or state agencies could spur initiatives to further regulate hydraulic fracturing under the SDWA, the Toxic Substances Control Act, or other statutory and/or regulatory mechanisms, which could lead to operational delays, increased operating and compliance costs, and additional regulatory burdens that could make it more difficult or commercially impracticable for us to perform hydraulic fracturing.
(previously NASDAQ: NBL), an independent energy company engaged in worldwide crude oil and natural gas exploration and production, where he led large-scale shale development efforts of the DJ Basin in Colorado, from January 2011 to 40 Table of Contents October 2016. From June 1993 to January 2011, Mr.
(previously NASDAQ: NBL), an independent energy company engaged in worldwide crude oil and natural gas exploration and production, where he led large-scale shale development efforts of the DJ Basin in Colorado, from January 2011 to October 2016. From June 1993 to January 2011, Mr.
While the United States has yet to adopt comprehensive climate change legislation, the federal government has taken a series of administrative actions aimed at curtailing GHG emissions.
While the United States has yet to adopt comprehensive climate change legislation, in the past the federal government has taken a series of administrative actions aimed at curtailing GHG emissions.
He also served as Senior Reservoir Engineer of ExxonMobil Production Company from February 2008 to March 2011. Mr. Ngo received a BS in Civil Engineering, an MS in International Political Economy and an ME in Petroleum Engineering from the Colorado School of Mines. Mr. Ngo also received an MBA from the University of Colorado, Denver.
He also served as Senior Reservoir Engineer of ExxonMobil Production Company from February 2008 to March 2011. Mr. Ngo received a BS in Civil Engineering, an MS in International Political Economy and an ME in Petroleum Engineering from the Colorado School of Mines. Mr.
By combining our reserves into a growing asset base with vertically integrated components, we believe we can enhance margins and create a “closed loop” emissions reduction strategy that reduces Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses and captures margin across the value chain. Grow through opportunistic, synergistic acquisitions.
By combining our reserves into a growing asset base with vertically integrated components, we believe we can enhance margins and create a “closed-loop” emissions reduction strategy that reduces Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses and captures margin across the value chain. 13 Table of Contents Grow through opportunistic, synergistic acquisitions.
Also, in the course of our operations, we generate some amounts of non-exploration and 33 Table of Contents production industrial wastes that may be regulated as hazardous wastes if such wastes have hazardous characteristics or are listed as hazardous under RCRA. Oil Pollution Ac t .
Also, in the course of our operations, we generate some amounts of non-exploration and production industrial wastes that may be regulated as hazardous wastes if such wastes have hazardous characteristics or are listed as hazardous under RCRA. Oil Pollution Ac t .
Customers and Product Marketing We utilize an unaffiliated third party to market all of our natural gas production to various purchasers, which consist of credit-worthy counterparties, including utilities, LNG producers, industrial consumers, major corporations, and super majors in our industry.
Customers and Product Marketing We utilize an unaffiliated third party to market all of our natural gas production to various purchasers, which consist of creditworthy counterparties, including utilities, LNG producers, industrial consumers, major corporations, and super majors in our industry.
We also compete with other oil and gas companies to secure drilling rigs, frac fleets, sand, and other equipment and materials necessary for the drilling and completion of wells and in the recruiting and retaining of qualified personnel. Such materials, equipment, and labor may be in short supply from time to time.
We also compete with other oil and gas companies to secure drilling rigs, frac fleets, sand, and other equipment and materials necessary for the drilling and completion of wells and in the recruiting and retaining of qualified personnel. Occasionally, such materials, equipment, and labor may be in short supply.
In recent history, much colder than normal weather has induced wellhead freeze-offs in various regional supply markets, which ultimately lessens supply available to broader markets. Various weather events related to the summer months can similarly have detrimental effects on available supply also.
In recent history, much colder than normal weather has induced wellhead freeze-offs in various regional supply markets, which ultimately lessens supply available to broader markets. Various weather events related to the summer months may also have detrimental effects on available supply.
More recently, on March 8, 2024, the EPA published its Methane Rule, which took effect on May 7, 2024 and established requirements for methane emissions from existing and modified oil and gas sources and imposed additional requirements for new sources with respect to methane and volatile organic chemical emissions, including sources not previously regulated under the oil and gas source category.
More recently, on March 8, 2024, the EPA 37 Table of Contents published its Methane Rule, which took effect on May 7, 2024 and established requirements for methane emissions from existing and modified oil and gas sources and imposed additional requirements for new sources with respect to methane and volatile organic chemical emissions, including sources not previously regulated under the oil and gas source category.
The historical 12-month pricing average in our December 31, 2024 disclosures above does not reflect the prevailing natural gas and oil futures.
The historical 12-month pricing average in our December 31, 2025 disclosures above does not reflect the prevailing natural gas and oil futures.
Natural Gas Midstream 13 Table of Contents Through our ownership in midstream systems, we are engaged in the gathering, processing, and transportation of natural gas (which we refer to as our natural gas midstream business) that supports our upstream assets and third-party producers in the Barnett and NEPA.
Natural Gas Midstream Through our ownership in midstream systems, we are engaged in the gathering, processing, and transportation of natural gas (which we refer to as our natural gas midstream business) that supports our upstream assets and third-party producers in the Barnett and NEPA.
The decrease in our proved reserves and the PV-10 Value of those reserves as of December 31, 2023, as compared to December 31, 2022, is primarily due to lower commodity pricing. There are numerous uncertainties inherent in estimating quantities of natural gas, NGL, and oil reserves and their values, including many factors beyond our control.
The decrease in our proved reserves and the PV-10 Value of those reserves as of December 31, 2024, as compared to December 31, 2023, was primarily due to lower commodity pricing. There are numerous uncertainties inherent in estimating quantities of natural gas, NGL, and oil reserves and their values, including many factors beyond our control.
For example, in December 2016, the EPA and certain environmental organizations entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production-related oil and gas wastes from regulation as hazardous wastes under RCRA.
For example, in December 2016, the EPA and certain environmental organizations entered into a consent decree to address the EPA’s 35 Table of Contents alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production-related oil and gas wastes from regulation as hazardous wastes under RCRA.
These sales of our common stock resulted in net proceeds of $265.7 million after deducting underwriter fees and offering expenses of $17.0 million. All shares sold were registered pursuant to a registration statement on Form S-1 (File No. 333-268469), as amended, which was declared effective by the Securities and Exchange Commission (the “SEC”) on September 25, 2024.
These sales of our common stock resulted in net proceeds of $265.7 million after deducting underwriter fees and offering expenses of $17.0 million. All shares sold were registered pursuant to a registration statement on Form S-1 (File No. 333-268469), as amended, which was declared effective by the SEC on September 25, 2024.
We believe we can achieve this through reductions in and offsets to our owned and operated upstream and natural gas midstream emissions from our “Pad of the Future” emissions reductions program and emissions monitoring and leak surveys, the retirement of SRECs generated by the BKV-BPP Power Joint Venture’s solar facility, and executing CCUS projects.
We believe we can achieve this through reductions in and offsets to our owned and operated upstream and natural gas midstream emissions from our Pad of the Future emissions reductions program and emissions monitoring and leak surveys, the retirement of SRECs generated by the BKV-BPP Power Joint Venture’s solar facility, and executing CCUS projects.
Scope 3 emissions estimated using source Category 11 represent the majority of Scope 3 emissions from our owned and operated upstream and natural gas midstream operations, with minor contributions from other source categories. Additionally, our estimated Scope 3 emissions calculations assume that all natural gas produced is combusted and does not account for other potential end uses of natural gas.
Scope 3 emissions estimated for Category 11 represent over 90% of the Scope 3 emissions from our owned and operated upstream and natural gas midstream operations, with minor contributions from other source categories. Additionally, our estimated Scope 3 emissions calculations assume that all natural gas produced is combusted and does not account for other potential end uses of natural gas.
We rely on the credit worthiness of such third-party marketer, who collects directly from the purchasers and remits to us the total of all amounts collected on our behalf less their fee for making such sales.
We rely on the creditworthiness of such third-party marketer, who collects directly from the purchasers and remits to us the total of all amounts collected on our behalf less their fee for making such sales.
See “ Risk Factors - Risks Related to Our CCUS Business. ” (3) We may not receive 100% of the environmental attributes associated with CCUS projects funded in whole or in part by third parties, and, in such cases, we expect to have the right to purchase such environmental attributes BKV would not otherwise receive.
See “ Risk Factors - Risks Related to Our CCUS Business. ” (2) We may not receive 100% of the environmental attributes associated with CCUS projects funded in whole or in part by third parties, and, in such cases, we expect to have the ability to purchase such environmental attributes BKV would not otherwise receive.
Extensions and discoveries added 139.2 Bcfe of proved undeveloped reserves across 98.0 gross (89.4 net) locations, driven by our optimized capital allocation and enhanced drilling program, which reduced costs and extended lateral lengths during the year ended December 31, 2024.
Extensions and discoveries added 139.2 Bcfe of proved undeveloped reserves across 16.0 gross (14.4 net) locations, driven by our optimized capital allocation and enhanced drilling program, which reduced costs and extended lateral lengths during the year ended December 31, 2024.
Encourage innovation. Our distinctive culture encourages innovation with a value-driven focus that feeds into our competitive advantage. For example, our emphasis on the efficient application of modern technology led to the development of our “Pad of the Future” program, our advancements in Barnett refracturing, and other operational improvements.
Encourage innovation. Our distinctive culture encourages innovation with a value-driven focus that feeds into our competitive advantage. For example, our emphasis on the efficient application of modern technology led to the development of our Pad of the Future program, our advancements in Barnett refracturing, and other operational improvements.
Additionally, BKV dCarbon Ventures will manage the BKV-BPP Cotton Cove Joint Venture and leverage our existing organization to provide marketing, engineering, finance, operations, project management, accounting, and other administrative services to the BKV-BPP Cotton Cove Joint Venture, in each case for an annual fee plus expenses. Eagle Ford Project .
Additionally, BKV dCarbon Ventures will manage the BKV-BPP Cotton Cove Joint Venture and leverage our existing organization to provide marketing, engineering, finance, operations, project management, accounting, and other administrative services to the BKV-BPP Cotton Cove Joint Venture, in each case for an annual fee plus expenses. East Texas Project .
Our Operations Natural Gas Production We are engaged in the acquisition, operation and development of natural gas and NGL properties primarily located in the Barnett and in NEPA. As of December 31, 2024, our total acreage position was approximately 481,000 net acres, substantially all of which was held by production.
Our Operations Natural Gas Production We are engaged in the acquisition, operation and development of natural gas and NGL properties primarily located in the Barnett and in NEPA. As of December 31, 2025, our total acreage position was approximately 563,000 net acres, substantially all of which was held by production.
We had an average working interest in our operated wells in the Barnett of approximately 97.2% as of December 31, 2024 and an Effective NRI in the Barnett of approximately 80.2%. As of December 31, 2024, our NEPA acreage position was approximately 19,100 net acres, 97% of which was held by production.
We had an average working interest in our operated wells in the Barnett of approximately 96.5% as of December 31, 2025 and an Effective NRI in the Barnett of approximately 80.2%. As of December 31, 2025, our NEPA acreage position was approximately 19,100 net acres, 97% of which was held by production.
Ryder Scott relies on various data provided by our internal reservoir engineering team in preparing its reserves estimates, including such items as oil and natural gas prices, ownership interests, production information, operating costs, planned capital expenditures and other technical data.
Ryder Scott relies on various data provided by our internal reservoir engineering team in preparing its reserves estimates, including such items as ownership interests, production information, operating costs, planned capital expenditures and other technical data.
The report found that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells.
The report found that hydraulic fracturing 36 Table of Contents activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells.
(3) The following table provides a reconciliation of the Standardized Measure to PV-10 (applying NYMEX Strip Pricing) with respect to estimated proved reserves as of December 31, 2024: December 31, 2024 PV-10 (millions) $ 2,446 Present value of future income taxes discounted at 10% (456) Standardized Measure $ 1,990 Preparation of Reserves Estimates and Internal Controls Our reserves estimates as of December 31, 2024, 2023, and 2022 included in this Annual Report on Form 10-K are based on reports prepared by Ryder Scott, our independent reserves engineer, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC in effect at such time.
(3) The following table provides a reconciliation of the Standardized Measure to PV-10 (applying NYMEX Strip Pricing) with respect to estimated proved reserves as of December 31, 2025: December 31, 2025 PV-10 (millions) $ 3,082 Present value of future income taxes discounted at 10% (508) Standardized Measure $ 2,574 Preparation of Reserves Estimates and Internal Controls Our reserves estimates as of December 31, 2025, 2024, and 2023 included in this Annual Report on Form 10-K are based on reports prepared by Ryder Scott, our independent reserves engineer, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC in effect at such time.
Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2024, 2023, and 2022 were approximately $135.1 million, $360.7 million, and $1,089.6 million, respectively, over the next five years, substantially all of which we expect to finance through cash flow from operations and/or borrowings under our RBL Credit Agreement.
Estimated future development costs relating to the development of our proved undeveloped reserves at December 31, 2025, 2024, and 2023, were approximately $1.0 billion, $135.1 million, and $360.7 million, respectively, over the next five years, substantially all of which we expect to finance through cash flow from operations and/or borrowings under our RBL Credit Agreement.
We expect that production of Carbon Sequestered Gas will be achieved by bundling RSG with carbon credits sufficient to offset the estimated emissions associated with the production, gathering, and boosting of such RSG, as well as the estimated emissions from its transmission, distribution (if applicable), and ultimate combustion, with the quantified emissions and the requisite volume of CCUS offsets being third-party certified.
We expect that production of Carbon Sequestered Gas will be achieved by bundling our low carbon intensity produced natural gas with carbon credits sufficient to offset the estimated emissions associated with the production, gathering, and boosting of such gas, as well as the estimated emissions from its transmission, distribution (if applicable), and ultimate combustion, with the quantified emissions and the requisite volume of CCUS offsets being third-party certified.
We currently engage third party consultants to develop and review our Scope 3 emissions estimates. Planned Path to Net Zero (Scope 1 and 2) Pad of the Future . Our “Pad of the Future” program implements pad level design improvements to reduce pad level usage of natural gas, reduce GHG emissions and maintain operational continuity.
We currently engage third party consultants to develop and review our Scope 3 emissions estimates. Planned Path to Net Zero (Scope 1 and 2) Pad of the Future . Our Pad of the Future program has implemented pad level design improvements to reduce pad level usage of natural gas, reduce GHG emissions, and maintain operational continuity.
There can be no assurance that any of these identified potential CCUS projects, the Barnett Zero Project, or any other CCUS project will achieve the forecasted sequestration volumes, and we may not commence sequestration operations for any of the projects identified above by the anticipated timeframe, or at all.
There can be no assurance that these potential CCUS projects, the projects further described herein, or any other CCUS project will achieve the forecasted sequestration volumes, and we may not commence sequestration operations for any of the projects identified above by the anticipated timeframe, or at all.
As of December 31, 2024 we have recorded asset retirement obligations of $201.2 million attributable to these activities. The regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules, and regulations affect our operations, as well as the oil and gas exploration and production industry in general.
As of December 31, 2025 we have recorded asset retirement obligations of $233.3 million attributable to these activities. The regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules, and regulations affect our operations, as well as the oil and gas exploration and production industry in general.
We rely on Ryder Scott’s expertise to ensure that our reserves estimates are prepared in compliance with SEC rules, regulations, and disclosure guidelines and that appropriate geologic, petroleum engineering, and evaluation principles and techniques are applied in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers titled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of June 2019).” A copy of Ryder Scott’s reserve reports are included as exhibits to this Annual Report on Form 10-K. 29 Table of Contents Our internal staff of petroleum engineers, geoscience professionals, operations, land, finance and accounting, and marketing personnel prior to our annual reserves process, work closely together to ensure the integrity, accuracy and timeliness of data so that our reservoir engineering team can review such data and then furnish it to, and work with, our independent reserves engineers in their reserves evaluation process.
We rely on Ryder Scott’s expertise to ensure that our reserves estimates are prepared in compliance with SEC rules, regulations, and disclosure guidelines and that appropriate geologic, petroleum engineering, and evaluation principles and techniques are applied in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers titled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of June 2019).” A copy of Ryder Scott’s reserve reports are included as exhibits to this Annual Report on Form 10-K. 31 Table of Contents Prior to our annual reserves process, our internal staff of petroleum engineers, geoscience professionals, operations, land, finance and accounting, and marketing personnel work closely together to ensure the integrity, accuracy, and timeliness of our reserves data.
Temple I and Temple II have baseload 14 Table of Contents design heat rates of approximately 6,904 Btu/kWh and 6,950 Btu/kWh, respectively, which are below the ERCOT Combined Cycle Gas Turbines (“CCGT”) average.
Temple I and Temple II have baseload design heat rates of approximately 6,904 Btu/kWh and 6,950 Btu/kWh, respectively, which are below the ERCOT Combined Cycle Gas Turbines average.
If we are unable to recover or pass through a significant portion of our costs related to complying with current and future regulations relating to climate change and GHGs, it could materially affect our operations and financial condition.
These compliance costs could adversely impact our future business. If we are unable to recover or pass through a significant portion of our costs related to complying with current and future regulations relating to climate change and GHGs, it could materially affect our operations and financial condition.
All NGLs under the Bridgeport contract are sold to EnLink at Mont Belvieu pricing subject to a market-based transport and fractionation differential. There are no MVCs associated with the natural gas gathering agreements for the assets we acquired in the Devon Barnett Acquisition.
All NGLs under the Bridgeport contract are sold to ONEOK at Mont Belvieu pricing subject to a 15 Table of Contents market-based transport and fractionation differential. There are no MVCs associated with the natural gas gathering agreements for the assets we acquired in the Devon Barnett Acquisition.
NEPA In NEPA, we own and operate approximately 16 miles of natural gas gathering pipelines, 14 miles of freshwater distribution pipelines, and six gas compression units in NEPA. As part of our sale of BKV Chaffee Corners, LLC (“Chaffee”) in June 2024, we sold our minority non-operated ownership interest in a Repsol Oil & Gas operated midstream system in NEPA.
NEPA In NEPA, we own and operate approximately 16 miles of natural gas gathering pipelines, 14 miles of freshwater distribution pipelines, and ten gas compression units in NEPA. As part of our sale of Chaffee in June 2024, we sold our minority non-operated ownership interest in a Repsol Oil & Gas operated midstream system in NEPA.
We believe Carbon Sequestered Gas could potentially provide a decarbonized, certified, and qualified fuel and retired credits bundle that is a differentiated and premium product. In March 2024, BKV entered into a contract with Kiewit Infrastructure South Co., a subsidiary of Kiewit Corporation (“Kiewit”), for the sale and purchase of up to 100 MMBtu/d of our Carbon Sequestered Gas.
We believe Carbon Sequestered Gas could potentially provide a decarbonized, certified, and qualified fuel and retired credits bundle that is a differentiated and premium product. We have a contract with Kiewit Infrastructure South Co., a subsidiary of Kiewit Corporation (“Kiewit”), for the sale and purchase of up to 100 MMBtu/d of our Carbon Sequestered Gas.
We have filed applications to seek Class VI permits for two of these industrial projects, one of which is in the State of Louisiana. The U.S.
We have filed applications to seek Class VI permits for three of these industrial projects, two of which are in the State of Louisiana and one of which is in the State of Texas. The U.S.
Scope 3 mass emissions are calculated using the EPA’s prescribed emissions factors for the speciated natural gas (methane and ethane) as well as NGLs, assuming Y-grade NGLs. CO 2e emissions are estimated using AR4 Global Warming Potentials, similar to those used by the EPA.
Scope 3 mass emissions are calculated using the EPA’s prescribed emissions factors for the speciated natural gas (methane and ethane) as well as NGLs, assuming Y-grade NGLs. Effective as of 2024, the Company's Scope 3 CO 2e emissions are estimated using AR5 Global Warming Potentials, similar to those used by the EPA.
As discussed in “— Carbon Capture, Utilization and Sequestration ,” above, we are currently operating the Barnett Zero Project and have identified additional potential CCUS projects that we believe are commercially viable and estimate would have a combined forecasted annual volume of carbon capture and sequestration of approximately 15.6 Mtpy CO 2e by the early 2030s, which represents a majority of our current Scope 1, 2, and 3 annual emissions from our owned and operated upstream and natural gas midstream businesses.
As discussed in “— Carbon Capture, Utilization and Sequestration ,” above, we are currently operating the Barnett Zero Project owned by the BKV-CIP Joint Venture and have identified additional potential CCUS projects that we believe are commercially viable and estimate would have a combined forecasted annual volume of carbon capture and sequestration of approximately 19.0 Mtpy CO 2 during the early 2030s, which represents a majority of our current Scope 1, 2, and 3 annual emissions from our owned and operated upstream and natural gas midstream businesses.
Kalnin received an HBA in Finance from the University of Western Ontario and an MBA from Northwestern University’s Kellogg School of Management. We believe that Mr. Kalnin’s extensive industry experience and demonstrated leadership capabilities throughout our growth make him qualified to serve on our board of directors. John T.
Kalnin received an HBA in Finance from the University of Western Ontario and an MBA from Northwestern University’s Kellogg School of Management. We believe that Mr. Kalnin’s extensive industry experience and demonstrated leadership capabilities throughout our growth make him qualified to serve on our board of directors. 41 Table of Contents David R.
During the period, ten wells were completed in the Barnett and three wells were completed in NEPA, all of which were net productive. As of December 31, 2024, all drilled and uncompleted wells from prior year programs had been completed and began production.
During the year ended December 31, 2024, ten wells were completed in the Barnett and three wells were completed in NEPA, all of which were net productive. All drilled and uncompleted wells from prior year programs had been completed and placed into production as of December 31, 2024.
Our development programs during the year ended December 31, 2024 focused on refracturing under-stimulated wells and designing and drilling new wells in the Barnett, and completing drilled and uncompleted wells in NEPA.
Our development programs during the year ended December 31, 2025 focused on refracturing under-stimulated wells and designing and drilling new wells in the Barnett, and designing, completing, and drilling new wells in NEPA.
Our internal reservoir engineering team consists of qualified petroleum engineers who maintain our internal evaluation of reserves and compare our information to the reserves prepared by Ryder Scott.
Our internal reservoir engineering team consists of qualified petroleum engineers who maintain our internal evaluation of reserves and compare our information to the reserves prepared by Ryder Scott. The internal reservoir engineering team reports directly to our President of Upstream.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Any of the above could materially and adversely affect our ability to execute on our CCUS strategy, the value of any CCUS project we develop through a current or potential future joint venture, and to reach our near term and long term net zero goals on our anticipated time frame or at all, as well as on our liquidity, financial condition, and results of operations.
Any of the above could materially and adversely affect our ability to execute on our CCUS strategy, the value of any CCUS project we develop through a current or potential future joint venture, and our ability to reach our near-term and long-term net zero goals on our anticipated time frame or at all, as well as on our liquidity, financial condition, and results of operations.
Energy conservation measures, alternative fuel requirements, governmental requirements for renewable energy resources, increasing consumer demand for alternatives to natural gas, NGLs, and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas, NGLs, and oil.
Energy conservation measures and technological advances could reduce demand for natural gas, NGLs, and oil. Energy conservation measures, alternative fuel requirements, governmental requirements for renewable energy resources, increasing consumer demand for alternatives to natural gas, NGLs, and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas, NGLs, and oil.
In addition, Christopher Kalnin serves as a member of Banpu’s Executive Committee with responsibilities to Banpu to, among other things, manage all aspects of Banpu’s business in North America. Although our corporate opportunity policy requires Mr.
In addition, Christopher Kalnin serves as a member of Banpu’s Executive Committee with responsibilities to Banpu to, among other things, manage all aspects of Banpu’s business in North America. Although our corporate opportunity policy requires Mr.
There may be organized opposition to carbon capture, including our projects, alleging concerns relating to the environment, environmental justice, health or safety, or the federal and state governments may cease supporting carbon capture and sequestration. • In addition to the BKV-BPP Cotton Cove Joint Venture, the development of a CCUS project may require us to enter into long-term joint ventures with large carbon emitters (which may need to finance and build, often over a multi-year period, the equipment to capture CO 2 emissions from various industrial processes) and operators of infrastructure for transporting CO 2 (or other GHGs), and we may not be able to do so on agreeable terms, or at all.
There may be organized opposition to carbon capture, including our projects, alleging concerns relating to the environment, environmental justice, health or safety, or the federal and/or state governments may cease supporting carbon capture and sequestration. • In addition to the BKV-CIP Joint Venture and the BKV-BPP Cotton Cove Joint Venture, the development of a CCUS project may require us to enter into long-term joint ventures with large carbon emitters (which may need to finance and build, often over a multi-year period, the equipment to capture CO 2 emissions from various industrial processes) and operators of infrastructure for transporting CO 2 (or other GHGs), and we may not be able to do so on agreeable terms, or at all.
Our level of indebtedness could affect our operations in several ways, including the following: • a significant portion of our cash flows could be used to service our indebtedness; • a high level of debt would increase our vulnerability to general adverse economic and industry conditions; • the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay dividends on our common stock, and make certain investments; • a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing; • our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; and • a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate, or other purposes.
Our level of indebtedness could affect our operations in several ways, including the following: • a significant portion of our cash flows could be used to service our indebtedness; • a high level of debt would increase our vulnerability to general adverse economic and industry conditions, and increase our interest rates; • the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay dividends on our common stock, and make certain investments; • a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing; • our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; and • a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate, or other purposes.
For example, the international community gathered in Glasgow, Scotland, U.K. at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), and the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals.
For example, the international community gathered in Glasgow, Scotland, U.K. at the 26th Conference to the Parties (“COP26”) on the UN Framework Convention on Climate Change (“UNFCCC”), and the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals.
Our operations are subject to a series of risks relating to climate change that could result in increased compliance or operating costs, limit the areas in which we may conduct natural gas and NGL exploration and production activities, and reduce demand for the natural gas and NGLs we produce. Climate change continues to attract considerable public and scientific attention.
Our operations are subject to a series of risks relating to climate change that could result in increased compliance or operating costs, limit the areas in which we may conduct natural gas and NGL exploration and production activities, and reduce demand for the natural gas and NGLs we produce. Climate change continues to attract considerable public, political, and scientific attention.
Climate change could have an effect on the severity of weather (including hurricanes, droughts, and floods), sea levels, the arability of farmland, changes in temperature and other meteorological patterns, and water availability and quality. If such effects were to occur, our development and production operations have the potential to be adversely affected.
Climate change could have an effect on the severity of weather (including hurricanes, droughts, floods, and freezes), sea levels, the arability of farmland, changes in temperature and other meteorological patterns, and water availability and quality. If such effects were to occur, our development and production operations have the potential to be adversely affected.
We may experience certain issues and encounter risks in our drilling operations, including: • mechanical and instrument or tool failures; • drilling difficulties associated with drilling in swelling clay or shales and unconsolidated formation, particularly in select parts of our Barnett development acreage; • wellbore instability and other geological hazards; • loss of well control and associated hydrocarbon release and/or natural gas clouds; • loss of drilling fluids circulation; surface spills of various drilling, or well fluids; • subsurface collision with existing wells; 46 Table of Contents • proximity of adjacent water wells or aquifers; • inability to establish drilling fluid circulation; • loss or compromise of drill pipe or casing integrity; • surface pumping operations and associated pressure and hydrocarbon hazards; • stuck and lost-in-hole tools, drill pipe, or casing; • large drilling equipment and machinery, including electrical hazards; • insufficient cementing of casing causing unwanted casing pressure or fluid migration; • surface overpressure events from large machinery (horsepower), equipment, or well pressure; • fines and violations related to relevant laws and regulations; • fires and explosions; • personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation, and trenching; • structural damage and collapse to large equipment and machinery; • major damage or malfunction to key equipment or processes; • in certain instances, close proximity of operations to residences and/or communities; and • other typical shale basin drilling challenges and risks.
We may experience certain issues and encounter risks in our drilling operations, including: • mechanical and instrument or tool failures; • drilling difficulties associated with drilling in swelling clay or shales and unconsolidated formation, particularly in select parts of our Barnett development acreage; • wellbore instability and other geological hazards; • loss of well control and associated hydrocarbon release and/or natural gas clouds; • loss of drilling fluids circulation; surface spills of various drilling, or well fluids; • subsurface collision with existing wells; • proximity of adjacent water wells or aquifers; • inability to establish drilling fluid circulation; • loss or compromise of drill pipe or casing integrity; • surface pumping operations and associated pressure and hydrocarbon hazards; • stuck and lost-in-hole tools, drill pipe, or casing; • large drilling equipment and machinery, including electrical hazards; • insufficient cementing of casing causing unwanted casing pressure or fluid migration; • surface overpressure events from large machinery (horsepower), equipment, or well pressure; • fines and violations related to relevant laws and regulations; • fires and explosions; • personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation, and trenching; • structural damage and collapse to large equipment and machinery; • major damage or malfunction to key equipment or processes; • in certain instances, close proximity of operations to residences and/or communities; and • other typical shale basin drilling challenges and risks.
We experience certain issues and encounter risks in our hydraulic fracturing, workover, and completions activities, including: • mechanical and instrument or tool failures; • loss of well control and associated hydrocarbon release and/or natural gas clouds; • well kick or flowback during completion or fracturing operations; • lost or stuck in hole wireline, coiled tubing, or workover strings and tools; • loss or compromise of workover string, tubing, or casing integrity; • large completions, wireline, coiled tubing, and workover rig equipment and machinery, including electrical hazards; • insufficient cementing of casing causing unwanted casing pressure or fluid migration while fracturing or thereafter; • proximity of adjacent water wells or aquifers and adjacent producing wells; • surface spills of various fracturing, freshwater, or well fluids or chemicals; • surface pumping and flowback operations and associated pressure and hydrocarbon hazards; • surface overpressure events from large machinery (horsepower), equipment, or well pressure; • fines and violations related to relevant laws and regulations; • fires and explosions; • personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation, and trenching; • structural damage and collapse to large equipment and machinery; • major damage or malfunction to key equipment or processes; • in certain instances, close proximity of operations to residences and/or communities; and • other typical fracturing, workover, and completion challenges and risks.
We experience certain issues and encounter risks in our hydraulic fracturing, workover, and completions activities, including: • mechanical and instrument or tool failures; • loss of well control and associated hydrocarbon release and/or natural gas clouds; • well kick or flowback during completion or fracturing operations; • lost or stuck in hole wireline, coiled tubing, or workover strings and tools; • loss or compromise of workover string, tubing, or casing integrity; • large completions, wireline, coiled tubing, and workover rig equipment and machinery, including electrical hazards; • insufficient cementing of casing causing unwanted casing pressure or fluid migration while fracturing or thereafter; • proximity of adjacent water wells or aquifers and adjacent producing wells; • surface spills of various fracturing, freshwater, or well fluids or chemicals; • surface pumping and flowback operations and associated pressure and hydrocarbon hazards; • surface overpressure events from large machinery (horsepower), equipment, or well pressure; • fines and violations related to relevant laws and regulations; • fires and explosions; 48 Table of Contents • personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation, and trenching; • structural damage and collapse to large equipment and machinery; • major damage or malfunction to key equipment or processes; • in certain instances, close proximity of operations to residences and/or communities; and • other typical fracturing, workover, and completion challenges and risks.
Future activist efforts could result in the following: • delay or denial of drilling permits; • shortening of lease terms and reduction in lease size; 66 Table of Contents • restrictions on installation or operation of production, gathering, or processing facilities; • restrictions on the use of certain operating practices, such as hydraulic fracturing, or disposal of related waste materials, such as hydraulic fracking fluids and production; • increased severance and/or other taxes; • cyber-attacks; • legal challenges or lawsuits; • negative publicity about our business or the natural gas, NGL, and oil industry in general; • increased costs of doing business; • reduction in demand for our products; and • other adverse effects on our ability to develop our properties and expand production.
Future activist efforts could result in the following: • delay or denial of drilling permits; • shortening of lease terms and reduction in lease size; • restrictions on installation or operation of production, gathering, or processing facilities; 69 Table of Contents • restrictions on the use of certain operating practices, such as hydraulic fracturing, or disposal of related waste materials, such as hydraulic fracking fluids and production; • increased severance and/or other taxes; • cyber-attacks; • legal challenges or lawsuits; • negative publicity about our business or the natural gas, NGL, and oil industry in general; • increased costs of doing business; • reduction in demand for our products; and • other adverse effects on our ability to develop our properties and expand production.
Following this date, Banpu and its affiliates will have no obligation to provide any additional funding, and instead, we expect to fund our capital expenditures for our upstream, midstream, and power businesses through cash flows from operations and from borrowings under our RBL Credit Agreement.
Following this date, Banpu and its affiliates have no obligation to provide any additional funding, and instead, we expect to fund our capital expenditures for our upstream, midstream, and power businesses through cash flows from operations and from borrowings under our RBL Credit Agreement.
In operating our midstream and production facilities, from time to time we experience certain issues and encounter risks, which include the following: • mechanical and instrument or tool failures; 55 Table of Contents • loss of well, pressure vessel, tank, or other related equipment control and associated hydrocarbon release and/or natural gas clouds; • loss or compromise of casing integrity during production; • unwanted casing pressure or fluid migration during production operations; • unwanted migration of sequestered carbon dioxide or other fluids in injection wells; • temporary and permanent surface facility operations and associated pressure and hydrocarbon hazards; • surface overpressure events and other hazards resulting from machinery (horsepower), equipment, or well pressure; • fines and violations related to relevant laws and regulations; • fires and explosions; • pipeline loss of containment due to integrity issues, pipeline strikes, or other reasons and associated hydrocarbon release; • personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation, and trenching; • major damage or malfunction to key equipment or processes; • structural damage and collapse to equipment and machinery; • in certain instances, close proximity of operations to residences, and/or communities; and • other typical midstream and production facilities challenges and risks.
In operating our midstream and production facilities, from time to time we experience certain issues and encounter risks, which include the following: • mechanical and instrument or tool failures; • loss of well, pressure vessel, tank, or other related equipment control and associated hydrocarbon release and/or natural gas clouds; • loss or compromise of casing integrity during production; • unwanted casing pressure or fluid migration during production operations; • unwanted migration of sequestered carbon dioxide or other fluids in injection wells; • temporary and permanent surface facility operations and associated pressure and hydrocarbon hazards; • surface overpressure events and other hazards resulting from machinery (horsepower), equipment, or well pressure; • fines and violations related to relevant laws and regulations; • fires and explosions; • pipeline loss of containment due to integrity issues, pipeline strikes, or other reasons and associated hydrocarbon release; • personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation, and trenching; • major damage or malfunction to key equipment or processes; • structural damage and collapse to equipment and machinery; • in certain instances, close proximity of operations to residences, and/or communities; and • other typical midstream and production facilities challenges and risks.
There can be no assurances that we will be able to execute on our CCUS strategy and continue to successfully operate the Barnett Zero Project with EnLink in the Barnett, or successfully develop the Cotton Cove Project with BPPUS, the Eagle Ford Project, or any future CCUS projects and any failure to do so in whole or in any significant part could have a material adverse effect on our ability to reach our near-term and long-term net zero goals on our anticipated time frame or at all, as well as on our liquidity, financial condition, and results of operations.
There can be no assurances that we will be able to execute on our CCUS strategy and continue to successfully operate the Barnett Zero Project with ONEOK in the Barnett, or successfully develop the Eagle Ford Project and the Cotton Cove Project with BPPUS, or any future CCUS projects and any failure to do so in whole or in any significant part could have a material adverse effect on our ability to reach our near-term and long-term net zero goals on our anticipated time frame or at all, as well as on our liquidity, financial condition, and results of operations.
Various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions.
Further, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions.
Although we commenced commercial operations with the initial injection of CO 2 waste at the Barnett Zero Project in November 2023, and have reached FID and entered into definitive agreements with respect to the Cotton Cove Project and the Eagle Ford Project, we have not reached FID with respect to or entered into the definitive agreements necessary to execute any of the other potential projects described in “ Business - Our Operations - Carbon Capture, Utilization, and Sequestration ” and may not be able to reach agreements on terms acceptable to us, or to achieve our projected timeline for commercial operations.
Although we commenced commercial operations with the initial injection of CO 2 waste at the Barnett Zero Project in November 2023, and have reached FID and entered into definitive agreements with respect to the Eagle Ford Project, the Cotton Cove Project, and the East Texas Project, we have not reached FID with respect to or entered into the definitive agreements necessary to execute any of the other potential projects described in “ Business - Our Operations - Carbon Capture, Utilization, and Sequestration ” and may not be able to reach agreements on terms acceptable to us, or to achieve our projected timeline for commercial operations.
The agreements governing our indebtedness contain restrictive covenants that limit our ability to, among other things: • incur additional debt; • incur additional liens; • sell, transfer, or dispose of assets; • merge or consolidate, wind-up, dissolve or liquidate; • pay dividends and distributions on, or repurchases of, equity; • make acquisitions and investments, other than direct investments in natural gas, NGL, and oil properties and other assets in permitted lines of business; • enter into certain transactions with our affiliates; • enter into sale-leaseback transactions; • make optional or voluntary payment of subordinated debt and certain other debt; • change the nature of our business; • change our fiscal year to make changes to the accounting treatment or reporting practices; • amend constituent documents; and • enter into certain hedging transactions.
The agreements governing our indebtedness contain restrictive covenants that limit our ability to, among other things: • incur additional debt; • incur additional liens; • sell, transfer, or dispose of assets; • merge or consolidate, wind-up, dissolve or liquidate; • pay dividends and distributions on, or repurchases of, equity; • make acquisitions and investments, other than direct investments in natural gas, NGL, and oil properties and other assets in permitted lines of business; • enter into certain transactions with our affiliates; • enter into sale-leaseback transactions; • make optional or voluntary payment of subordinated debt and certain other debt; • change the nature of our business; • change our fiscal year to make changes to the accounting treatment or reporting practices; • amend constituent documents; and 62 Table of Contents • enter into certain hedging transactions.
Alternatively, if a court were to find these provisions of our governing documents inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our financial condition, results of operations, and cash flows. ITEM 1B.
Alternatively, if a court were to find these provisions of our governing documents inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our financial condition, results of operations, and cash flows.
Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies, which could result in the restriction, delay, or cancellation of drilling or development programs or production activities and affect our access to capital for potential growth projects.
Institutional lenders and institutional investors who provide financing to fossil-fuel energy companies also have become more attentive to sustainable financing practices and some of them may elect not to provide funding for fossil fuel energy companies, which could result in the restriction, delay, or cancellation of drilling or development programs or production activities and affect our access to capital for potential growth projects.
Our certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by law, be the sole and exclusive forum for any (i) derivative action or proceeding brought on behalf of the Company, (ii) action asserting a claim of breach of a fiduciary duty owed by any director, officer or employee of the Company to the Company or our stockholders, (iii) action asserting a claim against the Company or any director or officer of the Company arising pursuant to any provision of the Delaware General Corporation Law or our governing documents, or (iv) action asserting a claim against the Company or any director, officer or employee of the Company, which claim is governed by the internal affairs doctrine.
Our certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by law, be the sole and exclusive forum for any (i) derivative action or proceeding brought on behalf of the Company, (ii) action asserting a claim of breach of a fiduciary duty owed by any director, officer or employee of the Company to the Company or our stockholders, (iii) action asserting a claim against the Company or any director or officer of the Company arising pursuant to any provision of the Delaware General Corporation Law or our governing documents, or (iv) action asserting a claim against the Company or 88 Table of Contents any director, officer or employee of the Company, which claim is governed by the internal affairs doctrine.
Different methodologies may be required to satisfy various regulatory and non-regulatory requirements regarding GHG emissions/sequestration at one or more of our projects, including, but not limited to, compliance with the EPA mandatory Greenhouse Gas Reporting Program. • CCUS injection wells and carbon sequestration reservoirs or formations may experience integrity, operating, or boundary breaches resulting in additional costs, liability and risk from undesired well casing pressures, breakthrough of injected CO 2 to the land surface, CO 2 plume migration outside of expected or modeled results into undesired or unwanted surface or subsurface areas, well integrity issues, or various other outcomes. • Carbon capture may be viewed as a pathway to the continued use of fossil fuels, notwithstanding that CO 2 emissions are intended to be captured.
Different methodologies may be required to satisfy various regulatory and non-regulatory requirements regarding GHG emissions/sequestration at one or more of our projects, including, but not limited to, compliance with any greenhouse gas reporting requirements. • CCUS injection wells and carbon sequestration reservoirs or formations may experience integrity, operating, or boundary breaches resulting in additional costs, liability and risk from undesired well casing pressures, breakthrough of injected CO 2 to the land surface, CO 2 plume migration outside of expected or modeled results into undesired or unwanted surface or subsurface areas, well integrity issues, or various other outcomes. • Carbon capture may be viewed as a pathway to the continued use of fossil fuels, notwithstanding that CO 2 emissions are intended to be captured.
Potential conflicts of interest or disputes may arise between Banpu and us in a number of areas relating to our past or ongoing relationships, including: • tax, employee benefits, indemnification, and other matters arising from our status as a publicly traded company; • employee retention and recruiting; • corporate opportunities that may be attractive to both Banpu and us; • the arrangements governing the BKV-BPP Power Joint Venture, BKV-BPP Cotton Cove Joint Venture, and any other new commercial arrangements between the Company and affiliates of Banpu in the future; and • sales or other disposals by Banpu of all or a portion of its interest in us.
Potential conflicts of interest or disputes may arise between Banpu and us in a number of areas relating to our past or ongoing relationships, including: • tax, employee benefits, indemnification, and other matters arising from our status as a publicly traded company; • employee retention and recruiting; • corporate opportunities that may be attractive to both Banpu and us; 83 Table of Contents • the arrangements governing the BKV-BPP Power Joint Venture, BKV-BPP Cotton Cove Joint Venture, and any other new commercial arrangements between the Company and affiliates of Banpu in the future; and • sales or other disposals by Banpu of all or a portion of its interest in us.
As a result, we are not insured against any losses 67 Table of Contents resulting from the death of our key employees. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, future business prospects, financial condition, results of operations, and cash flows.
As a result, we are not insured against any losses resulting from the death of our key employees. The loss of the services of our senior management or technical personnel 70 Table of Contents could have a material adverse effect on our business, future business prospects, financial condition, results of operations, and cash flows.
CFIUS may decide to block or delay transactions that could benefit our stockholders, impose conditions with respect to such transactions or request the President of the United States to order us to divest all or a portion of the assets or companies we acquired without first obtaining CFIUS approval, which may limit the attractiveness of, delay or prevent us from pursuing certain target companies or assets that we believe would otherwise be beneficial to us 76 Table of Contents and our stockholders, any of which could have a material adverse effect on our financial condition, results of operations, and cash flows.
CFIUS may decide to block or delay transactions that could benefit our stockholders, impose conditions with respect to such transactions or request the President of the United States to order us to divest all or a portion of the assets or companies we acquired without first obtaining CFIUS approval, which may limit the attractiveness of, delay or prevent us from pursuing certain target companies or assets that we believe would otherwise be beneficial to us and our stockholders, any of which could have a material adverse effect on our financial condition, results of operations, and cash flows.
Conflicts of interest between us and Banpu could be resolved in a manner unfavorable to us and our other stockholders. ” Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. We may make acquisitions of properties or businesses that complement or expand our current business in the future.
Conflicts of interest between us and Banpu could be resolved in a manner unfavorable to us and our other stockholders. ” Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. We have and may continue to make acquisitions of properties or businesses that complement or expand our current business in the future.
We may 74 Table of Contents have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment if any of the following occur: (i) water produced from our projects fails to meet the quality requirements set by relevant regulatory agencies, (ii) our wells produce water in excess of the allowed volumetric permit limits, (iii) the disposal wells fail to comply with applicable regulatory requirements, or (iv) we are unable to secure access to disposal wells with sufficient capacity to handle all of the produced water.
We may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment if any of the following occur: (i) water produced from our projects fails to meet the quality requirements set by relevant regulatory agencies, (ii) our wells produce water in excess of the allowed volumetric permit limits, (iii) the disposal wells fail to comply with applicable regulatory requirements, or (iv) we are unable to secure access to disposal wells with sufficient capacity to handle all of the produced water.
These decisions could include: • corporate opportunities; • the impact that operating or capital decisions (including the incurrence of indebtedness) relating to our business may have on Banpu’s consolidated financial statements or current or future indebtedness (including related covenants); • business combinations involving us; • our dividend and stock repurchase policies; • compensation and benefit programs and other human resources policy decisions; • management of stock ownership; • the payment of dividends on our common stock; and • determinations with respect to our tax returns.
These decisions could include: • corporate opportunities; • the impact that operating or capital decisions (including the incurrence of indebtedness) relating to our business may have on Banpu’s consolidated financial statements or current or future indebtedness (including related covenants); • business combinations involving us; • our dividend and stock repurchase policies; • compensation and benefit programs and other human resources policy decisions; • management of stock ownership; 84 Table of Contents • the payment of dividends on our common stock; and • determinations with respect to our tax returns.
Although we have identified potential CCUS projects in addition to the Barnett Zero Project, Cotton Cove Project, and the Eagle Ford Project, these additional potential projects are in different stages of the evaluation process. In most cases, emitters have required extended periods of time to evaluate potential projects and participate in negotiations.
Although we have identified potential CCUS projects in addition to the Barnett Zero Project, the Eagle Ford Project, Cotton Cove Project, and the East Texas Project, these additional potential projects are in different stages of the evaluation process. In most cases, emitters have required extended periods of time to evaluate potential projects and participate in negotiations.
Further, our ability to successfully operate the Barnett Zero Project with EnLink, or successfully develop the Cotton Cove Project with BPPUS and the Eagle Ford Project, or any future potential CCUS projects, depends on a number of factors that we are not able to fully control, including the following: • Commercial scale carbon capture is an emerging sector, and there are no substantial precedents to gauge the likely range of structures or economic terms that will be necessary to reach agreeable terms. • CCUS injection wells are currently subject to overlapping state and federal jurisdiction and new and evolving regulatory frameworks.
Further, our ability to successfully operate the Barnett Zero Project with ONEOK, or successfully develop the Eagle Ford Project and the Cotton Cove Project with BPPUS, and the East Texas Project, or any future potential CCUS projects, depends on a number of factors that we are not able to fully control, including the following: • Commercial scale carbon capture is an emerging sector, and there are no substantial precedents to gauge the likely range of structures or economic terms that will be necessary to reach agreeable terms. • CCUS injection wells are currently subject to overlapping state and federal jurisdiction and new and evolving regulatory frameworks.
For example, the recent decline in commodity prices may reduce the amount of capital the Company can raise through debt or equity financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all.
For example, a decline in commodity prices may reduce the amount of capital the Company can raise through debt or equity financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all.
Further, if there is a financial crisis, or the economic climate in the United States or abroad deteriorates, worldwide demand for hydrocarbon-based products could materially decrease, which could impact the price at which natural gas and 57 Table of Contents NGLs from our properties are sold, affect the ability of vendors, suppliers, and customers associated with our properties to continue operations, and ultimately materially adversely impact our results of operations and financial condition.
Further, if there is a financial crisis, or the economic climate in the United States or abroad deteriorates, worldwide demand for hydrocarbon-based products could materially decrease, which could impact the price at which natural gas and NGLs from our properties are sold, affect the ability of vendors, suppliers, and customers associated with our properties to continue operations, and ultimately materially adversely impact our results of operations and financial condition.
We are currently a “controlled company” within the meaning of the NYSE rules and, as a result, may qualify for and could rely on exemptions from certain corporate governance requirements. Banpu beneficially controls a significant majority of the voting power of our outstanding voting stock.
We are currently a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for and rely on exemptions from certain corporate governance requirements. Banpu beneficially controls a significant majority of the voting power of our outstanding voting stock.
The ultimate outcome and impact to us of these allegations cannot be predicted with certainty, and we could incur substantial legal costs associated with defending these and similar lawsuits in the future. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters.
The ultimate outcome and impact to us of these allegations cannot be predicted with certainty, and we could incur substantial legal costs associated with defending these and similar lawsuits in the future. 72 Table of Contents In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters.
Supreme Court finding in 2007 that GHG emissions constitute a pollutant under the CAA, the EPA adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the U.S.
Supreme Court finding in 2007 that GHG emissions constitute a pollutant under the CAA and the EPA's subsequent Endangerment Finding, the EPA adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the U.S.
Failure to comply with these laws and regulations may result in the assessment of sanctions, 73 Table of Contents including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the incurrence of capital expenditures, the occurrence of delays in the permitting, development, or expansion of projects, and the issuance of orders enjoining some or all of our future operations in a particular area.
Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the incurrence of capital expenditures, the occurrence of delays in the permitting, development, or expansion of projects, and the issuance of orders enjoining some or all of our future operations in a particular area.
Such delays or interruptions could have a material adverse effect on our financial condition, results of operations, and cash flows. A financial crisis or deterioration in general economic, business, or industry conditions could materially adversely affect our results of operations and financial condition.
Such delays or interruptions could have a material adverse effect on our financial condition, results of operations, and cash flows. A financial crisis, armed conflict, or deterioration in general economic, business, or industry conditions could materially adversely affect our results of operations and financial condition.
Our certificate of incorporation also renounces, to the fullest extent permitted by law, any interest or expectancy that we have in, or right to be offered an opportunity to participate in, specified business opportunities that are, from time to 80 Table of Contents time, presented to our officers, directors, or stockholders or their respective affiliates, other than those officers, directors, stockholders, or affiliates who are our, or our subsidiaries’ employees.
Our certificate of incorporation also renounces, to the fullest extent permitted by law, any interest or expectancy that we have in, or right to be offered an opportunity to participate in, specified business opportunities that are, from time to time, presented to our officers, directors, or stockholders or their respective affiliates, other than those officers, directors, stockholders, or affiliates who are our, or our subsidiaries’ employees.
Any termination or sustained disruption in the gathering, processing, and transportation of our natural gas and NGL production by EnLink on its systems and in its facilities would materially and adversely affect our financial condition and results of operations.
Any termination or sustained disruption in the gathering, processing, and transportation of our natural gas and NGL production by ONEOK on its systems and in its facilities would materially and adversely affect our financial condition and results of operations.
There is no assurance that we will be successful in obtaining permits or adequate levels of financial assurance for one or more of our CCUS projects or that permits can be obtained in a timely manner, whether due to difficulty with the technical demonstrations required to obtain such permits, public opposition, undeveloped regulatory framework, or otherwise.
There is no assurance that we will be successful in obtaining permits or 57 Table of Contents adequate levels of financial assurance for one or more of our CCUS projects or that permits can be obtained in a timely manner, whether due to difficulty with the technical demonstrations required to obtain such permits, public opposition, undeveloped regulatory framework, or otherwise.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and gas sector or otherwise restrict the areas in which this sector may produce oil and gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and gas.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and gas sector or otherwise restrict the areas in which this sector may produce oil and gas or generate GHG emissions could result in increased costs of 75 Table of Contents compliance or costs of consuming, and thereby reduce demand for, oil and gas.
ITEM 1A. RISK FACTORS The following risk factors should be considered in evaluating our business and future prospects, in addition to other information included in this Annual Report. Additional risk factors not presently known to us, or currently considered immaterial, may also have an adverse impact on our business, financial condition, and results of operations.
ITEM 1A. RISK FACTORS The following risk factors should be considered in evaluating our business and future prospects, in addition to other information included in this Annual Report on Form 10-K. Additional risk factors not presently known to us, or currently considered immaterial, may also have an adverse impact on our business, financial condition, and results of operations.
We cannot guarantee that we will be able to obtain necessary permits on a timely basis, on favorable terms, or at all. • As CCUS and carbon management represent an emerging sector, regulations may evolve rapidly, which could impact the feasibility of one or more of our anticipated projects.
We cannot guarantee that we will be able to obtain necessary permits on a timely basis, on favorable terms, or at all. 54 Table of Contents • As CCUS and carbon management represent an emerging sector, regulations may evolve rapidly, which could impact the feasibility of one or more of our anticipated projects.
The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, development, and production activities that could have an adverse impact on our ability to develop and produce our reserves.
The designation of previously unprotected species as threatened or endangered in areas where we operate could cause us to 78 Table of Contents incur increased costs arising from species protection measures or could result in limitations on our exploration, development, and production activities that could have an adverse impact on our ability to develop and produce our reserves.
Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market.
Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price 79 Table of Contents volatility through the OTC market.
The successful acquisition of natural gas and NGL properties requires an assessment of several factors, including: • recoverable reserves; • future commodity prices; • operating costs; and • potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain and rely on numerous assumptions and we may not be able to identify accretive acquisition opportunities.
The successful acquisition of natural gas and NGL properties requires an assessment of several factors, including: • recoverable reserves; • future commodity prices; • operating costs; and • potential environmental and other liabilities. These assessments are inherently uncertain and rely on numerous assumptions and we may not be able to identify accretive acquisition opportunities.
In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities.
In connection with these assessments, we perform a review of the subject properties 66 Table of Contents that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities.
If we are unable to obtain water to use in our operations from local sources or are unable to transport and store such water, we may be unable to economically produce natural gas and NGLs in the affected areas, which could have an adverse effect on our financial condition, results of operations, and cash flows.
If we are unable to obtain water to use in our operations from local sources or are unable to transport and store 49 Table of Contents such water, we may be unable to economically produce natural gas and NGLs in the affected areas, which could have an adverse effect on our financial condition, results of operations, and cash flows.
We enter into long-term firm transportation agreements, which provides us with a network of combined firm transportation capacity to East Coast, Gulf Coast, and Southeast markets as it relates to our upstream business units. 45 Table of Contents Additionally, BKV-BPP Power has long-term firm transportation and storage agreements with Atmos and Energy Transfer and firm storage with Energy Transfer.
We enter into long-term firm transportation agreements, which provides us with a network of combined firm transportation capacity to East Coast, Gulf Coast, and Southeast markets as it relates to our upstream business units. Additionally, BKV-BPP Power has long-term firm transportation and storage agreements with Atmos and Energy Transfer and firm storage with Energy Transfer.
In accordance with the terms of the Limited Liability Company Agreement of BKV-BPP Cotton Cove (the “BKV-BPP Cotton Cove LLC Agreement”), the BKV-BPP Cotton 54 Table of Contents Cove Joint Venture is managed by a board of managers (the “Cotton Cove JV Board”) consisting of six members, four of whom are appointed by BKV dCarbon Ventures and two of whom are appointed by BPPUS.
In accordance with the terms of the Limited Liability Company Agreement of BKV-BPP Cotton Cove (the “BKV-BPP Cotton Cove LLC Agreement”), the BKV-BPP Cotton Cove Joint Venture is managed by a board of managers (the “Cotton Cove JV Board”) consisting of six members, four of whom are appointed by BKV dCarbon Ventures and two of whom are appointed by BPPUS.
To the extent laws are enacted or other governmental action is taken that restricts drilling or production or imposes more stringent and costly operating, waste handling, disposal, and cleanup requirements, our business, prospects, financial condition, or results of operations could be materially adversely affected.
To the extent laws are enacted or 76 Table of Contents other governmental action is taken that restricts drilling or production or imposes more stringent and costly operating, waste handling, disposal, and cleanup requirements, our business, prospects, financial condition, or results of operations could be materially adversely affected.
When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require our current financial counterparties to post 77 Table of Contents additional capital as a result of entering into uncleared financial derivatives with us, which could increase the costs to us of future financial derivatives transactions.
When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require our current financial counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the costs to us of future financial derivatives transactions.
Our retail business depends on maintaining regulated permits and any loss of these permits would adversely affect our business. Our business requires a REP certificate from the PUCT and a load serving entity (“LSE”) registration and qualified scheduling entity (“QSE”) registration with ERCOT. Both the PUCT and ERCOT impose various requirements to maintain these permits.
Our retail business depends on maintaining regulated permits and any loss of these permits would adversely affect our business. 53 Table of Contents Our business requires a REP certificate from the PUCT and a load serving entity (“LSE”) registration and qualified scheduling entity (“QSE”) registration with ERCOT. Both the PUCT and ERCOT impose various requirements to maintain these permits.
Any significant variance in our assumptions and actual results could greatly affect our estimates of 43 Table of Contents reserves, the economically recoverable quantities of natural gas, NGLs, and oil attributable to any particular group of properties, the classifications of reserves based on risk of non-recovery and estimates of future net cash flows.
Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas, NGLs, and oil attributable to any particular group of properties, the classifications of reserves based on risk of non-recovery and estimates of future net cash flows.
Any such disruptions or curtailments could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, and cash flows. Risks Related to Our Retail Power Business We operate our retail power business through a joint venture which we do not control.
Any such disruptions or curtailments could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, and cash flows. Risks Related to Our Retail Power Business We operate our retail power business through a joint venture which we share control.
The agreements governing the indebtedness of Banpu require it to maintain certain financial ratios and tests based on consolidated financial statements. Banpu continues to have a substantial influence on our affairs and its voting power will constitute a substantial percentage of any quorum of our stockholders voting on any matter requiring the approval of our 79 Table of Contents stockholders.
The agreements governing the indebtedness of Banpu require it to maintain certain financial ratios and tests based on consolidated financial statements. Banpu continues to have a substantial influence on our affairs and its voting power will constitute a substantial percentage of any quorum of our stockholders voting on any matter requiring the approval of our stockholders.
Effective March 15, 2021, the CFTC implemented its final rule concerning speculative position limits, adopting new and amended federal spot-month limits for 2025 physical commodity derivatives.
Effective March 15, 2021, the CFTC implemented its final rule concerning speculative position limits, adopting new and amended federal spot-month limits for 25 physical commodity derivatives.
The inability of one or more of our significant counterparties to meet their payment or performance obligations may adversely affect our financial results. 65 Table of Contents We are subject to certain credit risks associated with nonpayment or nonperformance by our counterparties, including joint interest partners and customers.
The inability of one or more of our significant counterparties to meet their payment or performance obligations may adversely affect our financial results. We are subject to certain credit risks associated with nonpayment or nonperformance by our counterparties, including joint interest partners and customers.
Our access to external funding depends 53 Table of Contents on a number of factors, including general market conditions, potential investors’ confidence in our CCUS program, business model, growth potential, and our current and expected future earnings as well as the liquidity needs of the external funding sources themselves.
Our access to external funding depends on a number of factors, including general market conditions, potential investors’ confidence in our CCUS program, business model, growth potential, and our current and expected future earnings as well as the liquidity needs of the external funding sources themselves.
To the extent that natural gas, NGL, and oil prices become depressed or decline materially from current levels, such conditions could render uneconomic a portion of our proved natural gas, NGL, and oil reserves, and we may be required to write down our proved reserves.
To the extent that natural gas, NGL, and oil prices become depressed or decline materially from current levels, such conditions could 44 Table of Contents render uneconomic a portion of our proved natural gas, NGL, and oil reserves, and we may be required to write down our proved reserves.
Additionally, the development of CCUS projects through our current or potential future joint ventures involves risks not present in investments in which a third party is not involved, including the possibility that: • we and a co-venturer or partner may reach an impasse on a major decision that requires the approval of both parties; • we may not have exclusive control over the development, financing, management, and other aspects of the joint venture, which may prevent us from taking actions that are in our best interest but opposed by a co-venturer or partner; • a co-venturer or partner may encounter liquidity or insolvency issues or may become bankrupt, which may mean that we and any other remaining co-venturers or partners generally would remain liable for the joint venture’s liabilities; • a co-venturer or partner may at any time have economic or business interests or goals that are or may become inconsistent with ours; • a co-venturer or partner may be in a position to take action contrary to our instructions, requests, policies, or investment objectives, including our current policy with respect to maintaining our qualification for enhanced Section 45Q tax credits under the Code; • a co-venturer or partner may take actions that subject us to liabilities in excess of, or other than, those contemplated; • in certain circumstances, we may be liable for actions of our co-venturer or partner; • our joint venture agreements may restrict the transfer of a co-venturer’s or partner’s interest or otherwise restrict our ability to sell the interest when we desire or on advantageous terms; • our joint venture agreements may contain buy-sell provisions pursuant to which one co-venturer or partner may initiate procedures requiring the other co-venturer or partner to choose between buying the other co-venturer’s or partner’s interest or selling its interest to that co-venturer or partner; • if a joint venture agreement is terminated or dissolved, we may not continue to own or operate the interests or investments underlying the joint venture relationship or may need to purchase such interests or investments at a premium to the market price to continue ownership; or • disputes between us and a co-venturer or partner may result in litigation or arbitration that could increase our expenses and prevent our management from focusing their time and attention on our business.
Additionally, even in areas where such pipelines are in place, our use of them may require reaching agreements on CO 2 transportation with operators of the pipelines. 55 Table of Contents Additionally, the development of CCUS projects through our current or potential future joint ventures involves risks not present in investments in which a third party is not involved, including the possibility that: • we and a co-venturer or partner may reach an impasse on a major decision that requires the approval of both parties; • we may not have exclusive control over the development, financing, management, and other aspects of the joint venture, which may prevent us from taking actions that are in our best interest but opposed by a co-venturer or partner; • a co-venturer or partner may encounter liquidity or insolvency issues or may become bankrupt, which may mean that we and any other remaining co-venturers or partners generally would remain liable for the joint venture’s liabilities; • a co-venturer or partner may at any time have economic or business interests or goals that are or may become inconsistent with ours; • a co-venturer or partner may be in a position to take action contrary to our instructions, requests, policies, or investment objectives, including our current policy with respect to maintaining our qualification for enhanced Section 45Q tax credits under the Code; • a co-venturer or partner may take actions that subject us to liabilities in excess of, or other than, those contemplated; • in certain circumstances, we may be liable for actions of our co-venturer or partner; • our joint venture agreements may restrict the transfer of a co-venturer’s or partner’s interest or otherwise restrict our ability to sell the interest when we desire or on advantageous terms; • our joint venture agreements may contain buy-sell provisions pursuant to which one co-venturer or partner may initiate procedures requiring the other co-venturer or partner to choose between buying the other co-venturer’s or partner’s interest or selling its interest to that co-venturer or partner; • if a joint venture agreement is terminated or dissolved, we may not continue to own or operate the interests or investments underlying the joint venture relationship or may need to purchase such interests or investments at a premium to the market price to continue ownership; or • disputes between us and a co-venturer or partner may result in litigation or arbitration that could increase our expenses and prevent our management from focusing their time and attention on our business.
In addition, certain of our officers and such directors may now or in the future own capital stock or equity awards in Banpu or its affiliates. For certain of these individuals, their holdings of common stock or equity awards in Banpu or its affiliates may be significant compared to their total assets.
In addition, most of our directors now own, or our officers and other directors may own in the future, capital stock or equity awards in Banpu or its affiliates. For certain of these individuals, their holdings of common stock or equity awards in Banpu or its affiliates may be significant compared to their total assets.
The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources which may divert management’s attention from other business concerns. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.
The process of integrating acquired businesses may involve unforeseen liabilities, environmental issues, or other difficulties and may require a disproportionate amount of our managerial and financial resources which may divert management’s attention from other business concerns. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.
For example, during the period from January 1, 2022 through December 31, 2024, the Henry Hub natural gas spot price reached a high of $13.20 per MMBtu on January 13, 2024 and a low of $1.21 per MMBtu on November 11, 2024.
For example, during the period from January 1, 2023 through December 31, 2025, the Henry Hub natural gas spot price reached a high of $13.20 per MMBtu on January 13, 2024 and a low of $1.21 per MMBtu on November 11, 2024.
The development of our CCUS business, as well as the expansion of our “Pad of the Future” program and the effectiveness of our leak detection and repair emissions monitoring program and the BKV-BPP Power Joint Venture’s solar facility, are each important factors to our potential ability to achieve our emissions goal of net zero Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses by the early 2030s and aspirations to offset Scope 3 emissions from our owned and operated upstream and natural gas midstream businesses by the late 2030s.
The development of our CCUS business, as well as the expansion of our Pad of the Future program and the effectiveness of our leak detection and repair emissions monitoring program and the BKV-BPP Power Joint Venture’s solar facility, are each important factors to our potential ability to achieve our emissions goal of net zero Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses during the early 2030s and aspirations to offset Scope 3 emissions from our owned and operated upstream and natural gas midstream businesses by the late 2030s.
For the years ended December 31, 2024, 2023, and 2022, the portion of BKV's earnings in the BKV-BPP Power Joint Venture were $10.4 million, $16.9 million, and $8.5 million, respectively, and our interest in the earnings on the BKV-BPP Power Joint Venture represented approximately 1.8%, 1.7%, and 0.8% of our revenues, which includes derivative gains (losses), net, respectively.
For the years ended December 31, 2025, 2024, and 2023, the portion of BKV's earnings in the BKV-BPP Power Joint Venture were $14.9 million, $10.4 million, and $16.9 million, respectively, and our interest in the earnings on the BKV-BPP Power Joint Venture represented approximately 1.5%, 1.8%, and 1.7% of our revenues, which includes derivative gains (losses), net, respectively.
As a result, the BKV-BPP Power Joint Venture is subject to the risks of disruptions or curtailments in the production of power at the Temple Plants if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.
As a result, the BKV-BPP Power Joint Venture is subject to the risks of disruptions or curtailments in the production of 52 Table of Contents power at the Temple Plants if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.
Risks Related to Our Business Generally Substantially all of our oil, gas, and midstream properties are concentrated in Texas and Northeast Pennsylvania, making us vulnerable to risks associated with operating in only two geographic areas. 56 Table of Contents Substantially all of our oil, gas, and midstream properties are located in Texas and Northeast Pennsylvania.
Risks Related to Our Business Generally Substantially all of our oil, gas, and midstream properties are concentrated in Texas and Northeast Pennsylvania, making us vulnerable to risks associated with operating in only two geographic areas. Substantially all of our oil, gas, and midstream properties are located in Texas and Northeast Pennsylvania.
We rely on the credit worthiness of such third-party marketer, who collects directly from the purchasers and remits to us the total of all amounts collected on our behalf less their fee for making such sales.
We rely on the creditworthiness of such third-party marketer, who collects directly from the purchasers and remits to us the total of all amounts collected on our behalf less their fee for making such sales.
Our future operating performance and ability to refinance will be affected by economic and capital market conditions, fluctuations in commodity prices, results of operations, and other factors, many of which are beyond our control.
Our future operating performance and ability to refinance will be affected by economic and capital market conditions, the syndicated bank market, fluctuations in commodity prices, results of operations, and other factors, many of which are beyond our control.
The present value of future net revenues from our proved reserves is not the same as the current market value of our estimated natural gas, NGL, and oil reserves. We currently base the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated natural gas, NGL, and oil reserves. We currently base the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months.
Changes in regulation could create increased costs that BKV-BPP Retail might be unable to pass through to customers, particularly those on fixed-priced contracts. For example, ERCOT introduced a new ancillary service product — ERCOT 51 Table of Contents Reserve Contingency Service (“ECRS”) — in June 2023.
Changes in regulation could create increased costs that BKV-BPP Retail might be unable to pass through to customers, particularly those on fixed-priced contracts. For example, ERCOT introduced a new ancillary service product — ERCOT Reserve Contingency Service (“ECRS”) — in June 2023.
We do not own all of the land on which our pipelines and other midstream facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid right-of-ways or leases or if such right-of-ways or leases lapse or terminate.
We do not own all of the land on which our pipelines and other midstream facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate.
Our cash flow from operations and access to capital are subject to a number of variables, including: • the estimated quantities of our natural gas and NGL reserves; • the amount of hydrocarbon we produce from existing wells; • the prices at which we sell our production; • the levels of our operating expenses; • take-away and storage capacity; • our ability to acquire, locate, develop, and produce new reserves; and 64 Table of Contents • our ability to borrow under the RBL Credit Agreement and any additional working capital facilities that we obtain.
Our cash flow from operations and access to capital are subject to a number of variables, including: • the estimated quantities of our natural gas and NGL reserves; • the amount of hydrocarbon we produce from existing wells; • the prices at which we sell our production and prevailing basis differentials; • the levels of our operating expenses; • take-away and storage capacity; • our ability to acquire, locate, develop, and produce new reserves; and • our ability to borrow under the RBL Credit Agreement and any additional working capital facilities that we obtain.
We maintain credit procedures and policies to mitigate the credit risks posed by our counterparties. However, our credit procedures and policies may not be adequate to fully eliminate the risk and we do not require all of our counterparties to post collateral.
We maintain credit procedures and policies to mitigate the credit risks posed by our counterparties. However, our credit procedures and policies may not be adequate to fully eliminate the risk and we do not require all of our 68 Table of Contents counterparties to post collateral.
PHMSA promulgated the second component of the Gas Mega Rule in November 75 Table of Contents 2021, extending federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures.
PHMSA promulgated the second component of the Gas Mega Rule in November 2021, extending federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures.
If we are unable to service our indebtedness and fund our operating costs, we will be required to adopt alternative strategies that may include: • reducing or delaying capital expenditures; • seeking additional debt financing or equity capital; • selling assets; and/or • restructuring or refinancing debt.
If we are unable to service our indebtedness and fund our operating costs, we will be required to adopt alternative strategies that may include: • reducing or delaying capital expenditures; • seeking additional debt financing or equity capital; • selling assets; and/or 61 Table of Contents • restructuring or refinancing debt.
Impairment is indicated when a triggering event occurs and the sum of the estimated undiscounted future net cash flows of an evaluated asset is less 44 Table of Contents than the asset’s carrying value.
Impairment is indicated when a triggering event occurs and the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset’s carrying value.
See “ - Risks Related to Our Relationship with Banpu and its Affiliates - Banpu’s interests, including interests in certain corporate opportunities, may conflict with our interests and the 63 Table of Contents interests of our other stockholders.
See “— Risks Related to Our Relationship with Banpu and its Affiliates — Banpu’s interests, including interests in certain corporate opportunities, may conflict with our interests and the interests of our other stockholders.
Any such modifications could likely result in substantial additional capital expenditures. We may also choose to repower, refurbish, or upgrade these facilities based on our assessment that such activity will provide adequate financial returns.
Any such modifications could likely result 51 Table of Contents in substantial additional capital expenditures. We may also choose to repower, refurbish, or upgrade these facilities based on our assessment that such activity will provide adequate financial returns.
In addition, under our Stockholders’ Agreement, as long as BNAC and Banpu beneficially own 10% or more of our voting stock, BNAC will be entitled to designate for nomination to our board of directors a number of individuals approximately proportionate to such beneficial ownership, provided that (i) until September 27, 2025 (the first anniversary of the completion of our IPO), at least three board seats will not be BNAC designees, (ii) from September 27, 2025 until the first date on which BNAC and Banpu beneficially own 50% or less of our voting stock, at least four board seats will not be BNAC designees, and (iii) from and after the first date on which BNAC and Banpu beneficially own 50% or less of our voting stock, a number of board seats equal to the minimum number of directors that would constitute a majority of the total number of directors comprising our board of directors will not be BNAC designees.
In addition, under our Stockholders’ Agreement, as long as BNAC beneficially owns 10% or more of our voting stock, BNAC will be entitled to designate for nomination to our board of directors a number of individuals approximately proportionate to such beneficial ownership, provided that (i) from September 27, 2025 until the first date on which BNAC beneficially owns 50% or less of our voting stock, at least four board seats will not be BNAC designees, and (ii) from and after the first date on which BNAC beneficially owns 50% or less of our voting stock, a number of board seats equal to the minimum number of directors that would constitute a majority of the total number of directors comprising our board of directors will not be BNAC designees.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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For additional information about cybersecurity risks associated with our business, see Item 1A, “ Risk Factors .” Governance Risk Management Personnel We have an enterprise risk committee that includes our executive leadership team and other senior members within our legal, IT, finance and accounting, and operational departments, which oversees BKV's operational, strategic, and corporate-level risks, including risk management.
For additional information about cybersecurity risks associated with our business, see Item 1A, “ Risk Factors .” Governance Risk Management Personnel We have an enterprise risk committee that includes our executive leadership team and other senior members within our legal, IT, finance and accounting, and operational departments, which oversees our operational, strategic, and corporate-level risks, including risk management.
Board of Director Oversight Our Audit & Risk Committee provides oversight of cybersecurity risk in connection with BKV's comprehensive cybersecurity strategy and receives regular quarterly updates on our ongoing assessment of cybersecurity risks, threats, and data security programs to prevent and detect breaches and attacks against BKV.
Board of Director Oversight Our Audit & Risks Committee provides oversight of cybersecurity risk in connection with BKV's comprehensive cybersecurity strategy and receives regular quarterly updates on our ongoing assessment of cybersecurity risks, threats, and data security programs to prevent and detect breaches and attacks against us.
The CIO and other experts, as necessary, provide the Audit & Risks Committee quarterly updates that encompass a broad range of topics, including but not limited to: • Current cybersecurity threat landscape and emerging threats; 86 Table of Contents • Status of ongoing cybersecurity initiatives and strategies; • Incident reports and learnings from unique cybersecurity events, including those of other companies; • Compliance status and efforts with regulatory requirements and industry standards; and • Benchmarked data on the performance of certain aspects of our cybersecurity program relative to our peers The Audit & Risk Committee meets quarterly to discuss areas that are potentially high risk to the Company.
The senior technology advisor and other experts, as necessary, provide the Audit & Risks Committee quarterly cybersecurity updates and risk discussions that encompass a broad range of topics, including but not limited to: • Current cybersecurity threat landscape and emerging threats; • Status of ongoing cybersecurity initiatives and strategies; • Incident reports and learnings from unique cybersecurity events, including those of other companies; • Compliance status and efforts with regulatory requirements and industry standards; and • Benchmarked data on the performance of certain aspects of our cybersecurity program relative to our peers.
The Company has processes and procedures in place to monitor the prevention, detection, mitigation, and remediation of cybersecurity risks.
We have processes and procedures in place to monitor the prevention, detection, mitigation, and remediation of cybersecurity risks.
Managing Material Risks & Integrated Overall Risk Management BKV has strategically integrated cybersecurity risk management into its broader enterprise risk management framework to promote a company-wide culture of cyber risk awareness.
Managing Material Risks & Integrated Overall Risk Management We have strategically integrated cybersecurity risk management into our broader enterprise risk management framework to promote a company-wide culture of cyber risk awareness.
Risks from Cybersecurity Incidents As of March 31, 2025, BKV has not been subject to any material cybersecurity incidents and we are not aware of any cybersecurity risks that are reasonably likely to materially affect the Company, its operations, or financial standing.
Risks from Cybersecurity Incidents As of March 6, 2026, we have not experienced any material cybersecurity incidents and we are not aware of any cybersecurity risks that are reasonably likely to materially affect the Company, its operations, or financial standing.
Managing Third Party Risk BKV's cybersecurity approach also assesses the risks associated with the use of vendors, service providers, and other third parties that provide information system services, process information on its behalf, or have access to its information systems, and has processes in place to oversee and manage these risks.
Managing Third Party Risk Our cybersecurity approach assesses and manages the risks associated with the use of vendors, service providers, and other third parties that provide information system services, process information on our behalf, or have access to our information systems.
These include but are not limited to: • Maintaining and regularly updating a defined and practiced incident response plan (“IRP”); • Maintaining cyber insurance coverage; • Employing appropriate incident prevention and detection software, such as antivirus, anti-malware, firewall, endpoint detection, and identity and access management; • Executing scheduled, recurring server and infrastructure patching processes; • Maintaining a defined disaster recovery policy and employing backup/disaster recovery software, where appropriate; • Educating, training, and testing employees on information security practices and identification of potential cybersecurity risks and threats; and • Ensuring familiarity and compliance with cybersecurity frameworks where appropriate. 85 Table of Contents Engaging Third Parties on Risk Management Recognizing the complexity and evolving nature of cybersecurity risk, BKV engages with external experts, including, but not limited to a managed security service provider (“MSSP”), the Cybersecurity Operations Center (“CSOC”) team to evaluate, monitor, and test BKV's cyber management systems and related cyber risks.
These include but are not limited to: 89 Table of Contents • Maintaining and regularly updating a defined and practiced incident response plan (“IRP”); • Maintaining cyber insurance coverage; • Employing appropriate incident prevention and detection software, such as antivirus, anti-malware, firewall, endpoint detection, and identity and access management; • Executing scheduled, recurring server and infrastructure vulnerability management and patching processes; • Maintaining a defined disaster recovery policy with backup/disaster recovery software; • Educating, training, and testing employees on information security practices and identification of potential cybersecurity risks and threats; and • Ensuring familiarity and compliance with cybersecurity frameworks.
BKV's Chief Information Officer (“CIO”) and Manager of Cybersecurity work closely with its information technology (“IT”) department to continuously evaluate and address cybersecurity risks in alignment with business objectives, operational needs, and industry-accepted standards, such as the Center for Internet Security (CIS) Critical Security Controls and National Institute of Standards and Technology (NIST) frameworks.
Our cybersecurity risk management program is supported by a senior technology advisor and the Senior Director of Cybersecurity who work closely with our information technology (“IT”) department to continuously evaluate and address cybersecurity risks in alignment with business objectives, operational needs, and industry-accepted standards, such as the Center for Internet Security (CIS) Critical Security Controls, National Institute of Standards and Technology (NIST) frameworks, and the North American Electric Reliability Corporation (NERC) standards.
ITEM 1C. CYBERSECURITY BKV employs a comprehensive cybersecurity strategy to protect against threats that could compromise sensitive information, disrupt data or systems, or jeopardize the security of facilities and infrastructure, including third-party processing plants and pipelines.
ITEM 1C. CYBERSECURITY Our processes are designed to identify, assess, and manage cybersecurity risks that could be material to the Company, including risks that could compromise sensitive information, disrupt data or systems, or jeopardize the security of facilities and infrastructure, including third-party processing plants and pipelines.
In addition to the minimum security and control standards, these processes include other quality control measures as well. BKV also maintains ongoing monitoring to support continuous compliance with its cybersecurity standards, and regularly updates and patches third-party applications and tools when vulnerabilities are discovered.
BKV maintains ongoing monitoring to support continuous compliance with our cybersecurity standards and requirements, and regularly updates and patches third-party applications and tools when vulnerabilities are discovered.
ITEM 2. PROPERTIES Information regarding our properties is included in Item 1. “ Business ” and in Note 19 - Supplemental Oil and Gas Disclosures (unaudited) incorporated herein.
The Audit & Risks Committee meets quarterly to discuss areas that are potentially high risk to the Company. ITEM 2. PROPERTIES Information regarding our properties is included in Item 1. “ Business ” and in Note 20 - Supplemental Oil and Gas Disclosures (unaudited) incorporated herein.
They implement and oversee processes for the 24/7/365 monitoring of our information systems as well as ongoing threat assessment monitoring. The deployment of advanced security measures, regular system audits to identify potential vulnerabilities, and periodic cyber assessment exercises support these programmatic efforts. In the event of a cybersecurity incident, the Company is equipped with a defined and practiced IRP.
The deployment of advanced security measures, regular system audits to identify potential vulnerabilities, and periodic cyber assessment exercises support these programmatic efforts. In the event of a cybersecurity incident, the Company is equipped with a defined and practiced IRP. This plan includes immediate actions to mitigate the impact and long-term strategies for remediation and prevention of future incidents.
The IT department conducts extensive reviews of our systems, networks, and data infrastructure to identify potential cybersecurity threats and vulnerabilities and implements systems and tools to remediate perceived risks. These tools are designed to prevent and detect activities or events that could pose a cybersecurity risk to our business.
Our cybersecurity team continually conducts extensive reviews of our systems, networks, and data infrastructure to identify potential cybersecurity threats and vulnerabilities and implements systems and tools to remediate perceived risks.
Our third party CSOC team provides 24-hour monitoring to detect and respond to suspicious activity in real time. Monitor Cybersecurity Incidents The CIO and Manager of Cybersecurity are continually informed and updated about the latest developments in cybersecurity, including emerging threats and innovative risk management techniques.
Monitor Cybersecurity Incidents 90 Table of Contents The senior technology advisor and Senior Director of Cybersecurity are continually informed and updated about the latest developments in cybersecurity, including emerging threats and innovative risk management techniques. Through the aid of the Company's CSOC, processes are implemented for 24/7/365 monitoring of our information systems and ongoing cybersecurity threat assessment.
The Company's collaboration with these third parties includes audits, threat and vulnerability assessments, IRP testing, company-wide monitoring of cybersecurity risks, and consultation on security enhancements. Third-party experts have assisted BKV in conducting cross-functional tabletop exercises and quarterly strategic meetings as well as developing comprehensive remediation plans following cybersecurity assessments.
Our third-party CSOC team provides 24-hour monitoring to detect and respond to suspicious activity in real time. Our collaboration with third parties includes audits, threat and vulnerability assessments, IRP testing, company-wide monitoring of cybersecurity risks, and consultation on security enhancements.
Our comprehensive cybersecurity risk management is led by our CIO who brings over 30 years of extensive experience in information technology with a specialization in cybersecurity. Her expertise spans global information systems and data, cybersecurity operations, security management strategies and tools, security assessment and remediation, as well as the design and implementation of controls to prevent and detect cybersecurity threats.
Our comprehensive cybersecurity risk management is led by a senior technology advisor, who brings over 40 years of extensive experience in information technology and over 35 years in the oil and gas industry leading large, complex global technology operating environments.
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BKV’s cybersecurity risk management program is overseen by management at multiple levels. The CIO and Manager of Cybersecurity play key roles in assessing, monitoring, and managing the Company's cybersecurity risks. The CIO Cybersecurity governance also is supported by our IT department and CSOC. These stakeholders meet monthly to review the monthly cybersecurity assessment and remediation report.
Added
Engaging Third Parties on Risk Management Recognizing the complexity and evolving nature of cybersecurity risk, we engage with external experts, including, but not limited to, the Cybersecurity Operations Center (“CSOC”) team to evaluate, monitor, and test our cyber management systems, and to respond to cyber risks.
Removed
This plan includes immediate actions to mitigate the impact and long-term strategies for remediation and prevention of future incidents.
Added
Third-party experts have assisted us in conducting cross-functional tabletop exercises, IT and operational technology network penetration assessments, and periodically scheduled cybersecurity risk discussions to develop comprehensive identified vulnerability remediation plans.
Added
The senior technology advisor works closely with executive management and the Senior Director of Cybersecurity to provide strategic oversight and guidance on cybersecurity risk management.
Added
The senior technology advisor and Senior Director of Cybersecurity, who brings over 30 years of cybersecurity and compliance experience in the oil and gas and mining industries as a Certified Information Systems Security Professional (CISSP) and Certified Information Systems Auditor (CISA) in large complex global information technology operating environments, play key roles in assessing, monitoring, and managing the Company's cybersecurity risks.
Added
The senior technology advisor and Senior Director of Cybersecurity are supported by our IT department and CSOC. These stakeholders meet monthly to review the current risk trends, vulnerability and threat landscape, improvement programs, and an overall baseline scorecard over our cybersecurity risk.
Added
These tools are designed to prevent and detect activities or events that could pose a cybersecurity risk to our business and also enable the Company to quickly respond and recover from any potential cybersecurity event.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Our results of operations and cash flows, however, could be significantly impacted in the reporting periods in which such matters are resolved. This information with respect to this Item 3. “ Legal Proceedings ” is set forth in Item 8 of Part II, Financial Statements and Supplementary Data , in Note 16 - Commitments and Contingencies incorporated herein. ITEM 4.
Our results of operations and cash flows, however, could be significantly impacted in the reporting periods in which such matters are resolved. The information with respect to this Item 3. “ Legal Proceedings ” is set forth in Item 8 of Part II, Financial Statements and Supplementary Data , in Note 16 - Commitments and Contingencies incorporated herein. ITEM 4.
MINE SAFETY DISCLOSURES Not applicable. 87 Table of Contents PART II
MINE SAFETY DISCLOSURES Not applicable. 91 Table of Contents PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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The performance graph below illustrates changes over the period of September 26, 2024 through December 31, 2024, in cumulative total stockholder return on our common stock as measured against the cumulative total return of the S&P Small Cap 600, the S&P Oil & Gas Exploration and Production Index, and a customized peer group.
The performance graph below illustrates changes over the period of September 26, 2024 through December 31, 2025, in cumulative total stockholder return on our common stock as measured against the cumulative total return of the S&P Small Cap 600, the S&P Oil & Gas Exploration and Production Index, and a customized peer group.
Stock Performance Graph The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filings under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filings.
Stock Performance Graph The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filings under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference into such filings.
ITEM 6. [ RESERVED ] 89 Table of Contents
ITEM 6. [ RESERVED ] 93 Table of Contents
Prior to trading on the NYSE, there was no established public trading market for our common stock. On March 28, 2025, the closing price of our common stock was $20.74 and we had approximately 1,000 stockholders of record, excluding stockholders for whom shares are held in “nominee” or “street” name.
Prior to trading on the NYSE, there was no established public trading market for our common stock. On February 27, 2026, the closing price of our common stock was $31.33 and we had approximately 50 stockholders of record, excluding stockholders for whom shares are held in “nominee” or “street” name.
The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends for the index securities) from September 26, 2024 through December 31, 2024. 9/26/2024 9/30/2024 10/31/2024 11/29/2024 12/31/2024 BKV Corporation $ 100 $ 102 $ 100 $ 122 $ 132 S&P Small Cap 600 100 101 98 109 100 S&P Oil & Gas Exploration & Production 100 103 102 113 104 2024 Self-Constructed Peer Group (1) 100 104 103 125 125 _________________________________ (1) The 2024 Self-Constructed Peer Group includes the following companies: EQT Corporation, Range Resources Corporation, Gulfport Energy Corporation, Expand Energy Corporation, and CNX Resources Corporation.
The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends for the index securities) from September 26, 2024 through December 31, 2025. 92 Table of Contents 9/26/2024 9/30/2024 12/31/2024 3/31/2025 6/30/2025 9/30/2025 12/31/2025 BKV Corporation $ 100 $ 102 $ 132 $ 117 $ 134 $ 129 $ 151 S&P Small Cap 600 100 101 100 91 95 103 104 S&P 1500 Oil & Gas Exploration & Production 100 103 104 111 100 100 100 Self-Constructed Peer Group (1) 100 104 125 130 139 128 134 _________________________________ (1) The Self-Constructed Peer Group includes the following companies: EQT Corporation, Range Resources Corporation, Gulfport Energy Corporation, Expand Energy Corporation, and CNX Resources Corporation.
Removed
Recent Sales of Unregistered Securities None. Use of Proceeds There has been no material change in the expected use of the net proceeds from our IPO as described in our prospectus filed on September 27, 2024 and other periodic reports previously filed with the SEC.
Added
Securities Authorized for Issuance Under Equity Compensation Plans Information required by this item is incorporated by reference to our 2026 Proxy Statement, as defined in Part III, Item 10 of this Annual Report on Form 10-K.
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Securities Authorized for Issuance Under Equity Compensation Plans 2024 Equity and Incentive Compensation Plan Our 2024 Equity and Incentive Compensation Plan (the “2024 Plan”) became effective immediately prior to the consummation of the IPO.
Added
Issuer Purchases of Equity Securities On December 18, 2025, our board of directors authorized a two-year share repurchase program (the "Share Repurchase Program"), pursuant to which we may repurchase, from time to time, shares of our common stock for an aggregate purchase price of up to $100.0 million through open market purchases, block trades, 10b5-1 plans, or by means of privately negotiated purchases, in each case subject to compliance with the applicable provisions of federal and state securities laws and regulations, including Rule 10b-18 under the Exchange Act.
Removed
The 2024 Plan permits the grant of awards to the non-employee directors, officers, and other employees of BKV and its controlled subsidiaries in order to provide incentives and rewards for service and/or performance.
Added
The timing and total amount of any share repurchases will be determined at the discretion of our management based on a variety of factors, including economic and market conditions, the stock price, our liquidity requirements and priorities, regulatory requirements, applicable legal requirements, and other factors.
Removed
We may grant stock options, appreciation rights, restricted stock, restricted stock units (“RSUs”), performance shares, performance units, cash incentive awards, and certain other awards based on or related to shares of our common stock.
Added
The repurchase program does not obligate us to repurchase any specific number of shares and may be suspended, modified, or discontinued at any time at the discretion of our board of directors. Share repurchases are expected to be funded through available cash or borrowings under our existing reserve-based lending agreement.
Removed
Under the 2024 Plan, we can issue up to 5,000,000 shares of its common stock, which are subject to adjustment to reflect any extraordinary cash dividend, stock dividend, split, or combination of our common stock.
Added
We made no purchases of common stock under the Share Repurchase Program during the three and twelve months ended December 31, 2025.
Removed
The aggregate number of shares of our common stock available for award under the 2024 Plan will be reduced by one share of our common stock for every one share of its common stock subject to an award granted under the 2024 Plan.
Removed
Each grant of an award under the 2024 Plan will be evidenced by an award agreement that includes terms and provisions, determined by our Compensation Committee (or other committee of the board of directors designated by the board to administer the 2024 Plan), which outlines the number of shares of common stock, earning or vesting terms, and any other terms consistent with the 2024 Plan.
Removed
Employee Stock Purchase Plan Our Employee Stock Purchase Plan (the “ESPP”) became effective immediately prior to the consummation of the IPO.
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A total of 500,000 shares of our common stock is available for awards under the ESPP and only permits eligible employees to purchase shares of our common stock through payroll deductions, which cannot exceed 10% of the employee's eligible compensation.
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The ESPP will be implemented through a series of offerings of up to a period of 27 months, which will consist of one offering period. During the offering period, payroll contributions will accumulate without interest and, on the last trading day of the offering period, accumulated payroll deductions will be used to purchase shares of our common stock.
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For the year ended December 31, 2024, we did not recognize any equity-based compensation expense related to the ESPP. 2021 Equity and Incentive Compensation Plan On January 1, 2021, the BKV Corporation Long-Term Incentive Plan (the “2021 Plan”) was established and as of December 31, 2024, 7,724,499 RSUs were considered to have been granted under Accounting Standards Codification (“ASC”) 718 - Compensation-Stock Compensation (“ASC 718”), when taking into consideration performance RSUs at the maximum performance level and time-based RSUs anticipated to be legally granted in the three years following inception. 88 Table of Contents As of December 31, 2024, the awards considered granted under ASC 718 since inception equaled the number of RSUs legally granted.
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Issuer Purchases of Equity Securities We currently do not maintain a common stock repurchase program.
Removed
Any future determination related to a common stock repurchase program will be made at the sole discretion of our board of directors after considering our general economic and business conditions, including our financial condition and results of operations, capital requirements, restrictions under our indebtedness, potential acquisition opportunities and other current and anticipated cash needs and any other factors our board of directors deems relevant.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

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Our marketing revenues are derived under our marketing agreement with a third party pursuant to which we receive a fixed percentage of all net income realized in the resale of our and other producers’ hydrocarbons.
Marketing Revenues Our marketing revenues are derived under our marketing agreement with a third party pursuant to which we receive a fixed percentage of all net income realized in the resale of our and other producers’ hydrocarbons.
The change was also due to the decrease of $49.0 million of capital expenditures (excluding CCUS activities), a $37.8 million reduction of CCUS-related expenditures, and a $4.9 million decrease in cash used for acquisition of natural gas properties for the year ended December 31, 2024 compared to the prior year.
The change was also due to a decrease of $49.0 million in capital expenditures (excluding CCUS activities), a $37.8 million reduction of CCUS-related expenditures, and a $4.9 million decrease in cash used for acquisition of natural gas properties for the year ended December 31, 2024 compared to the prior year.
Net cash used in financing activities was $304.8 million for the year ended December 31, 2024, which consisted of net payments on debt of $493.0 million, payments of $53.2 million for taxes related to net share settlement of restricted stock units, and payments of debt issuance costs and debt extinguishment costs of $18.3 million.
Net cash used in financing activities was $304.8 million for the year ended December 31, 2024, which consisted of $493.0 million of net payments on debt, $53.2 million of payments for taxes related to net share settlement of restricted stock units, and $18.3 million for payments of debt issuance costs and debt extinguishment costs.
Revolving Credit Agreements On June 11, 2024, using the funds from the RBL Credit Agreement, we repaid the outstanding debt balances under (i) the Term Loan Credit Agreement, (ii) the Revolving Credit Agreement, and (iii) our loan agreement previously entered into in March 2022 with Standard Charter Bank (the “SCB Credit Facility”), in each case with proceeds from the loans under the RBL Credit Agreement and cash on hand.
Revolving Credit Agreements and Term Loan Credit Agreement On June 11, 2024, using the funds from the RBL Credit Agreement, we repaid the outstanding debt balances under (i) the Term Loan Credit Agreement, (ii) the Revolving Credit Agreement, and (iii) our loan agreement previously entered into in March 2022 with Standard Charter Bank (the “SCB Credit Facility”), in each case with proceeds from the loans under the RBL Credit Agreement and cash on hand.
The following table provides information on our operating expenses: Year Ended December 31, (in thousands, other than percentages and average costs) 2024 2023 $ Change % Change Operating expenses Lease operating and workover $ 136,991 $ 150,647 $ (13,656) (9) % Taxes other than income 35,009 72,290 (37,281) (52) % Gathering and transportation costs 222,391 248,990 (26,599) (11) % Depreciation, depletion, amortization, and accretion 217,533 223,370 (5,837) (3) % General and administrative 104,473 114,688 (10,215) (9) % Other 19,385 12,625 6,760 54 % Total operating expense $ 735,782 $ 822,610 Average costs per Mcfe Lease operating and workover $ 0.47 $ 0.48 $ (0.01) (2) % Taxes other than income 0.12 0.23 (0.11) (48) % Gathering and transportation costs 0.77 0.79 (0.02) (3) % Depreciation, depletion, amortization, and accretion 0.75 0.71 0.04 6 % General and administrative 0.36 0.37 (0.01) (3) % Other 0.07 0.04 0.03 75 % Total $ 2.54 $ 2.62 *Percentage not meaningful Lease Operating and Workover The following table summarizes our components of lease operating expenses for the periods presented: Year Ended December 31, 2024 2023 $ Change % Change (in thousands, other than percentages and average costs) Amount Per Mcfe Amount Per Mcfe Lease operating expenses $ 132,317 $ 0.46 $ 142,911 $ 0.46 $ (10,594) (7) % Workover expenses 4,674 0.01 7,736 0.02 (3,062) (40) % Total lease operating and workover expense $ 136,991 $ 0.47 $ 150,647 $ 0.48 $ (13,656) (9) % Lease operating and workover expenses were $137.0 million, or $0.47 per Mcfe, for the year ended December 31, 2024, which was a decrease of approximately $13.7 million, or 9%, from $150.6 million, or $0.48 per Mcfe, for the year ended December 31, 2023.
The following table provides information on our operating expenses: Year Ended December 31, (in thousands, other than percentages and average costs) 2024 2023 $ Change % Change Operating expenses Lease operating and workover $ 136,991 $ 150,647 $ (13,656) (9) % Taxes other than income 35,009 72,290 (37,281) (52) % Gathering and transportation costs 222,391 248,990 (26,599) (11) % Depreciation, depletion, amortization, and accretion 217,533 223,370 (5,837) (3) % General and administrative 104,473 114,688 (10,215) (9) % Other 19,385 12,625 6,760 54 % Total operating expense $ 735,782 $ 822,610 Average costs per Mcfe Lease operating and workover $ 0.47 $ 0.48 $ (0.01) (2) % Taxes other than income 0.12 0.23 (0.11) (48) % Gathering and transportation costs 0.77 0.79 (0.02) (3) % Depreciation, depletion, amortization, and accretion 0.75 0.71 0.04 6 % General and administrative 0.36 0.37 (0.01) (3) % Other 0.07 0.04 0.03 75 % Total $ 2.54 $ 2.62 *Percentage not meaningful Lease Operating and Workover The following table summarizes our components of lease operating expenses for the periods presented: Year Ended December 31, 2024 2023 $ Change % Change (in thousands, other than percentages and average costs) Amount Per Mcfe Amount Per Mcfe Lease operating expenses $ 132,317 $ 0.46 $ 142,911 $ 0.46 $ (10,594) (7) % Workover expenses 4,674 0.01 7,736 0.02 (3,062) (40) % Total lease operating and workover expense $ 136,991 $ 0.47 $ 150,647 $ 0.48 $ (13,656) (9) % Lease operating and workover expenses were $137.0 million, or $0.47 per Mcfe, for the year ended December 31, 2024 , which was a decrease of $13.7 million , or 9% , from $150.6 million , or $0.48 per Mcfe, for the year ended December 31, 2023 .
General and Administrative General and administrative expenses were $104.5 million, or $0.36 per Mcfe, for the year ended December 31, 2024, which was a decrease of approximately $10.2 million, or 9%, from $114.7 million , or $0.37 per Mcfe, for the year ended December 31, 2023 .
General and Administrative General and administrative expenses were $104.5 million , or $0.36 per Mcfe, for the year ended December 31, 2024 , which was a decrease of $10.2 million , or 9% , from $114.7 million , or $0.37 per Mcfe, for the year ended December 31, 2023 .
Depreciation, Depletion, Amortization, and Accretion Depreciation, depletion, amortization, and accretion was $217.5 million, or $0.75 per Mcfe, for the year ended December 31, 2024, which was a decrease of approximately $5.8 million, or 3%, from $223.4 million, or $0.71 per Mcfe, for the year ended December 31, 2023 .
Depreciation, Depletion, Amortization, and Accretion Depreciation, depletion, amortization, and accretion was $217.5 million , or $0.75 per Mcfe, for the year ended December 31, 2024 , which was a decrease of $5.8 million , or 3% , from $223.4 million , or $0.71 per Mcfe, for the year ended December 31, 2023 .
Taxes Other Than Income Taxes other than income were $35.0 million, or $0.12 per Mcfe, for the year ended December 31, 2024, which was a decrease of approximately $37.3 million, or 52%, from $72.3 million, or $0.23 per Mcfe, for the year ended December 31, 2023.
Taxes Other Than Income Taxes other than income were $35.0 million , or $0.12 per Mcfe, for the year ended December 31, 2024 , which was a decrease of $37.3 million , or 52% , from $72.3 million , or $0.23 per Mcfe, for the year ended December 31, 2023 .
Other Operating Expenses Other operating expenses were $19.4 million, or $0.07 per Mcfe, for the year ended December 31, 2024, which was an increase of approximately $6.8 million, or 54%, from $12.6 million, or 0.04 per Mcfe, for the year ended December 31, 2023.
Other Operating Expenses Other operating expenses were $19.4 million , or $0.07 per Mcfe, for the year ended December 31, 2024 , which was an increase of $6.8 million, or 54%, from $12.6 million , or $0.04 per Mcfe, for the year ended December 31, 2023 .
NGL Revenues Our NGL revenues decreased by approximately $22.4 million, or 12%, to $165.5 million for the year ended December 31, 2024, from $187.9 million for the year ended December 31, 2023 .
NGL Revenues Our NGL revenues decreased by $22.4 million, or 12%, to $165.5 million for the year ended December 31, 2024 , from $187.9 million for the year ended December 31, 2023 .
The decrease in depreciation, depletion, amortization, a nd accretion during the year ended December 31, 2024 compared to the year ended December 31, 2023 was due to lower production during the year ended December 31, 2024 compared to the same period in the prior year, offset by lower estimated proved reserves resulting from lower natural gas prices used in the determination of proved reserves and from the divestiture of Chaffee and certain non-operated upstream assets in Chelsea in June 2024.
The decrease in depreciation, depletion, amortization, and accretion during the year ended December 31, 2024, compared to the year ended December 31, 2023, was due to lower production during the year ended December 31, 2024, compared to the same period in the prior year, offset by lower estimated proved reserves resulting from lower natural gas prices used in the determination of proved reserves and from the divestiture of Chaffee and certain non-operated upstream assets in Chelsea in June 2024.
Oil Revenues Our oil revenues decreased by approximately $1.8 million, or 22%, to $6.6 million for the year ended December 31, 2024, from $8.4 million for the year ended December 31, 2023 .
Oil Revenues Our oil revenues decreased by $1.8 million, or 22%, to $6.6 million for the year ended December 31, 2024, from $8.4 million for the year ended December 31, 2023 .
These cost savings were partially offset by a $12.6 million acceleration of time-based restricted stock units (“TRSU”) recognized upon the IPO (including $2.5 million in payroll taxes), $3.5 million in stock compensation expense under the 2024 Plan, and $3.7 million in higher payroll costs due to increased headcount in 2024.
These cost savings were partially offset by a $12.6 million acceleration of time-based restricted stock units (“TRSU”) recognized upon the IPO (including $2.5 million in payroll taxes), $3.5 million in stock compensation expense under the 2024 Equity and Incentive Compensation Plan (the "2024 Plan"), and $3.7 million in higher payroll costs due to increased headcount in 2024.
Marketing Revenues Our marketing revenues increased by approximately $2.0 million to $10.7 million for the year ended December 31, 2024 from $8.7 million for the year ended December 31, 2023.
Marketing Revenues Our marketing revenues increased by $2.0 million to $10.7 million for the year ended December 31, 2024 from $8.7 million for the year ended December 31, 2023 .
The decreased losses for the year ended December 31, 2024 was primarily attributable to the significant asset positions as of December 31, 2023 reversing due to settlement during 2024 , resulting in unrealized losses of $146.7 million, which included the sale of call options in January 2024 limiting our 2026/2027 pricing upside, and is currently in a long term liability position.
The decreased losses for the year ended December 31, 2024, was primarily attributable to the significant asset positions as of December 31, 2023, reversing due to settlement during 2024, resulting in unrealized losses 102 Table of Contents of $146.7 million, which included the sale of call options in January 2024 limiting our 2026/2027 pricing upside, and is currently in a long term liability position.
Certain ad valorem and production taxes are not applicable to our NEPA properties. 95 Table of Contents Gathering and Transportation Gathering and transportation expenses were $222.4 million, or $0.77 per Mcfe, for the year ended December 31, 2024, which was a decrease of approximately $26.6 million, or 11%, from $249.0 million, or $0.79 per Mcfe, for the year ended December 31, 2023.
Certain ad valorem and production taxes are not applicable to our NEPA properties. 104 Table of Contents Gathering and Transportation Gathering and transportation expenses were $222.4 million , or $0.77 per Mcfe, for the year ended December 31, 2024 , which was a decrease of $26.6 million , or 11% , from $249.0 million , or $0.79 per Mcfe, for the year ended December 31, 2023 .
The RBL Credit Agreement will mature on June 12, 2028. The obligations under the RBL Credit Agreement are secured and guaranteed on a secured basis by BKV Corporation, BKV Upstream Midstream, and all of BKV Upstream Midstream’s current and future material restricted subsidiaries.
The RBL Credit Agreement will mature on June 12, 2028. The obligations under the RBL Credit Agreement are secured and guaranteed on a senior secured basis by BKV Upstream Midstream and all of BKV Upstream Midstream’s current and future material restricted subsidiaries.
The increase in other operating expenses during the year ended December 31, 2024 compared to the same period in 2023 was primarily driven by the following factors: $5.3 million in CCUS operating expenses for CO 2 purchases and fuel and increased legal contingencies, $3.4 million in higher emissions monitoring costs, $2.1 million in well clean up costs and expenses related to a potential CCUS equity raise and investments, and $1.0 million in costs from the newly enacted EPA fees under the Inflation Reduction Act.
The increase in other operating expenses during the year ended December 31, 2024 was primarily driven by the following factors: $5.3 million in CCUS operating expenses for CO 2 purchases and fuel and increased legal contingencies, $3.4 million in higher emissions monitoring costs, $2.1 million in well clean up costs and expenses related to a potential CCUS equity raise and investments, and $1.0 million in costs from the newly enacted EPA fees under the Inflation Reduction Act.
Although we take every reasonable effort to ensure our reserves estimates are 105 Table of Contents representative of our actual reserves — for example, by involving independent reserves engineers in the assessment of the estimates — the subjective decisions and variances in the data available could give rise to revisions that could materially impact the accompanying historical consolidated financial statements.
Although we take every reasonable effort to ensure our reserves estimates are representative of our actual reserves — for example, by involving independent reserves engineers in the assessment of the estimates — the subjective decisions and variances in the data available could give rise to revisions that could materially impact the accompanying historical consolidated financial statements.
No claim has been made, nor are we aware of any liability which we may have, as it relates to any material environmental cleanup, restoration, or the violation of any rules or regulations relating thereto. Environmental expenditures are expensed or capitalized depending on their future economic benefit.
No claim has been made, nor are we aware of any liability which we may have, as it relates to any material environmental cleanup, restoration, or the violation of any rules or regulations relating thereto. 111 Table of Contents Environmental expenditures are expensed or capitalized depending on their future economic benefit.
Other factors significantly affecting our financial condition and results of operations include, among others: • success in drilling new wells; • the availability of attractive acquisition opportunities and our ability to execute them; • the amount of capital we invest in the leasing and development of our properties; • facility or equipment availability and unexpected downtime; and • delays imposed by or resulting from compliance with regulatory requirements. 91 Table of Contents Production Volumes.
Other factors significantly affecting our financial condition and results of operations include, among others: • success in drilling new wells; • the availability of attractive acquisition opportunities and our ability to execute them; • the amount of capital we invest in the leasing and development of our properties; • facility or equipment availability and unexpected downtime; and • delays imposed by or resulting from compliance with regulatory requirements.
Similarly, any additional capital contributions to BKV-BPP Cotton Cove must receive the unanimous approval of BKV-BPP Cotton Cove, LLC's six member board of managers, four of whom are appointed by us and two of whom are appointed by BPPUS.
Similarly, any additional capital contributions to BKV-BPP Cotton Cove must receive the unanimous approval of the BKV-BPP Cotton Cove Joint Venture's six-member board of managers, four of whom are appointed by us and two of whom are appointed by BPPUS.
Loss on early extinguishment of debt. Loss on early extinguishment of debt was $13.9 million for the year ended December 31, 2024 in connection with the early termination of our Term Loan Credit Facility and Revolving Credit Agreement that took place in June 2024. 96 Table of Contents Interest expense .
Loss on early extinguishment of debt. Loss on early extinguishment of debt was $13.9 million for the year ended December 31, 2024, in connection with the early termination of our Term Loan Credit Agreement and Revolving Credit Agreement that took place in June 2024. Interest expense .
The increase year-over-year was primarily due to an increase in third party gas sales of $2.7 million. 94 Table of Contents Operating Expenses Our operating expenses reflect costs incurred in the development, production and sale of natural gas, NGLs, and oil.
The increase year-over-year was primarily due to an increase in third party gas sales of $2.6 million. 103 Table of Contents Operating Expenses Our operating expenses reflect costs incurred in the development, production and sale of natural gas, NGLs, and oil.
Rather, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies. We may take advantage of these provisions until the last day of our fiscal year following the fifth anniversary of the date of our IPO. Such fifth anniversary will occur in 2029.
Rather, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies. 112 Table of Contents We may take advantage of these provisions until the last day of our fiscal year following the fifth anniversary of the date of our IPO.
Net c ash provided by operating activities was $118.5 million for the year ended December 31, 2024, compared to $123.1 million for the year ended December 31, 2023 .
Net cash provided by operating activities was $118.5 million for the year ended December 31, 2024 , compared to $123.1 million for the year ended December 31, 2023.
The following table provides information on our revenues and other operating income for the periods presented: Year Ended December 31, (in thousands, other than percentages) 2024 2023 $ Change % Change Revenues Natural gas revenues $ 385,456 $ 509,846 $ (124,390) (24) % NGL revenues 165,508 187,860 (22,352) (12) % Oil revenues 6,606 8,445 (1,839) (22) % Midstream revenues 12,560 16,168 (3,608) (22) % Derivative gains (losses), net (34,152) 238,743 (272,895) * Marketing revenues 10,668 8,710 1,958 22 % Gain on sale of business 7,080 — 7,080 * Gain on sales of assets 3,523 2,207 1,316 60 % Related party revenues 17,101 4,294 12,807 * Other 6,631 3,957 2,674 68 % Total revenues and other operating income $ 580,981 $ 980,230 *Percentage not meaningful Natural Gas Revenues Our natural gas revenues decreased by approximately $124.4 million, or 24%, to $385.5 million for the year ended December 31, 2024, from $509.8 million for the year ended December 31, 2023.
The following table provides information on our revenues and other operating income for the periods presented: 101 Table of Contents Year Ended December 31, (in thousands, other than percentages) 2024 2023 $ Change % Change Revenues Natural gas revenues $ 385,456 $ 509,846 $ (124,390) (24) % NGL revenues 165,508 187,860 (22,352) (12) % Oil revenues 6,606 8,445 (1,839) (22) % Midstream revenues 12,560 16,168 (3,608) (22) % Derivative gains (losses), net (34,152) 238,743 (272,895) * Marketing revenues 10,668 8,710 1,958 22 % Gain on sale of business 7,080 — 7,080 * Gain on sales of assets, net 3,523 2,207 1,316 60 % Section 45Q tax credits 14,021 701 13,320 * Related party revenues 3,080 3,593 (513) (14) % Other 6,631 3,957 2,674 68 % Total revenues and other operating income $ 580,981 $ 980,230 *Percentage not meaningful Natural Gas Revenues Our natural gas revenues decreased by $124.4 million, or 24%, to $385.5 million for the year ended December 31, 2024 , from $509.8 million for the year ended December 31, 2023 .
For further information regarding these arrangements, see Note 16 - Commitments and Contingencies to our consolidated financial statements and under “ —Loan Agreements and Credit Facilities — RBL Credit Agreement. ” Critical Accounting Policies and Estimates Management’s discussion and analysis of our financial condition and results of operations are based upon our historical consolidated financial statements, which have been prepared in accordance with GAAP.
For further information regarding these arrangements, see Note 16 - Commitments and Contingencies to our consolidated financial statements and under “ —Liquidity and Capital Resources — Loan Agreements and Credit Facilities.” 110 Table of Contents Critical Accounting Policies and Estimates Management’s discussion and analysis of our financial condition and results of operations are based upon our historical consolidated financial statements, which have been prepared in accordance with GAAP.
The decrease in interest expense during the year ended December 31, 2024 was primarily due to lower interest rates on our RBL Credit Facility, which we entered into on June 11, 2024, and the subsequent pay down on the outstanding balances on our SCB Credit Facility, the Revolving Credit Agreement, and the Term Loan Credit Agreement, which incurred higher interest rates.
The decrease in interest expense during the year ended December 31, 2025, was primarily due to lower interest rates and a lower outstanding balance on our RBL Credit Agreement, which we entered into on June 11, 2024, and subsequently paid down the outstanding balances on our SCB Credit Facility, the Revolving Credit Agreement, and the Term Loan Credit Agreement, which incurred higher interest rates.
This was slightly offset by an increase in the interest on the loan under the related party loan with BNAC, which provided for seven months of interest in 2022 compared to a full year in 2023 . Other income.
This was slightly offset by an increase in the interest on the loan under the related party loan with BNAC, which provided for seven months of interest in 2023 compared to a full year in 2024 . Income tax benefit (expense).
We currently believe that our cash flows from operations, cash on hand, borrowings under our RBL Credit Agreement, and our commodity hedges in place will provide sufficient liquidity to fund our operations and our capital expenditures into 2025, excluding our CCUS business.
We currently believe that our cash flows from operations, cash on hand, borrowings under our RBL Credit Agreement and the 2030 Senior Notes, the 2025 Equity Offering, and our commodity hedges in place will provide sufficient liquidity to fund our operations and our capital expenditures into 2026, excluding our CCUS business.
There were higher gains in the prior period due to a significant decrease in the forward curve commodity pricing for natural gas (NYMEX) and oil (WTI) assumptions used in the Monte Carlo simulations during the year ended December 31, 2023 compared to slight decreases during the year ended December 31, 2024 . Earnings (losses) from equity affiliate .
The higher gains in 2023 were due to a significant decrease in the forward curve commodity pricing for natural gas (NYMEX) and oil (WTI) assumptions used in the Monte Carlo simulations during that year compared to slight decreases in 2024. Earnings from equity affiliate .
We recognized a gain on contingent consideration liabilities accruing as an earnout obligation under the purchase agreements executed in connection with the Devon Barnett Acquisition and the Exxon Barnett Acquisition.
For the year ended December 31, 2024, we recognized a gain on contingent consideration liabilities accruing as an earnout obligation under the purchase agreements executed in connection with the Devon Barnett Acquisition and the Exxon Barnett Acquisition.
Our net working capital deficit was $71.6 million as of December 31, 2024 , compared to a deficit of $100.1 million as of December 31, 2023 . Our working capital fluctuates based on the timing of cash collections on accounts receivable and payments on accounts payable.
Our net working capital surplus was $170.0 million as of December 31, 2025 , compared to a working capital deficit of $71.6 million as of December 31, 2024 . Our working capital fluctuates based on the timing of cash collections on accounts receivable and payments on accounts payable.
During the year ended December 31, 2023, BKV-BPP Power made a distribution of $10.0 million to BKV Corporation, and during the year 104 Table of Contents ended December 31, 2022, no distributions were made by BKV-BPP Power or BKV-BPP Cotton Cove.
During the years ended December 31, 2025 and 2024, no distributions were made by BKV-BPP Power or BKV-BPP Cotton Cove. During the year ended December 31, 2023, BKV-BPP Power made a distribution of $10.0 million to BKV Corporation.
Emerging Growth Company Status We are an “emerging growth company” as defined under the JOBS Act. As a result, for so long as we qualify as an emerging growth company, we are eligible to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies.
As a result, for so long as we qualify as an emerging growth company, we are eligible to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies.
Our primary uses of cash during the years ended December 31, 2024 and 2023 were to pay down debt and fund the development of our natural gas properties, and during the year ended December 31, 2022, our primary use of cash was to fund our Exxon Barnett Acquisition.
Our primary uses of cash during the year ended December 31, 2025 were to fund the Bedrock Acquisition and the development of our natural gas properties. Our primary uses of cash during the years ended December 31, 2024 and 2023 were to pay down debt and fund the development of our natural gas properties.
This was offset by a decrease in operating fee income with BKV-BPP Power of $0.5 million due to contracted rate decreases. Other Revenue We generate a portion of our revenues from the sale of third-party natural gas. Other revenues was $6.6 million for the year ended December 31, 2024 compared to $4.0 million for the year ended December 31, 2023.
Related party revenues decreased during the year ended December 31, 2024, compared to the year ended December 31, 2023, from the decrease in operating fee income with BKV-BPP Power of $0.5 million due to contracted rate decreases. Other Revenues We generate a portion of our revenues from the sale of third-party natural gas.
Year Ended December 31, 2024 2023 2022 (in thousands) Total use of cash and cash equivalents for capital expenditures $ (100,916) $ (187,716) $ (248,097) (Increase) decrease in accrued capital expenditures (16,710) 23,863 (19,247) Capital expenditures (accrued) $ (117,626) $ (163,853) $ (267,344) Cash flows provided by (used in) financing activities .
Year Ended December 31, 2025 2024 2023 (in thousands) Total use of cash and cash equivalents for capital expenditures $ (300,165) $ (100,916) $ (187,716) (Increase) decrease in accrued capital expenditures (18,344) (16,710) 23,863 Capital expenditures (accrued) $ (318,509) $ (117,626) $ (163,853) Cash flows provided by (used in) financing activities .
Results of Operations Comparison of the Year Ended December 31, 2023 and 2022 Operating Revenues and Operating Income Our operating revenues and other income from operations include the activity from the sale of natural gas, NGLs, and oil, midstream revenues, gains and losses on our derivative contracts and on the sale of assets, marketing revenues, and other income from operations.
Results of Operations Comparison of the Year Ended December 31, 2024 and 2023 Operating Revenues and Operating Income Our operating revenues and other income from operations include the activity from the sale of natural gas, NGLs, and oil, midstream revenues, gains and losses on our derivative contracts and on the sales of our business and assets, marketing revenues, Section 45Q tax credits, related party revenues, and other income from operations.
The decrease was also due to the impact of commodity price decreases , excluding the effect of derivative settlements, which resulted in a $1.6 million decrease in year-over-year revenues (calculated as the change in the year-over-year average price times current period production volumes).
The decrease was also due to the impact of commodity price decreases , excluding the impact of derivative settlements, which accounted for a $0.2 million decrease in the year-over-year revenues (calculated as the change in the year-over-year average price times current year's production volumes).
Contributing to the cash inflow during the year ended December 31, 2024 were the total proceeds from the sale of Chaffee and certain non-operated upstream assets held by Chelsea of $132.6 million.
The increase in cash inflows of $213.9 million was due to the $132.6 million of total proceeds from the sale of Chaffee and certain non-operated upstream assets held by Chelsea during the year ended December 31, 2024.
For more information about our joint ventures with BPPUS, see “ Risk Factors - Risks Related to Our Power Generation Business - We operate our power generation business through a joint venture which we do not control ” and “ Risk Factors - Risks Related to Our CCUS Business - We operate the Cotton Cove Project through a joint venture that requires the consent of BPPUS for certain material actions. ” Internal Controls and Procedures As an emerging growth company, we are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act, and therefore are not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose.
For more information about our joint ventures with BPPUS, see “ — Risk Factors — Risks Related to Our Power Generation Business — We operate our power generation business through a joint venture that requires the consent of BPPUS for certain material actions. ” and “ Risk Factors — Risks Related to Our CCUS Business — We operate the Cotton Cove Project through a joint venture that requires the consent of BPPUS for certain material actions. ” Internal Controls and Procedures As an accelerated filer, we are required to comply with the SEC’s rules implementing Section 404(a) of the Sarbanes-Oxley Act of 2022.
The assets sold had an approximate carrying value of $97.3 million, which resulted in a gain on the sale of Chaffee of $7.1 million. Gains on Sales of Assets For the year ended December 31, 2024 , we sold other properties for $5.0 million in proceeds, which resulted in a gain on the sale of these properties of $3.6 million.
Gains (Losses) on Sales of Assets, Net For the year ended December 31, 2024, we sold other properties for $5.0 million in proceeds, which resulted in a gain on the sale of these properties of $3.6 million.
For further discussion on our derivative contracts, see Note 7 - Derivative Instruments in Item 8 of Part II, “ Financial Statements and Supplementary Data. ” The following is a comparison of average pricing excluding and including the effects of derivatives: Year Ended December 31, 2024 2023 2022 Average prices: Natural gas ($/Mcf): Average NYMEX Henry Hub price $ 2.27 $ 2.74 $ 6.64 Average natural gas realized price (excluding derivatives) $ 1.69 $ 2.04 $ 6.02 Average natural gas realized price (including derivatives) (1) $ 2.10 $ 2.23 $ 3.72 Differential $ (0.58) $ (0.70) $ (0.62) NGLs ($/Bbl): Average NGL realized price (excluding derivatives) $ 16.79 $ 17.80 $ 30.58 Average NGL realized price (including derivatives) (1) $ 17.19 $ 17.55 $ 27.78 Oil ($/Bbl): Average oil realized price $ 68.81 $ 70.97 $ 84.76 High and low daily spot prices: Oil ($/Bbl): High NYMEX WTI $ 87.69 $ 93.67 $ 123.64 Low NYMEX WTI $ 66.73 $ 66.61 $ 71.05 Natural gas ($/Mcf): High NYMEX Henry Hub $ 13.20 $ 3.78 $ 9.85 Low NYMEX Henry Hub $ 1.21 $ 1.74 $ 3.46 ___________________________________ (1) Impact of derivatives prices excludes $13.3 million and $46.7 million of gains on derivative contract terminations for the years ended December 31, 2024 and 2023, respectively, and $158.4 million of losses on derivative contract terminations for the year ended December 31, 2022. 92 Table of Contents Results of Operations Comparison of the Year Ended December 31, 2024 and 2023 Operating Revenues and Operating Income Our operating revenues and other income from operations include the activity from the sale of natural gas, NGLs, and oil, midstream revenues, gains and losses on our derivative contracts and on the sales of our business and assets, marketing revenues, related party revenues, and other income from operations.
For further discussion on our derivative contracts, see Note 7 - Derivative Instruments in Item 8 of Part II, “ Financial Statements and Supplementary Data. ” The following is a comparison of average pricing excluding and including the effects of derivatives: 96 Table of Contents Year Ended December 31, 2025 2024 2023 Average prices Natural gas ($/Mcf) Average NYMEX Henry Hub price $ 3.43 $ 2.27 $ 2.74 Average natural gas realized price (excluding derivatives) $ 2.78 $ 1.69 $ 2.04 Average natural gas realized price (including derivatives) (1) $ 2.75 $ 2.10 $ 2.23 Differential $ (0.65) $ (0.58) $ (0.70) NGLs ($/Bbl) Average NGL realized price (excluding derivatives) $ 17.00 $ 16.79 $ 17.80 Average NGL realized price (including derivatives) (1) $ 16.84 $ 17.19 $ 17.55 Oil ($/Bbl) Average oil realized price $ 59.50 $ 68.81 $ 70.97 High and low daily spot prices Oil ($/Bbl) High NYMEX WTI $ 80.73 $ 87.69 $ 93.67 Low NYMEX WTI $ 55.44 $ 66.73 $ 66.61 Natural gas ($/Mcf) High NYMEX Henry Hub $ 9.86 $ 13.20 $ 3.78 Low NYMEX Henry Hub $ 2.65 $ 1.21 $ 1.74 ___________________________________ (1) Impact of derivatives prices excludes $13.3 million and $46.7 million of gains on derivative contract terminations for the years ended December 31, 2024 and 2023, respectively.
Beginning with the fiscal quarter ending September 30, 2024, the RBL Credit Agreement requires BKV Upstream Midstream and its restricted subsidiaries to always hedge not less than 50% of projected production from their proved developed producing reserves for the subsequent 24 calendar month period immediately following such required delivery date.
The RBL Credit Agreement requires BKV Upstream Midstream and its restricted subsidiaries to always hedge not less than 50% of reasonably anticipated projected production from their proved developed producing reserves for the subsequent 24 calendar month period immediately following the date financial statements are required to be delivered under the RBL Credit Agreement for each fiscal quarter.
Earnings from our equity affiliate was $16.9 million for the year ended December 31, 2023 which was a change of $8.4 million from $8.5 million compared to the same period in 2022 . Earnings from our equity affiliate is related to our investment in, and our proportionate share in the income or losses of, the BKV-BPP Power Joint Venture.
Earnings from our equity affiliate was $14.9 million for the year ended December 31, 2025, which was an increase of $4.5 million, from $10.4 million for the year ended December 31, 2024. Earnings from our equity affiliate is related to our investment in, and our proportionate share in the income or losses of the BKV-BPP Power Joint Venture.
Off-Balance Sheet Arrangements We may enter into off-balance sheet arrangements and transactions that could give rise to material off-balance sheet arrangements. As of December 31, 2024, our material off-balance sheet arrangements and transactions included volume commitments of $320.6 million and letters of credit of $14.1 million against the RBL Credit Agreement.
Off-Balance Sheet Arrangements We may enter into off-balance sheet arrangements and transactions that could give rise to material off-balance sheet arrangements. As of December 31, 2025, our material off-balance sheet arrangements and transactions included natural gas transportation commitments of $259.4 million and letters of credit of $15.0 million against the RBL Credit Agreement.
The impact of commodity price decreases , excluding the effect of derivative settlements, resulted in a $994.3 million decrease in year-over-year revenues (calculated as the change in the year-over-year average price times current year production volumes).
The impact of commodity price increases, excluding the effect of derivative settlements, provided a $265.6 million increase in year-over-year revenues (calculated as the change in the year-over-year average price times current year's production volumes).
The RBL Credit Agreement is secured by substantially all of the assets of BKV Corporation, BKV Upstream Midstream, and its restricted subsidiaries that are guarantors, and upon an event of default the agent under the RBL Credit Agreement could commence foreclosure proceedings.
The RBL Credit Agreement is 109 Table of Contents secured by substantially all of BKV Upstream Midstream's assets and those of the guarantors, and upon an event of default the agent under the RBL Credit Agreement could commence foreclosure proceedings.
BKV-BPP Power and BKV-BPP Cotton Cove Joint Ventures Under the terms of the BKV-BPP Power LLC Agreement and BKV-BPP Cotton Cove LLC Agreement, we do not have the ability to unilaterally cause BKV-BPP Power or BKV-BPP Cotton Cove to make distributions. During the year ended December 31, 2024, no distributions were made by BKV-BPP Power or BKV-BPP Cotton Cove.
BKV-BPP Power and BKV-BPP Cotton Cove Joint Ventures Under the terms of the BKV-BPP Power LLC Agreement and BKV-BPP Cotton Cove LLC Agreement, as applicable, we do not have the ability to unilaterally cause BKV-BPP Power or BKV-BPP Cotton Cove to make distributions.
Our related party revenues were $4.3 million for the year ended December 31, 2023 , as compared to $2.7 million for the year ended December 31, 2022 .
Our related party revenues were $3.1 million for the year ended December 31, 2024 , compared to $3.6 million for the year ended December 31, 2023 .
Derivative Gains (Losses), Net For the year ended December 31, 2023 , we had net realized and unrealized gains on derivative contracts of $238.7 million compared to net realized and unrealized losses on derivative contracts of $629.7 million for the year ended December 31, 2022 .
Derivative Gains (Losses), Net For the year ended December 31, 2025 , we had net realized and unrealized gains on derivative contracts of $105.1 million compared to net realized and unrealized losses on derivative contracts of $34.2 million for the year ended December 31, 2024.
However, if certain events occur prior to the end of such five-year period, including if we become a “large accelerated filer,” our gross revenues for any fiscal year equal or exceed 106 Table of Contents $1.235 billion or we issue more than $1.0 billion of non-convertible debt in any three-year period, we will cease to be an emerging growth company prior to the end of such five-year period.
However, if certain events occur prior to the end of such five-year period, including if (i) we become a “large accelerated filer,” which requires that the market value of our common equity held by non-affiliates be at least $700 million as of the end of the most recently completed second fiscal quarter, (ii) our gross revenues for any fiscal year equal or exceed $1.235 billion, or (iii) we issue more than $1.0 billion of non-convertible debt in any three-year period, then we will cease to be an emerging growth company prior to the end of such five-year period.
Other Revenue Other revenues were $4.0 million for the year ended December 31, 2023 , as compared to $0.1 million for the year ended December 31, 2022 .
Other revenues was $6.6 million for the year ended December 31, 2024 , compared to $4.0 million for the year ended December 31, 2023 .
However, any additional capital contributions to BKV-BPP Power must be approved by a majority of BKV-BPP Power 's ten member board of managers, five of whom are appointed by us and five of whom are appointed by BPPUS.
However, following the closing of the BKV-BPP Power Joint Venture Transaction on January 30, 2026, any additional capital contributions to BKV-BPP Power must be approved by a majority of BKV-BPP Power 's twelve member board of managers, nine of whom are appointed by us and three of whom are appointed by BPPUS.
The decrease was primarily due to the payment in full of the loan under the $116 Million Loan Agreement (as defined herein) in 2022 , which provided nine months of interest compared to none in 2023 .
The decrease was primarily due to the payment in full of the loan with BNAC in 2023 , which provided nine months of interest compared to none in 2024 .
The decrease was driven by lower production volumes during the year ended December 31, 2023 , which accounted for a $1.8 million decrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year average price).
The increase was due to higher production volumes during the year ended December 31, 2025, which accounted for a $5.5 million increase in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price).
This was offset by higher production volumes, primarily from the 2022 Barnett Assets, during the year ended December 31, 2023 , which accounted for a $193.8 million increase in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year average price).
The increase was due to higher production volumes during the year ended December 31, 2025, which accounted for a $4.4 million increase in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price).
See Item 1A of Part I, “Risk Factors” and under “Cautionary Note Regarding Forward-Looking Statements.” Overview We are a forward thinking, growth driven energy company focused on creating value for our stockholders through the organic development of our properties as well as accretive acquisitions.
See Item 1A of Part I, “Risk Factors” and under “Cautionary Note Regarding Forward-Looking Statements.” Overview We are a forward-thinking, growth-driven energy company focused on creating long-term risk-adjusted stockholder value through the development of natural gas producing assets, the ownership and operation of natural gas-fired power generation assets, and selective accretive acquisitions.
Net cash provided by operating activities decreased during the year ended December 31, 2024 compared to the year ended December 31, 2023 due to a $41.5 million decrease in income from operations (excluding net unrealized gains (losses), depreciation, depletion, amortization, and accretion, equity-based compensation, and gain on sales of assets), resulting from lower natural gas prices compared to 2023, a $17.3 million decrease in working capital, $10.0 million in distributions from the BKV-BPP Power Joint Venture made in 2023, and $3.9 million of transaction costs associated with the sale of Chaffee and certain non-operated upstream assets in Chelsea.
The decrease of $4.5 million was due to a $41.5 million decrease in income from operations (excluding non-cash items), resulting from lower natural gas prices compared to 2023, an unfavorable $17.3 million change in working capital, $10.0 million in distributions from the BKV-BPP Power Joint Venture made in 2023, and $3.9 million of transaction costs associated with the sale of Chaffee and certain non-operated upstream assets in Chelsea.
We terminated the Term Loan Credit Agreement concurrently with the repayment of such outstanding borrowings. 103 Table of Contents RBL Credit Agreement On June 11, 2024, BKV Corporation, as guarantor, and BKV Upstream Midstream, as borrower, entered into the RBL Credit Agreement with Citibank, N.A., as the administrative agent, and the financial institutions party thereto.
Loan Agreements and Credit Facilities RBL Credit Agreement On June 11, 2024, BKV Corporation, as a guarantor, and BKV Upstream Midstream, as borrower, entered into the RBL Credit Agreement with Citibank, N.A., as the administrative agent, and the financial institutions party thereto. The RBL Credit Agreement includes a maximum credit commitment of $1.5 billion.
The RBL Credit Agreement includes customary equity cure rights that will enable us to cure certain breaches of the minimum current ratio covenant or the maximum net leverage ratio covenant. The RBL Credit Agreement generally includes customary events of default for a reserve-based credit facility, some of which allow for an opportunity to cure.
The RBL Credit Agreement includes customary equity cure rights that will enable us to cure certain breaches of the minimum current ratio covenant or the maximum net leverage ratio covenant (subject to certain limitations in the RBL Credit Agreement).
Operational and Financial Highlights Below are some highlights of our operating and financial results for the year ended December 31, 2024. • Production of natural gas, NGLs, and oil was 288.4 Bcfe. • Average realized product prices, excluding the impact of settled derivatives, were $1.93 per Mcfe. • Production revenues were $557.6 million and midstream revenues were $12.6 million. • Lease operating expense was $132.3 million, or $0.46 per Mcfe. • Net income (loss) was $(142.9) million. • Net cash provided by operating activities was $118.5 million. • Accrued capital expenditures were $117.6 million.
Operational and Financial Highlights Below are some highlights of our operating and financial results for the year ended December 31, 2025. • Production of natural gas, NGLs, and oil was 305.0 Bcfe, or 835.5 MMcfe/d. • Average realized product prices, excluding the impact of settled derivatives, were $2.81 per Mcfe. 94 Table of Contents • Production revenues were $857.6 million and midstream revenues were $10.5 million. • Lease operating expense was $145.6 million, or $0.48 per Mcfe. • Net income attributable to BKV was $173.1 million. • Net cash provided by operating activities was $242.7 million. • Accrued capital expenditures were $318.5 million.
We expect our owned and operated upstream and natural gas midstream businesses to achieve net zero Scope 1 and Scope 2 emissions by the early 2030s, and net zero Scope 1, 2, and 3 emissions by the late 2030s. We maintain a “closed-loop” approach to our net zero emissions goal through the operation of our four business lines.
As part of our ongoing operations, we expect our owned and operated upstream and natural gas midstream businesses to achieve net-zero Scope 1 and Scope 2 greenhouse gas emissions during the early 2030s and net-zero Scope 1, Scope 2, and Scope 3 emissions by the late 2030s.
Our core business is to produce natural gas from our owned and operated upstream businesses, which are supported by our four business lines: natural gas production; our natural gas midstream business; power generation; and CCUS.
Our core businesses are the production of natural gas and the generation of natural gas-fired power from our owned and operated assets, supported by a closed-loop strategy enabled by our upstream, midstream, power, and CCUS businesses. Our operations are supported by four business lines: natural gas production, natural gas midstream, power generation, and CCUS.
The impact of commodity price decreases , excluding the effect of derivative settlements, provided a $134.9 million decrease in year-over-year revenues (calculated as the change in 97 Table of Contents the year-over-year average price times current period production volumes).
The increase was offset by the impact of commodity price decreases, excluding the effect of derivative settlements, which accounted for a $1.5 million decrease in the year-over-year revenues (calculated as the change in the year-over-year average price times current year's production volumes).
We will continue to monitor commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.
We will continue to monitor commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions. On January 14, 2026, we entered into a manufacturing reservation agreement related to a planned power generation project.
This was offset by higher production volumes, primarily from the 2022 Barnett Assets, during the year ended December 31, 2023 , which accounted for a $11.2 million increase in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year average price).
The increase was also due to higher production volumes during the year ended December 31, 2025, which accounted for a $24.0 million increase in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price).
Other Income (Expense) Gains on contingent consideration liabilities. We recognized a gain on contingent consideration liabilities accruing as an earnout obligation under the purchase agreements executed in connection with the Devon Barnett Acquisition and the Exxon Barnett Acquisition.
We recognized a gain on contingent consideration liabilities accruing as an earnout obligation under the purchase agreements executed in connection with the Devon Barnett Acquisition and the Exxon Barnett Acquisition. The gain on contingent consideration liabilities was $9.7 million in 2024, compared to $38.4 million in 2023, which was a decrease of $28.7 million.
Related party revenues increased during the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to an increase in Section 45Q tax credits of $13.3 million from the injection of CO 2 waste in our Barnett Zero well, which started in the fourth quarter of 2023.
Section 45Q Tax Credits Our Section 45Q tax credits increased by $13.3 million to $14.0 million for the year ended December 31, 2024 from $0.7 million for the year ended December 31, 2023. This increase was due to higher volumes of CO 2 waste sequestered in 2024, which started in the fourth quarter of 2023.
This decrease was primarily due to the divestiture of Chaffee of $2.6 million as we sold our Repsol Midstream Interest in connection with this sale. The remainder of the decrease was due to changes in deal structures that reduced midstream transportation revenue while increasing third party gas sales.
The remainder of the decrease was due to the changes in deal structures that reduced midstream transportation revenue while increasing third party gas sales.
Other Operating Expenses Other operating expenses were $12.6 million , or $0.04 per Mcfe, for the year ended December 31, 2023 , which was an increase of $9.0 million from $3.6 million , or $0.01 per Mcfe, for the year ended December 31, 2022 .
Other Operating Expenses Other operating expenses were $54.9 million, or $0.18 per Mcfe, for the year ended December 31, 2025, which was an increase of $35.5 million, from $19.4 million, or $0.07 per Mcfe, for the year ended December 31, 2024.
During the years ended December 31, 2024, 2023, and 2022, cash paid for capital expenditures was $100.9 million, $187.7 million, and $248.1 million, respectively. Our current estimated budget for total capital expenditures in 2025 is approximately $320 million to $380 million. Capital expenditures for our operated properties are largely discretionary and within our control.
During the years ended December 31, 2025, 2024, and 2023, cash paid for capital expenditures was $300.2 million, $100.9 million, and $187.7 million, respectively. Our current estimated budget for total accrued capital expenditures in 2026 is approximately $410 million to $560 million on a Company-wide basis.
Operating cash flow fluctuations are substantially driven by realized commodity prices, production volumes, and operating expenses. Prices for natural gas and NGLs have historically been volatile, primarily as a result of supply and demand, pipeline infrastructure constraints, basis differentials, inventory storage levels, and seasonal influences.
Prices for natural gas and NGLs have historically been volatile, primarily as a result of supply and demand, pipeline infrastructure constraints, basis differentials, inventory storage levels, and seasonal influences. We are unable to predict future commodity prices and therefore cannot provide assurance about future levels of cash provided by operating activities. Cash flows provided by (used in) investing activities .
The drivers of the current period inflow were the $258.5 million and $117.0 million of advances received from the Revolving Credit Facilities and Revolving Credit Agreement, respectively. In addition, we received a capital contribution from BNAC in the amount of $150.0 million in exchange for 7,500,000 shares of our common stock.
Net cash provided by financing activities was $66.7 million for the year ended December 31, 2023, which consisted of $258.5 million and $117.0 million of advances received from the Revolving Credit Facilities and Revolving Credit Agreement, respectively. In addition, we received $150.0 million of capital contributions from BNAC in exchange for 7,500,000 shares of our common stock.
The $9.7 million gain compared to the $38.4 million gain was primarily attributable to the prior period’s gain on contingent consideration liabilities with the Devon Barnett Acquisition of $25.0 million compared to the current period's gain of $7.5 million , as well as the prior period's gain on contingent consideration liabilities with the Exxon Barnett Acquisition of $13.4 million compared to the current period's gain of $2.2 million .
The decrease was primarily attributable to lower gains on contingent consideration liabilities with the Devon Barnett Acquisition and the Exxon Barnett Acquisition. Gains related to the Devon Barnett Acquisition were $7.5 million in 2024 compared to $25.0 million in 2023, and gains related to the Exxon Barnett Acquisition were $2.2 million in 2024 compared to $13.4 million in 2023.
Gathering and Transportation Gathering and transportation expenses were $249.0 million , or $0.79 per Mcfe, for the year ended December 31, 2023 , which was an increase of $40.2 million , or 19% , from $208.8 million , or $0.75 per Mcfe, for the year ended December 31, 2022 .
Gathering and Transportation Gathering and transportation expenses were $250.8 million, or $0.82 per Mcfe, for the year ended December 31, 2025, which was an increase of $28.5 million, or 13%, from $222.4 million, or $0.77 per Mcfe, for the year ended December 31, 2024.
Capital Resources Historically, our primary sources of capital and liquidity have consisted of internally generated cash flows from operations, together with loans and capital contributions from our majority stockholder, BNAC. We also enter into financial instruments to reduce the impact of commodity price volatility and provide a level of certainty and stability around of cash flows.
We also enter into financial instruments to reduce the impact of commodity price volatility and provide a level of certainty and stability around cash flows.
Interest expense from related parties was $7.1 million for the year ended December 31, 2023 , which was a decrease of $3.7 million from $10.8 million for the year ended December 31, 2022 .
Interest income was $1.6 million for the year ended December 31, 2025 , which was a decrease of $2.3 million, from $3.9 million for the year ended December 31, 2024 .

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

13 edited+5 added−5 removed14 unchanged
By removing price volatility from a portion of our expected production through December 2027, we have mitigated, but not eliminated, the potential negative effects of changing prices on our operating cash flows for those periods.
By removing price volatility from a portion of our expected production through December 2028, we have mitigated, but not eliminated, the potential negative effects of changing prices on our operating cash flows for those periods.
We rely on the credit worthiness of such third party marketer, who collects directly from the purchasers and remits to us the total of all amounts collected on our behalf, less their fee for making such sales.
We rely on the creditworthiness of such third party marketer, who collects directly from the purchasers and remits to us the total of all amounts collected on our behalf, less their fee for making such sales.
As of December 31, 2024, the estimated fair value of our commodity derivative instruments was a net liability of $67.6 million, comprised of current and noncurrent liabilities. As of December 31, 2023, the estimated fair value of our commodity derivative instruments was a net asset of $102.5 million, comprised of current and noncurrent assets.
As of December 31, 2025, the estimated fair value of our commodity derivative instruments was a net asset of $82.4 million, comprised of current and noncurrent assets and noncurrent liabilities. As of December 31, 2024, the estimated fair value of our commodity derivative instruments was a net liability of $67.6 million, comprised of current and noncurrent liabilities.
Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment; therefore, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our consolidated 107 Table of Contents statements of operations.
The fair values of our derivative instruments are adjusted for non-performance risk. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment; therefore, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our consolidated statements of operations.
The derivative contracts outstanding as of December 31, 2024 consisted of commodity price swaps, basis differential swaps, call options, and producer collar agreements, subject to master netting agreements with each individual counterparty. These derivative contracts cover portions of our projected positions through 2027.
The derivative contracts outstanding as of December 31, 2025 consisted of commodity swaps, basis swaps, put and call options, and producer collar agreements, subject to master netting agreements with each individual counter party. These derivative contracts cover portions of our projected positions through 2028.
BKV-BPP Power is exposed to basis risk in its operations when its derivative contracts settle financially and it delivers physical electricity on different terms. For example, if BKV-BPP Power enters into an HRCO, it hedges its electricity production based on an agreed price for that electricity, but physical electricity must be delivered to delivery points in the market it serves.
For example, if BKV-BPP Power enters into an HRCO, it hedges its electricity production based on an agreed price for that electricity, but physical electricity must be delivered to delivery points in the market it serves.
Pricing for natural gas and NGLs has historically been volatile and unpredictable, and we expect this volatility to continue in the future. The prices we receive for our production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.
The prices we receive for our production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.
We estimate that a 1.0% increase in the applicable average interest rates during the years ended December 31, 2024 and 2023 would have resulted in increases of $4.9 million and $7.8 million in interest expense, respectively. 108 Table of Contents
We estimate that a 1.0% increase in the applicable average interest rates during the year ended December 31, 2025 would have resulted in an increase of $1.8 million in interest expense. 114 Table of Contents
Our commodity hedge position as of December 31, 2024 is summarized in “ Note 7 - Derivative Instruments ” to our consolidated financial statements. We may enter into single hedge transactions with settlements up to 48 months.
Our commodity hedge position as of December 31, 2025 is summarized in Note 7 - Derivative Instruments to our consolidated financial statements. We may enter into single hedge transactions with settlements up to 48 months. The aggregation of these executed hedge instruments may not exceed certain limits without board of director approval of our forecasted production volumes.
All derivative instruments, other than those that meet the normal purchase and normal sale scope exception, are recorded at fair market value in accordance with GAAP and are included in our consolidated balance sheets as assets or liabilities. The fair values of our derivative instruments are adjusted for non-performance risk.
Either such event could have a material adverse effect on BKV-BPP Power, and thus on our business, financial condition, results of operations, and cash flows. 113 Table of Contents All derivative instruments, other than those that meet the normal purchase and normal sale scope exception, are recorded at fair market value in accordance with GAAP and are included in our consolidated balance sheets as assets or liabilities.
During the years ended December 31, 2024, 2023, and 2022, a hypothetical increase or decrease of $0.10 per Mcf in NYMEX would have resulted in a $9.7 million, $1.6 million, and $7.7 million decrease or increase in natural gas hedge revenues, respectively, and a hypothetical increase or decrease of $1.00 per Bbl of NGL purity product price would have resulted in a $7.0 million, $1.9 million, and $4.6 million decrease or increase in NGL hedge revenues, respectively.
For the year ended December 31, 2025, a hypothetical increase of $0.10 per Mcf in NYMEX would have resulted in a $13.1 million decrease in natural gas hedge revenues, while a hypothetical decrease of $0.10 per Mcf in NYMEX would have resulted in a $13.2 million increase in natural gas hedge revenues.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Commodity Price Risk and Hedging Activities Our primary market risk exposure is in the price we receive for our natural gas and NGL production. Pricing is primarily driven by spot regional market prices applicable to our U.S. natural gas production.
Pricing is primarily driven by spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas and NGLs has historically been volatile and unpredictable, and we expect this volatility to continue in the future.
The average annualized interest rate incurred on our outstanding borrowings during the years ended December 31, 2024 and 2023 was approximately 9.3% and 8.7%, respectively .
For more information on our 2030 Senior Notes, see Note 4 - Debt and Note 6 - Fair Value Measurements to our consolidated financial statements included in Item 8 of Part II of this report. The average annualized interest rate incurred on our outstanding variable rate borrowings during the year ended December 31, 2025 was approximately 7.4% .
Removed
The aggregation of these executed hedge instruments may not exceed 60% without board of director approval of our forecasted production volumes for the current year and subsequent year, and for up to 40% and 25% of our forecasted production volumes in each of the respective subsequent years thereafter.
Added
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Commodity Price Risk and Hedging Activities As of December 31, 2025 , we did not enter into any trading market risk sensitive instruments, and our market risk sensitive instruments consisted entirely of non-trading instruments entered into for risk management purposes related to our natural gas and NGL production and power operations.
Removed
Either such event could have a material adverse effect on BKV-BPP Power, and thus on our business, financial condition, results of operations, and cash flows.
Added
A hypothetical increase of $1.00 per Bbl of NGL purity product price would have resulted in a $5.6 million decrease, while a $1.00 per Bbl decrease would have resulted in a $5.6 million increase.
Removed
Interest Rate Risks As of December 31, 2024 , our primary exposure to interest rate risk resulted from our $165.0 million of outstanding borrowings on our RBL Credit Agreement, which has a floating interest rate.
Added
These HRCOs are entered into to economically hedge power price and fuel cost exposures rather than for trading purposes. BKV-BPP Power is exposed to basis risk in its operations when its derivative contracts settle financially and it delivers physical electricity on different terms.
Removed
As of December 31, 2023, our primary exposure to interest rate risk resulted from our outstanding related party borrowings with BNAC, the Term Loan Credit Agreement, the Revolving Credit Agreement, and the SCB Credit Facility, all of which had floating interest rates.
Added
Although these derivatives are not designated as accounting hedges for GAAP purposes, they are not entered into for trading or speculative purposes and are intended to manage commodity price and basis risk associated with our operations.
Removed
As of December 31, 2023, we had $75.0 million of outstanding borrowings with BNAC, $456.0 million of outstanding borrowings under the Term Loan Credit Agreement, $31.0 million of outstanding borrowings under the SCB Credit Facility, and $96.0 million of outstanding borrowings under the Revolving Credit Agreement.
Added
Interest Rate Risks As of December 31, 2025 , we did not have primary exposure to interest rate risk due to the zero balance on our RBL Credit Agreement. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate 2030 Senior Notes, but can affect their fair values.