NYSE: BKV

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.

We believe our business model, experienced management team, and disciplined technology-enabled operations support our ability to create long-term, risk-adjusted stockholder value.

Initial Public Offering

On September 27, 2024, we completed our initial public offering (“IPO”) of 15,000,000 shares of our common stock at a price to the public of $18.00 per share. We also granted the underwriters of our IPO a 30-day option to purchase up to 2,250,000 additional shares of common stock on the same terms. The underwriters partially exercised the option and, on October 28, 2024, purchased 701,003 additional shares of common stock. 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 used $200.0 million to pay down a portion of our outstanding borrowings, including interest, under our RBL Credit Agreement, and $50.0 million to repay the outstanding balance, including interest, under our related party loan with BNAC, our majority stockholder. The remaining amounts were used for growth capital expenditures and other general corporate purposes.

Strategy

Our strategy is to create value for our stockholders by managing and growing our integrated asset base and focusing on our net zero objectives. We believe the following strategic priorities will help drive value creation and long-term success.

Optimize the value of our core businesses. We utilize technology and data analysis to enhance our assets and operations, which we believe improves operational efficiencies, reduces our emissions, and helps us realize our operational and financial goals as we continue to scale our business. 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. We have also improved pad efficiencies and reduced lease operating costs through improvements including leveraging of data analytics to coordinate the workforce, prioritize high-value activity, and assess individual well profitability; automating critical plunger set points; in-sourcing key services such as slick-line, value re-builds, compression overhaul, and location repair and maintenance; and entering water share arrangements to reduce disposal and trucking cost. 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.

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Grow through opportunistic, synergistic acquisitions. A significant element of our business strategy is gaining scale through accretive acquisitions. We believe our business model, management team experience, and application of technology enable us to quickly and efficiently integrate additional upstream, midstream, power, and CCUS assets into our business.

Maintain a disciplined financial strategy. We believe we can execute on our business plan and grow our business while continuing to generate substantial Adjusted Free Cash Flow. We believe our capital efficient project inventory, low-decline natural gas production, and multiple integrated business lines will provide consistent returns through varying business cycles. We intend to apply our cash flows to manage our indebtedness in line with our leverage target, fund our capital expenditure program, enhance stockholder value, and execute opportunistic acquisitions across our four business lines.

Focus on our net zero objectives. We seek to apply our integrated business model, CCUS projects, and carbon-negative initiatives to realize Scope 1 and 2 net zero emissions from our owned and operated upstream and natural gas midstream businesses during the early 2030s. 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 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.

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. We intend to continue to develop, retain, and add to our already talented, experienced, and forward-thinking employees. Our unified team and mantra of “Being a force for good” support our core values and provide us with confidence in our ability to successfully manage and grow our business.

Deliver robust returns to stockholders. We intend to prioritize delivering strong returns to our stockholders through our focus on creating stockholder value. We believe our operational expertise in successfully drilling and refracturing wells, acquiring and integrating assets purchased at attractive valuations, and maintaining financial discipline will underpin our ability to meet our stockholder return goals.

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. For the year ended December 31, 2025, our net daily production (after giving effect to the Bedrock Acquisition) averaged 835.5 MMcfe/d, consisting of approximately 80% natural gas and approximately 20% NGLs. As of December 31, 2025, our total proved reserves of 5,921 Bcfe had an estimated 7.4% year-over-year average base decline rate over the next 10 years.

As of December 31, 2025, our Barnett acreage position was approximately 544,000 net acres, substantially all of which was held by production. Our average daily Barnett production of approximately 742.0 MMcfe/d for the year ended December 31, 2025 consisted of approximately 77% natural gas and approximately 23% NGLs. 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. Our average net daily production of 93.6 MMcfe/d for the year ended December 31, 2025 consisted entirely of natural gas. As of December 31, 2025, we had an average working interest in our operated wells in NEPA of 87.8%.

On September 29, 2025, BKV Upstream Midstream acquired 100% of the equity interests of Bedrock Production, LLC (now known as BKV Barnett II, LLC (“BKV Barnett II”)), a Texas limited liability company (such transaction, the “Bedrock Acquisition”). BKV Barnett II and its subsidiaries own certain oil and natural gas producing properties and midstream assets in the Barnett Shale. As a result of the Bedrock Acquisition, we acquired approximately 96,000 net acres and gas gathering lines, 1,121 producing locations with low 1- and 5-year base decline rates of approximately 7%, and nearly 1 Tcfe of proved reserves (>70% PDP reserves) using NYMEX strip pricing. The Bedrock Acquisition is expected to increase our production over 100 MMcfe/d and enhance our inventory in the Barnett Shale, aligning with our strategic position in the Fort Worth Basin.

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Certification and Market Positioning. As of December 31, 2025, we re-certified approximately 72% of our NEPA production and 46% of our Barnett production under the TrustWell environmental assessment program of Project Canary, an environmental certification and ESG data company. All of our TrustWell-certified production received a Gold or Silver rating from Project Canary. Since our initial certification in 2021, the RSG market has not materialized, and during 2026, Project Canary will be closing down its TrustWell program. We may seek to certify our production against the MiQ Standard and/or align with the Oil & Gas Methane Partnership 2.0 (OGMP 2.0) of the United Nations ("UN") Environment Programme. Because there has yet to be a U.S. domestic standard for certification, we intend to position ourselves for a variety of competitive landscapes to promote market access and advance our own market for low carbon, and carbon neutral gas products by utilizing our “Carbon Sequestered Gas,” which is a Scope 1, 2, and 3 carbon neutral natural gas product.

Carbon Sequestered Gas. 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 have an agreement with a third party to establish the blockchain ledger and tokens; however, this process is dependent upon the development of the necessary technology by such third party. In addition, we expect to utilize the blockchain ledger and tokens for carbon offset produced natural gas developed by existing carbon registries such as ACR (formerly American Carbon Registry) or Verra, as those methodologies are currently being established. The carbon credits included in our Carbon Sequestered Gas will be generated by our CCUS projects, as described below in “- Path to Net Zero Emissions” and retired against our Scope 1 and/or Scope 3 emissions. 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. The carbon credits included in our Carbon Sequestered Gas will be generated by our CCUS projects and will be third party verified. We plan to commence delivery of Carbon Sequestered Gas upon completion of our certification process with the ACR (see “- Carbon Capture, Utilization and Sequestration” below).

In August 2025, BKV entered into a deal with Gunvor Group, Ltd. ("Gunvor"), a leading commodities trader for Carbon Sequestered Gas. This deal covers up to 10,000 MMBtu/d and allows Gunvor to purchase, market, and sell this premium commodity market product.

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. Our midstream assets improve our overall corporate returns by enhancing our margins and lowering our break-even operating costs while allowing us to manage the timing, development, and optimization of production of our upstream assets.

Barnett

In the Barnett, during the year ended December 31, 2025, approximately 202 MMcf/d of our gross production (approximately 20% of our total gross Barnett production) was gathered and processed by our owned Barnett midstream system, which includes approximately 870 miles of gathering pipeline, 61 midstream compressors, and one amine processing unit. Our remaining Barnett production was gathered and processed primarily under an agreement with ONEOK (formerly EnLink) with no minimum volume commitments (“MVC”).

For the assets we acquired in the Bedrock Acquisition, the substantial majority of our natural gas is gathered and transported by third parties, with less than 5% gathered and transported by us. For the assets we acquired in the Exxon Barnett Acquisition, approximately 90% of our natural gas is gathered and transported through an agreement assigned to our wholly-owned subsidiary, BKV Midstream, LLC, through various market-rate based contracts that take lean gas to various delivery points into Energy Transfer’s pipeline. All gas currently flows to Energy Transfer, where BKV is under an acreage dedication for its downstream takeaway. For the assets we acquired in the Devon Barnett Acquisition, approximately 95% of our natural gas is gathered and transported by ONEOK through various contracts that govern the services provided for the Bridgeport, Ponder, and Jarvis systems. The Bridgeport system consists of both rich and lean gas governed by a market-rate based contract, as amended, with a term expiring in 2033. The gathering and processing fees under the Bridgeport contract contain an incentive mechanism pursuant to which we can achieve lower rates through refractured or new wells. All NGLs under the Bridgeport contract are sold to ONEOK at Mont Belvieu pricing subject to a

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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.

Additionally, our owned Barnett midstream system has over 200 MMcf/d in unutilized pipeline and processing capacity, providing room to increase throughput (from our own production and for third-party volumes) while maintaining optimal operating pressure with limited additional capital investment required. We also believe we have ample dedicated capacity on third party midstream systems for our expected production and future development.

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. Our gross operated production volumes in NEPA are contractually gathered and treated primarily by three third-party providers. For the year ended December 31, 2025, approximately 52%, 41%, and 7% of our gross operated volumes in NEPA were further gathered, treated, and transported to sales on the gathering systems of UGI Energy Services Midstream Services, Williams Companies, and Energy Transfer, respectively. We have secured these services through acreage dedications, pursuant to which current and future production sourced from the specific acreage positions designated in each contract is required to be gathered and treated by each specific entity. Some of our NEPA gas gathering and processing contracts contain limited MVC terms, which expire in the second quarter of 2029. As of December 31, 2025, 82 MMcf/d of MVC related to the gathering, central delivery point aggregation, and intra-basin transport.

The terms of these contracts range from 10 and 20 years from original execution date, with an average term of three years remaining between the various contracts, as of December 31, 2025. The specified rates within these contracts are generally escalated annually subject to a standard Consumer Price Index escalator. These gathering and treating contracts offer deliverability to intra-basin markets, as well as multiple downstream pipelines that offer access to inter- and intra-regional markets. This flexibility ultimately provides sufficient liquidity and market optionality that help facilitate the overall process of maximizing corporate netbacks.

Power Generation

As of December 31, 2025, we owned a 50% ownership interest in the BKV-BPP Power Joint Venture, which owns the Temple Plants, modern combined cycle gas and steam turbine power plants located in the ERCOT North Zone in Temple, Texas. As of December 31, 2025, the remaining 50% interest in the BKV-BPP Power Joint Venture was owned by BPPUS, a wholly-owned subsidiary of Banpu Power and an affiliate of our sponsor, Banpu.

Temple I and Temple II have annual average power generation capacities of 752 MW and 747 MW, respectively, and each power plant delivers power to customers on the ERCOT power network in Texas. 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. The modern technology utilized at the Temple Plants enables them to respond to rapidly changing market signals in real time, ensuring the highest operational readiness during the time when electricity consumption peaks (in winter and summer), making the power plants well-suited to serve the various needs of the ERCOT market. We continue to explore potential additional acquisitions to expand our power generation business. We expect our power generation assets will be synergistic with our base upstream business, and we leverage our existing organization to provide marketing, engineering, finance, accounting, and other administrative services to the BKV-BPP Power Joint Venture for an annual fee plus expenses.

In February 2023, the BKV-BPP Power Joint Venture launched a retail marketing business to sell electricity to commercial, industrial, and residential retail customers in Texas through its wholly-owned subsidiary, BKV-BPP Retail, under the brand name BKV Energy. As of December 31, 2025, BKV Energy has a portfolio of over 58,000 customers and is licensed to serve throughout the deregulated portions of Texas.

Following the closing of the BKV-BPP Power Joint Venture Transaction on January 30, 2026, the BKV-BPP Power Joint Venture is owned 75% by BKV and 25% by BPPUS. Refer to Note 14 - Investments and Note 19 - Subsequent Events to our consolidated financial statements for more information.

Carbon Capture, Utilization, and Sequestration

Through our CCUS business, we aim to reduce man-made GHG emissions to the atmosphere by capturing CO2 emitted in connection with natural gas activities, whether from our own operations or third-party operations, as well as from other energy and industrial sources. Our process involves capturing CO2 before it is released into the atmosphere and then compressing the captured CO2 and transporting it via pipeline to sites where it can be injected into Underground Injection Control (“UIC”) wells for secure geologic sequestration.

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As part of our “closed-loop” approach to our net zero emissions goal, we expect to apply a portion of the CO2 emissions that are sequestered through our CCUS business to offset GHG emissions from our owned and operated upstream and natural gas midstream businesses. We have engaged third parties to analyze and report the CO2 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 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. 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. We may also provide development and support services for third-party owned CCUS projects on a fee-for-service model, although such projects will not be included in our path to net zero. In addition, in the future, we may sell carbon credits associated with our CCUS projects to unrelated third parties outside of our value chain. 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. See “— Path to Net Zero Emissions” below for a description of how we estimate our Scope 1, 2, and 3 annual emissions and how we expect our CCUS business to contribute to the offset of those emissions.

We expect to fund the majority of our CCUS business from a variety of external sources, including contributions from our joint ventures with the Class B Member and BPPUS, project-based equity partnerships, debt financing, and federal grants, with the remaining capital needs being funded with cash flows from operations. The projected timeline for commercial operations and the generation of positive CCUS business revenue and positive earnings depends, in part, on our ability to fund the anticipated capital requirements for the potential projects that we have identified and described below through external funding and revenues from our upstream business, as well as on our ability to receive our portion of the anticipated Section 45Q tax credits associated with these projects. 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 CO2 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. In either case, the Section 45Q tax credits are available for a 12-year period for qualifying facilities that begin construction before January 1, 2033. We may not receive 100% of the Section 45Q tax credits associated with projects funded by third parties and, in such cases, we will receive a certain fee for CO2 transportation and/or sequestration services we provide for such projects, or we will receive only a corresponding percentage of the anticipated Section 45Q tax credits associated with such projects.

CCUS Projects

On May 8, 2025, BKV dCarbon Ventures, together with the Class B Member, and for the limited purposes specified therein, BKV Corporation, entered into the BKV-CIP JV Agreement forming BKV dCarbon Project, LLC (the “BKV-CIP Joint Venture”) for the purpose of developing CCUS projects. On May 8, 2025, BKV dCarbon Ventures contributed to the BKV-CIP Joint Venture $40.3 million of CCUS assets that included BKV dCarbon Barnett Zero, LLC and BKV dCarbon Las Tiendas, LLC and related assets (including the Barnett Zero and Eagle Ford CCUS projects), and $4.1 million of Section 45Q accrued receivables at carrying value, and committed to future contributions of certain CCUS projects, related assets, and/or cash in exchange for an interest in the BKV-CIP Joint Venture and 4,796,421 Class A Units at $10.00 per share. The Class B Member committed up to an initial $500.0 million in cash for use by the BKV-CIP Joint Venture in construction and operating new CCUS projects across the U.S. in exchange for no more than a 49% interest in the BKV-CIP Joint Venture. As of December 31, 2025, the Class B Member contributed $17.9 million.

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. We have entered into various letters of intent and definitive contracts that we expect to grant us carbon storage and sequestration rights on over 42,000 acres of leased pore space across seven distinct projects located in three states. Our projected timeline for commercial operations of these projects depends in part on our ability to fund the capital requirements for these potential projects through external funding and revenues from our upstream business. Our timeline also depends on a regulatory environment that is favorable to our projects and their development. Our projects can be placed into two categories: (i) Class II (NGP) projects and (ii) Class VI projects. The table below presents actual and forecasted quantities of active sequestration operations for each category for years 2025 through 2028 and the early 2030s.

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Project Category (1) (2)

YE 2025 Actual Gross Rate (Mtpy CO2)

YE 2026 Forecasted Gross Rate (Mtpy CO2)

YE 2027 Forecasted Gross Rate (Mtpy CO2) (3)

YE 2028 Forecasted Gross Rate (Mtpy CO2) (3)

Early 2030s Forecasted Gross Rate (Mtpy CO2) (3)

Class II0.10.20.41.32.1

Class VI———0.216.9

Total 0.10.20.41.519.0

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(1) Our projected timeline for commencement of sequestration operations for the project categories identified above depends in part on our ability to fund the capital requirements for these potential projects through external funding and revenues from our upstream business, as well as a regulatory environment that is favorable to our projects and their development. 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. 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.

(3) We have not secured external financing, reached FID, or entered into the definitive agreements necessary to execute many of the projects contributing to the YE 2027, YE 2028, and Early 2030s Forecasted Gross Rates above.

However, we have not secured external financing, reached FID, or entered into the definitive agreements necessary to execute many of the projects contributing to the YE 2027, YE 2028, and Early 2030s Forecast Gross Rates identified above, and there can be no guarantee that we will be able to execute and operate any of these potential future CCUS projects (or any other CCUS projects) with sufficient volumes of CO2 sequestration to achieve our Scope 1, 2, and 3 emissions goals on the timelines we anticipate. 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.

We estimate the aggregate investment required to develop the actual and potential CCUS projects identified above to be between approximately $1.3 - $1.6 billion between now and the end of 2030. We anticipate that some of these project costs will be borne by third-party investors in these projects, including our joint venture partners, owners of sources of CO2, landowners, and other stakeholders. In order to achieve the projected timeline for commercial operations of such projects, we expect to fund the majority of the anticipated cost of these CCUS projects from third-party sources, including contributions from our joint ventures with the Class B Member and BPPUS, project-based equity partnerships, debt financing, and federal grants, with the remaining capital needs being funded with cash flows from operations. We are able to moderate the capital required to fund our CCUS business, as our CCUS business model provides flexibility for us to selectively invest in only the sequestration component of a project or in the capture, transportation, and sequestration components, depending on the scope of the project. If sufficient external funding is not available to help fund our CCUS business, then we would expect to continue to develop our CCUS business from cash flows from operations on a less accelerated timeline, which may result in an inability to achieve our Scope 1, 2, and 3 emissions goals on the timeline we anticipate.

We have achieved notable milestones with respect to certain projects within each category, as more fully described below.

Class II Operational Projects

Barnett Zero Project. In November 2023, our first CCUS project, which we refer to as the Barnett Zero Project, commenced commercial sequestration of CO2 waste generated by ONEOK’s Bridgeport natural gas processing plant and neighboring operations. 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 CO2 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. During 2025, our operational projects achieved a total sequestration of approximately 138,000 metric tons of CO2.

We have used and intend to continue to use the Barnett Zero Project as a prototype for modular NGP projects that can be repeated and quickly scaled. We are currently progressing additional NGP projects based on this model and anticipate that these projects will reach FID and initiate sequestration operations at various points in 2026 through 2028.

Class II FID Projects

Eagle Ford Project. On December 18, 2024, BKV dCarbon Ventures reached internal FID to develop our second CCUS project for the sequestration of CO2 waste generated by a natural gas processing plant. This CCUS project, which

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we refer to as the Eagle Ford Project, will capture, compress, and then dispose of and geologically sequester the CO2 waste stream generated as a byproduct of third-party natural gas processed by the plant. We estimate the Eagle Ford Project will geologically sequester up to approximately 90,000 metric tons of CO2 per year. We currently estimate the total investment required for the Eagle Ford Project to be approximately $22 million and we expect to be entitled to use 100% of the environmental attributes associated with the project towards our net zero goals. We are targeting commencement of CO2 sequestration activities during the first quarter of 2026, at which point we expect this project will be the second of our current modular line of identified potential NGP projects.

Cotton Cove Project. On October 18, 2022, BKV dCarbon Ventures reached internal FID to develop our third CCUS project in the Barnett. This CCUS project, which we refer to as the Cotton Cove Project, will separate, dispose of, and geologically sequester CO2 generated as a byproduct of our natural gas production in the Barnett and will utilize our midstream assets to do so. We have secured pore space for CO2 injection, and we estimate the Cotton Cove Project will geologically sequester up to approximately 32,000 metric tons of CO2 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 currently estimate the total investment required for the Cotton Cove Project to be approximately $18 million, of which we contributed $9.0 million and BPPUS contributed $8.8 million through December 31, 2025. We currently expect to be entitled to use the majority of the environmental attributes associated with such project towards our net zero goals. We are targeting commencement of CO2 sequestration activities during the first half of 2026, at which point we expect this project will be the third of our current modular line of identified potential NGP projects, in addition to the Barnett Zero 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. On December 11, 2025, BKV dCarbon Ventures reached internal FID to develop our fourth CCUS project for the sequestration of waste emissions from a natural gas processing plant. This CCUS project, which we refer to as the East Texas Project, will capture, compress, and then dispose of and geologically sequester the CO2 waste stream generated as a byproduct of third-party natural gas processed by the plant. We estimate the East Texas Project will geologically sequester up to approximately 70,000 metric tons of CO2 per year. We currently estimate the total investment required for the East Texas Project to be approximately $22 million and we expect to be entitled to use 100% of the environmental attributes associated with the project towards our net zero goals. We are targeting commencement of CO2 sequestration activities in the first half of 2027, at which point we expect this project will be the fourth of our current modular line of identified potential NGP projects.

Other Class II NGP Projects

We have identified other potential NGP projects that we anticipate will achieve FID and commence initial sequestration operations at various points in 2026 through 2028. Much of the carbon capture infrastructure required for these NGP projects is already in place. For example, the NGP facilities have amine towers to capture and concentrate CO2 emissions to meet natural gas sales specifications. Also, we have secured or are in discussions to secure definitive agreements for pore space leasehold for several projects, and have submitted or are working towards submitting well permit applications. If these projects are approved at FID, definitive agreements are executed on the terms and timeline we believe are obtainable, and sufficient external funding is secured, we expect these projects to start sequestration operations before December 31, 2028.

On February 24, 2026, BKV dCarbon Ventures entered into a definitive agreement in connection with our fifth and sixth CCUS projects for the sequestration of waste emissions from natural gas processing plants. We expect these CCUS projects to capture, compress, and then dispose of and geologically sequester the CO2 waste stream generated as a byproduct of Comstock Resource’s natural gas processing plants in the Western Haynesville region. Although we have not secured external financing, reached FID, or entered into all definitive agreements necessary to execute these projects we have identified, if approved at FID, assuming we are able to execute additional definitive agreements on the terms and timeline we believe are obtainable, and secure sufficient external funding, and subject to receipt of required regulatory approvals, these projects are expected to include the development of two Class II injection wells and further expand our current modular line of identified potential NGP projects. For more information about the risks involved in our CCUS business, see “Risk Factors - Risks Related to Our CCUS Business.”

Class VI Projects

We are also evaluating potential medium to higher concentration industrial projects to sequester third-party emissions, and anticipate these projects will achieve FID and commence initial sequestration operations at various points prior to 2033.

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Pore space leaseholds have been secured for our potential industrial projects, including one covering approximately 21,000 acres of state-owned land in Louisiana, which we refer to as the High West Project.

In August 2023, High West entered into a carbon sequestration agreement with the State of Louisiana to develop facilities and permanently sequester CO2 from local third-party emissions sources. The State of Louisiana granted High West the carbon storage and sequestration rights on approximately 21,000 acres of land in St. Charles and Jefferson Parishes. The acreage is in an ideal location for targeted carbon capture and sequestration efforts, with an estimated 10 Mtpy CO2 of potential capture and sequestration in Phase I of the development. This site is located within a 20 mile radius from various emissions points. The Class VI permit application for Phase I of the initial five well development was submitted on March 31, 2025, and was deemed administratively complete on August 27, 2025 by the Louisiana Department of Energy and Natural Resources (now the Louisiana Department of Conservation and Energy). The storage site is estimated to have approximately 200 Mt of total CO₂ storage capacity in Phase I of the development, which is expected to support injection volumes of up to 10 Mt per year over an anticipated operating life of approximately 20 years. Additional phases of development may be undertaken as needed. We currently estimate the total investment required for High West to be approximately $163 million with the potential for additional phases of development. Under the agreement, High West will dispose of CO2 waste from local third-party emissions sources through permanent sequestration via injection wells on the designated acreage.

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. Environmental Protection Agency (the “EPA”) recognized our permit applications as being administratively complete in January 2024 and February 2024, respectively, for one of our State of Louisiana projects and the State of Texas project. Both the State of Louisiana and State of Texas applied for, and have been granted, primacy for the EPA’s Class VI permitting program and these two applications have been transferred from the EPA to the respective state agencies. In July 2025, the Louisiana Department of Conservation and Energy additionally recognized the permit application originally submitted to the EPA for the State of Louisiana permit as administratively complete. For the other State of Louisiana Class VI location (which BKV has designated as the “High West” project), the Class VI permit application for a five well initial development industrial location was filed with the State of Louisiana on March 31, 2025. On August 27, 2025, the Louisiana Department of Conservation and Energy recognized the initial five well permit applications as being administratively complete. We continue to engage in discussions with additional CO2 sources regarding a number of potential projects. Subject to FID for each project, the availability of sufficient external financing, and the execution of definitive agreements we believe are obtainable, we expect to initiate sequestration operations prior to 2033.

Our CCUS business and all of our CCUS projects are in the early stages of development. Although we commenced commercial operations with the initial injection of CO2 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 may not be able to reach agreements on terms acceptable to us or achieve our projected timeline for commercial operations for these projects. In addition, the development of our CCUS business is expected to require material capital investments, and the projected timeline for commercial operations depends on our ability to fund the anticipated capital requirements for the potential projects that we have identified through external funding and revenues from our upstream business. We expect to fund the majority of these CCUS projects from a variety of external sources, including contributions from our joint ventures with the Class B Member and BPPUS, project-based equity partnerships, debt financing, and federal grants, with the remaining capital needs being funded with cash flows from operations. The commercial viability of our CCUS projects depends, in part, on obtaining necessary permits and other regulatory approvals and on our ability to receive our portion of the anticipated Section 45Q tax credits associated with these projects. In particular, we must meet certain wage and apprenticeship requirements in order to qualify for enhanced Section 45Q tax credits. For more information about the risks involved in our CCUS business, see “Risk Factors - Risks Related to Our CCUS Business.”

We are also currently progressing Front-End Engineering Design (FEED) studies regarding CO2 capture from combined cycle natural gas power turbines, like those at our Temple location, to further delineate capital and operating costs of such facilities. Implementation of such capture at BKV’s existing or developed power facilities would significantly reduce the carbon intensity of the associated power produced from such facilities.

Path to Net Zero Emissions

We conducted an initial assessment of our annual Scope 1 and 2 emissions from our owned and upstream businesses as of December 31, 2021, and subsequently updated that assessment for the upstream and natural gas midstream businesses acquired through the Exxon Barnett Acquisition in 2022 to establish an emissions baseline of 2.49 Mtpy CO2e annual Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses as of December 31,

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2021. Our assessments did not address our GHG emissions from our other business operations. 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. These estimates will be updated annually to reflect any changes in activity, inventory, production throughput, and emissions reduction retrofits or equipment modifications, and published in our annual Sustainability Report.

Our path to net zero solely addresses GHG emissions relating to our owned and operated upstream and natural gas midstream businesses and does not address GHG emissions from our other business operations, namely our CCUS and power generation businesses. Although we believe our current path to net zero will be sufficient to reduce emissions related to our existing owned and operated upstream and natural gas midstream businesses, the future growth or expansion of such businesses will result in additional GHG emissions. 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 estimate that our annual Scope 3 emissions from our owned and operated upstream and natural gas midstream businesses were approximately 17.0 Mtpy CO2 as of December 31, 2024. These Scope 3 emissions are currently estimated in accordance with IPIECA’s “Sustainability reporting guidance for oil and gas industry,” dated March 2020. Specifically, Scope 3 emissions are estimated per the Greenhouse Gas Protocol’s “Corporate Value Chain (Scope 3) Accounting and Reporting Standard,” released in 2011, under Category 11 (Use of Sold Product). 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. 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 CO2e emissions are estimated using AR5 Global Warming Potentials, similar to those used by the EPA. The AR5 Global Warming Potentials supersede the AR4 Global Warming Potentials applied in prior periods. Our annual Scope 3 CO2e emissions for the year ended December 31, 2024 were estimated at an approximated year-end net production volume of 855 MMcfe/d of natural gas (approximately 85% methane, 5% ethane and 10% other) and approximately 113.4 MBbls of NGLs (or approximately 1.7 MMcfe/d), as reported to the EPA for Subpart W. Our NGL constituents are estimated based on average constituent NGL barrel. Allocating the entire 856 MMcfe/d towards combustion as the end use, applying suitable combustion emission factors from the EPA, and using AR5 GWPs, Scope 3 annual emissions from our operated upstream operations are estimated at approximately 17.0 Mtpy CO2. 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. As of December 31, 2025, we completed the conversion of over 75% of our pneumatic devices and pneumatic pumps in the Barnett and during the year ended December 31, 2025, we successfully completed the program with our upstream owned and operated assets in NEPA. Through December 31, 2025, our total costs incurred to complete the conversions approximated $23.6 million.

Based on the success of this effort, methane is no longer our largest source of GHG emissions on a CO2e emissions-related basis. Due to this success, regulatory updates, and other operational efficiencies, we are evaluating the need for future pneumatic retrofits and will be transitioning investments to other emission reduction technologies more impactful to our assets.

Emissions Monitoring. Our leak detection and repair emissions monitoring program involves continuous ground-based instrument monitoring, satellite-based monitoring, aerial flyovers, and on the ground leak detection and repair inspections.

Solar Renewable Credits. We expect to purchase the SRECs generated by the BKV-BPP Power Joint Venture’s planned 2.5 MW to 5 MW solar facility. The initial 2.5 MW phase was completed and began generating power in August 2024. The BKV-BPP Power Joint Venture has obtained permits for the full 5 MW facility and is evaluating development of the remaining 2.5 MW. Solar facilities may be subject to increasingly arduous regulatory requirements, including additional permitting requirements. For every 1,000 kilowatt-hours of electricity produced by an eligible solar facility, one SREC is awarded. For a solar facility to be credited with that SREC, the system must be certified and registered by state agencies. The BKV-BPP Power Joint Venture’s solar facility is expected to generate SRECs sufficient to offset approximately 30% of the Scope 2 emissions from our owned and operated upstream and natural gas midstream business as of December 31, 2025.

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CCUS. Further, as discussed under “— Carbon Capture, Utilization, and Sequestration” above, we believe that the Barnett Zero Project, together with the Eagle Ford Project, the Cotton Cove Project, the East Texas Project, and the additional pre-FID projects for the capture and sequestration of third-party emissions that we have identified, have a combined annual forecasted sequestration volume of approximately 19.0 Mtpy CO2 during the early 2030s. Although we have not secured external financing, reached FID, or entered into the definitive agreements necessary to execute any of the additional pre-FID projects we have identified, if approved at FID, and assuming we are able to execute definitive agreements on the terms and timeline we believe are obtainable, and secure sufficient external funding, we expect these projects to start sequestration operations before December 31, 2029.

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 CO2 sequestration to achieve our Scope 1, 2, and 3 emissions goals on the timelines we anticipate. There can be no assurance that any of the potential projects we have identified or the Barnett Zero Project will achieve forecasted sequestration volumes, and we may not commence sequestration operations for any of the potential projects identified above by the anticipated timeframe, or at all. Furthermore, 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. In addition, in the future, we may sell carbon credits associated with our CCUS projects to unrelated third parties outside our value chain. 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. 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.

Planned Path to Net Zero (Scope 1, 2, and 3)

We also aspire to offset the annual Scope 3 emissions impact of our owned and operated upstream and natural gas midstream businesses by the late 2030s, which we estimated to be approximately 17.0 Mtpy CO2 annually as of December 31, 2024. Our CCUS business of capturing and sequestering our gas processing-related emissions along with third-party GHG emissions is a critical component to achieving this net zero goal. 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 will periodically perform materiality assessments on our Scope 3 emissions to ensure the accuracy of our Scope 3 missions footprint. At this time, our Scope 3 emissions estimate does not include our GHG emissions from our other business operations, namely our CCUS and power generation 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 CO2 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. The BKV-CIP Joint Venture will retain and monetize all environmental attributes associated with CCUS projects contributed to the BKV-CIP Joint Venture, including pursuant to a first right of BKV or its affiliates to purchase such environmental attributes at fair market value. Ultimately, with respect to CCUS projects contributed to the BKV-CIP Joint Venture, we will be able to apply to offset our own GHG emissions only the portion of sequestered emissions attributable to the percentage of environmental attributes that BKV purchases from the BKV-CIP Joint Venture. We will continue to evaluate and identify potential CCUS project opportunities consistent with our goal of offsetting our annual Scope 1, 2, and 3 emissions from our owned and operated upstream and natural gas midstream businesses by the late 2030s. However, we may not purchase, receive, or retain 100% of the environmental attributes associated with our CCUS projects as discussed above, which may negatively impact our net zero strategy, potentially delaying or preventing our progress towards achieving our net zero goals.

Large scale CCUS projects are subject to numerous risks and uncertainties, including securing third-party financing, reaching definitive agreements with third parties, and obtaining necessary permits and other regulatory approvals, and we may be unable to execute on some or all of these projects, including the projects for which we have reached FID on the timeline we anticipate, on terms acceptable to us, or at all. 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. If sufficient external funding is not available to help fund our CCUS business, then we would expect to continue to develop our CCUS business from cash flows from operations on a less accelerated timeline. If we are

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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.

Our Acreage

The following table summarizes our acreage position as of December 31, 2025:

DevelopedUndevelopedTotal

Operating RegionGrossNetGrossNetGrossNet

Barnett (1)
760,746 504,815 48,330 39,214 809,076 544,029

NEPA21,677 18,312 1,467 785 23,144 19,097

Total782,423 523,127 49,797 39,999 832,220 563,126

The following table summarizes our acreage position as of December 31, 2024:

DevelopedUndevelopedTotal

Operating RegionGrossNetGrossNetGrossNet

Barnett (1)
641,923 426,314 40,134 35,496 682,057 461,810

NEPA21,677 18,312 1,467 785 23,144 19,097

Total663,600 444,626 41,601 36,281 705,201 480,907

The following table summarizes our acreage position as of December 31, 2023:

DevelopedUndevelopedTotal

Operating RegionGrossNetGrossNetGrossNet

Barnett (1)
638,193 421,491 41,113 38,421 679,306 459,912

NEPA63,739 29,501 18,774 7,364 82,513 36,865

Total701,932 450,992 59,887 45,785 761,819 496,777

__________________________

(1) Includes acreage acquired during 2021 from Jamestown Resources, LLC, Larchmont Resources, LLC, and Pelican Energy, LLC, for which acreage the leasehold interest is derived from unit-based assignments and includes 133,470 gross and 3,318 net developed acres, and no undeveloped acreage.

The percentage of our net undeveloped acreage that is subject to lease expiration over the next three years, if such leases are not renewed, is approximately 0.93% in 2026, 1.14% in 2027, and 0.64% in 2028.

Our Productive Wells

The following table sets forth our gross and net productive natural gas and oil wells as of December 31, 2025:

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Producing Natural Gas WellsProducing Oil WellsTotalAverage Working Interest

Operated Wells
GrossNetGrossNetGrossNet

Barnett6,357 6,132 10 10 6,367 6,142 96.5 %

NEPA147 129 — — 147 129 87.8 %

Total6,504 6,261 10 10 6,514 6,271 96.3 %

Non-Operated Wells

Barnett927 89 7 1 934 90 9.6 %

NEPA36 1 — — 36 1 2.8 %

Total963 90 7 1 970 91 9.4 %

Total

Barnett7,284 6,221 17 11 7,301 6,232 85.4 %

NEPA183 130 — — 183 130 71.0 %

Total7,467 6,351 17 11 7,484 6,362 85.0 %

The following table sets forth our gross and net productive natural gas and oil wells as of December 31, 2024:

Producing Natural Gas WellsProducing Oil WellsTotalAverage Working Interest

Operated Wells
GrossNetGrossNetGrossNet

Barnett5,492 5,340 7 7 5,499 5,347 97.2 %

NEPA142 130 — — 142 130 91.5 %

Total5,634 5,470 7 7 5,641 5,477 97.1 %

Non-Operated Wells

Barnett924 90 1 — 925 90 9.7 %

NEPA35 — — — 35 — — %

Total959 90 1 — 960 90 9.4 %

Total

Barnett6,416 5,430 8 7 6,424 5,437 84.6 %

NEPA177 130 — — 177 130 73.4 %

Total6,593 5,560 8 7 6,601 5,567 84.3 %

The following table sets forth our gross and net productive natural gas and oil wells as of December 31, 2023:

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Producing Natural Gas WellsProducing Oil WellsTotalAverage Working Interest

Operated Wells
GrossNetGrossNetGrossNet

Barnett5,614 5,437 6 6 5,620 5,443 96.9 %

NEPA142 127 — — 142 127 89.4 %

Total5,756 5,564 6 6 5,762 5,570 96.7 %

Non-Operated Wells

Barnett993 95 1 — 994 95 9.6 %

NEPA272 37 — — 272 37 13.6 %

Total1,265 132 1 — 1,266 132 10.4 %

Total

Barnett6,607 5,532 7 6 6,614 5,538 83.7 %

NEPA414 164 — — 414 164 39.6 %

Total7,021 5,696 7 6 7,028 5,702 81.1 %

Drilling, Refrac, and Restimulation Activity

During the years ended December 31, 2025, 2024, and 2023, we drilled development wells as set forth in the table below:

202520242023

Development
GrossNetGrossNetGrossNet

Barnett

Productive
33.0 33.0 6.0 6.0 15.0 15.0

Dry
1.0 0.9 — — — —

NEPA

Productive
4.0 4.0 — — 3.0 3.0

Dry
— — — — — —

Total38.0 37.9 6.0 6.0 18.0 18.0

As of December 31, 2025, we had four wells (4.0 net) drilled and uncompleted in the Barnett and three wells (3.0 net) drilled and uncompleted in NEPA. In addition, we had one well (1.0 net) in the process of being drilled in the Barnett, and none in NEPA. During the year ended December 31, 2025, 35 wells (34.9 net) were completed in the Barnett, which included two previously drilled but uncompleted wells that were acquired in the Bedrock Acquisition, and one well was 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, 2025.

As of December 31, 2024, we had four wells (4.0 net) drilled and uncompleted in the Barnett and no wells drilled and uncompleted in NEPA. 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.

During the year ended December 31, 2023, seven wells were completed in the Barnett (all of which were net productive) and no wells were completed in NEPA.

We also maintain a restimulation program in the Barnett to develop economic incremental reserves in existing wellbores and arrest the overall field production decline. During the years ended December 31, 2025, 2024, and 2023, we completed 56, three, and 32 horizontal and vertical restimulations, respectively. Additionally, as of December 31, 2025, we had 209 proved undeveloped horizontal locations and 323 proved developed non-producing refrac candidates in the Barnett. For a discussion of how we identify drilling locations and refrac candidates, please see “ — Determination of Identified Drilling and Refracture Locations.”

Production Volumes and Average Unit Prices

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The following table summarizes sales volumes, sales prices and production cost information for our net natural gas and production for the years ended December 31, 2025, 2024, and 2023.

Year ended December 31,

202520242023

Production Volumes

Barnett

Natural gas (MMcf)208,779.7 185,857.3 198,099.4

Natural gas liquids (MBbl)10,181.4 9,857.7 10,553.6

Oil (MBbl)159.3 96.0 118.6

Total Barnett (Bcfe)270.8 245.6 262.1

NEPA

Natural gas (MMcf)34,151.7 42,825.3 51,666.9

Natural gas liquids (MBbl)— — —

Oil (MBbl)— — —

Total NEPA (Bcfe)34.2 42.8 51.7

Total Company (Bcfe)305.0 288.4 313.8

Average Sales Prices (excluding impact of derivative settlements)

Barnett

Natural gas ($/Mcf)
$2.91 $1.87 $2.28

Natural gas liquids ($/Bbl)
$17.00 $16.79 $17.80

Oil ($/Bbl)
$59.38 $68.81 $71.21

NEPA

Natural gas ($/Mcf)
$1.98 $0.91 $1.12

Natural gas liquids ($/Bbl)
$— $— $—

Oil ($/Bbl)
$— $— $—

Total Company ($/Mcfe)
$2.81 $1.93 $2.25

Average Sales Prices (including the impact of derivative prices) (1)

Natural gas ($/Mcf)
$2.75 $2.10 $2.23

Natural gas liquids ($/Bbl)
$16.84 $17.19 $17.55

Oil ($/Bbl)
$59.50 $68.81 $70.97

Total Company ($/Mcfe)
$2.79 $2.28 $2.39

Average Production Cost ($/Mcfe) (2)

Barnett $1.45 $1.43 $1.48

NEPA$0.29 $0.20 $0.24

Total Company $1.32 $1.25 $1.27

____________________________________________________

(1) Impact of derivative 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.

(2) Excludes natural gas and oil ad valorem and production taxes.

For additional information on pricing see, Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of Part II in this Annual Report on Form 10-K.

Determination of Identified Drilling and Refracture Locations

Proved Drilling and Refracture Locations

As of December 31, 2025, we had approximately 209 gross (191 net) proved undeveloped horizontal drilling locations and 323 gross (305 net) proved developed non-producing refrac candidates at SEC reserves pricing. We use production data and experience gains from our development programs to identify and prioritize development of our proved inventory of undeveloped horizontal drilling locations and proved developed non-producing refrac candidates. These drilling locations and refrac candidates are included in our proved inventory only after they have been evaluated technically and are part of a development plan that has been adopted by management indicating that such locations are scheduled to be drilled within five years. 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

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considers the availability of local infrastructure, drilling support assets, state and local regulations, and other factors it deems relevant in determining such locations.

Unproved Drilling and Refracture Locations

Our unproved horizontal drilling locations and refrac candidates are specifically identified on a field-by-field basis considering the applicable geologic, engineering, and production data. We analyze past field development practices and identify analogous drilling opportunities taking into consideration historical production performance, estimated drilling and completion costs, spacing, and other performance factors. These horizontal drilling locations and refrac candidates primarily include (i) infill drilling locations, (ii) additional locations due to field extensions, and (iii) restimulations. We believe the assumptions and data used to estimate these horizontal drilling locations and refrac candidates are consistent with established industry practices based on the type of recovery processes we are using.

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. For more information about our reserves volumes and values, see “— Preparation of Reserves Estimates and Internal Controls” and Ryder Scott’s summary reserve reports, which are filed as exhibits to this Annual Report on Form 10-K.

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. The increase in our proved reserves and the PV-10 Value of those reserves as of December 31, 2025, as compared to December 31, 2024, is primarily due to higher commodity pricing. 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.

Estimated SEC Reserves (1)

December 31,

202520242023

Estimated proved developed reserves:

Natural gas (MMcf)3,097,864 2,059,984 2,443,072

Producing2,913,523 1,951,322 2,290,025

Non-producing184,341 108,662 153,047

Natural gas liquids (MBbls)183,111 134,017 156,399

Producing162,684 113,739 129,260

Non-producing20,427 20,278 27,139

Oil (MBbls)1,763 878 992

Producing1,600 713 802

Non-producing163 165 190

Total estimated proved developed reserves (MMcfe)4,207,108 2,869,354 3,387,418

Producing3,899,227 2,638,034 3,070,397

Non-producing307,881 231,320 317,021

Estimated proved undeveloped reserves:

Natural gas (MMcf)1,247,900 176,047 539,423

Natural gas liquids (MBbls)75,545 13,605 27,766

Oil (MBbls)2,118 813 59

Total estimated proved undeveloped reserves (MMcfe) (2), (3)
1,713,878 262,555 706,373

Estimated total proved reserves:

Natural gas (MMcf)4,345,764 2,236,031 2,982,495

Natural gas liquids (MBbls)258,656 147,622 184,165

Oil (MBbls)3,881 1,691 1,051

Total estimated proved reserves (MMcfe)5,920,986 3,131,909 4,093,791

Standardized Measure (millions)$2,345 $633 $1,062

PV-10 (millions) (4), (5)
$2,788 $672 $1,232

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_________________________________

(1) Prices for natural gas, oil and NGLs, respectively, used in preparing our estimated proved reserves and the associated PV-10 Value based on SEC Pricing (i) at December 31, 2025 were $3.39 per MMBtu (Henry Hub), $65.34 per Bbl (WTI Cushing), and NGL pricing equal to 34.4% of WTI Cushing, (ii) at December 31, 2024 were $2.13 per MMBtu (Henry Hub), $75.48 per Bbl (WTI Cushing), and NGL pricing equal to 29.5% of WTI Cushing, and (iii) at December 31, 2023 were $2.637 per MMBtu (Henry Hub), $78.22 per Bbl (WTI Cushing), and NGL pricing equal to 29.5% of WTI Cushing.

(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.

(3) Sustained lower prices for oil and natural gas may cause us to forecast less capital to be available for development of our proved undeveloped reserves, which may cause us to decrease the amount of our proved undeveloped reserves we expect to develop within the allowed time frame. 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.

(4) PV-10 refers to the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. PV-10 is not a financial measure calculated in accordance with GAAP because it does not include the effects of income taxes on future net revenues. PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure. Neither PV-10 nor Standardized Measure represent an estimate of the fair market value of our oil and natural gas properties. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and gas properties. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the Standardized Measure reported in accordance with GAAP, but rather should be considered in addition to the Standardized Measure.

(5) The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated proved reserves as of December 31, 2025, 2024, and 2023:

December 31,

202520242023

PV-10 (millions)$2,788 $672 $1,232

Present value of future income taxes discounted at 10%(443)(39)(170)

Standardized Measure$2,345 $633 $1,062

During the years ended December 31, 2025, 2024, and 2023, we incurred costs of approximately $140.0 million, $22.8 million, and $37.7 million, respectively, to convert 157.9 Bcfe, 57.6 Bcfe, and 31.9 Bcfe, respectively, of proved undeveloped reserves to proved developed reserves. 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. 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 proved undeveloped reserves, as of December 31, 2025, are scheduled to be developed within five years of their initial disclosure.

2025 Activity

During the year ended December 31, 2025, our proved reserves increased by 2,789.1 Bcfe. The increase in proved reserves was primarily attributable to increased commodity pricing and drilling activity, which resulted in total upward revisions of 2,201.0 Bcfe. In addition, in September 2025, we acquired 100% of the equity interests of BKV Barnett II (formerly known as Bedrock Production, LLC), increasing reserves by 743.0 Bcfe. Our extensions and discoveries and improved recoveries experienced in 2025 also resulted in net increases to proved reserves of 129.6 Bcfe and 20.6 Bcfe, respectively. We produced 305.0 Bcfe during the year ended December 31, 2025.

Revisions of previous estimates primarily consisted of upward revisions to proved developed reserves and proved undeveloped reserves of 915.8 Bcfe and 679.2 Bcfe, respectively, as a result of higher average pricing during 2025 for natural gas, NGLs, and oil. Additional upward revisions were made to proved undeveloped reserves of 599.2 Bcfe due to increases in capital spend and drilling activity during 2025. Changes to the Company’s drilling schedule added 86.0 gross (81.2 net) proved locations in NEPA and the Barnett to be developed within the next five years. The drilling schedule changes reflect the Company’s ongoing commitment to optimize the long-term plan to best develop its assets, maximize cash flow, and produce economic returns.

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Extensions and discoveries added 129.6 Bcfe of proved undeveloped reserves across 11.0 gross (8.9 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, 2025.

Improved recoveries added 20.6 Bcfe of proved developed reserves achieved through the continued enhancement of recovery techniques applied to producing wells during the year ended December 31, 2025.

Purchases of minerals in place consisted of 494.6 Bcfe and 248.4 Bcfe of acquired proved developed reserves and proved undeveloped reserves, respectively, from the Bedrock Acquisition, which represented 1,002.0 gross (877.6 net) locations in the Barnett.

Conversions of proved undeveloped reserves to proved developed reserves consisted of 211.8 Bcfe related to the completion of 34.0 gross (31.0 net) wells during the year ended December 31, 2025 that were converted to proved developed wells, previously classified as proved undeveloped.

2024 Activity

During the year ended December 31, 2024, our proved reserves decreased by 961.9 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. As discussed below, these decreases were partially offset by extensions and discoveries and improved recoveries we experienced in 2024, which resulted in net increases to proved reserves of 139.2 Bcfe and 52.2 Bcfe, respectively. We produced 288.4 Bcfe during the year ended December 31, 2024.

Revisions of previous estimates primarily consisted of downward revisions to proved developed reserves and proved undeveloped reserves of 235.6 Bcfe and 213.7 Bcfe, respectively, as a result of lower average pricing during 2024 for natural gas, NGLs, and oil. Additional downward revisions were made to proved undeveloped reserves of 265.6 Bcfe due to lower capital spend and the resulting reduction in drilling activity during 2024. Changes to our drilling schedule moved the development of 38.0 gross (35.1 net) locations in NEPA and the Barnett beyond the SEC requirement of developing PUD reserves five years from initial booking. These 38.0 gross (35.1 net) locations remain in inventory of unproved locations to be developed outside of the next five years. The drilling schedule changes reflect our ongoing commitment to optimize the long-term plan to best develop our assets, maximize cash flow, and produce economic returns.

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.

Improved recoveries added 52.2 Bcfe of proved developed reserves achieved through the continued enhancement of recovery techniques applied to producing wells during the year ended December 31, 2024.

Sale of minerals in place consisted of 103.9 Bcfe and 46.1 Bcfe of divested proved developed reserves and proved undeveloped reserves, respectively, of Chaffee assets and certain non-operating upstream assets in Chelsea, both sold in June 2024, which represented 330.0 gross (39.6 net) locations in NEPA.

Conversions of proved undeveloped reserves to proved developed reserves consisted of 57.6 Bcfe related to the completion of 8.0 gross (7.9 net) wells during the year ended December 31, 2024 that were converted to proved developed wells, previously classified as proved undeveloped.

2023 Activity

During the year ended December 31, 2023, our proved reserves decreased by 2,042.1 Bcfe. The decrease in proved reserves was primarily attributable to decreased commodity pricing and changes in our drilling activity, which resulted in total downward revisions of 1,986.3 Bcfe. As discussed below, these decreases were partially offset by extensions and discoveries and improved recoveries in 2023, which resulted in net increases to proved reserves of 227.8 Bcfe and 30.2 Bcfe, respectively. We produced 313.8 Bcfe during the year ended December 31, 2023.

Revisions of previous estimates primarily consisted of downward revisions to proved developed reserves and proved undeveloped reserves of 1,191.9 Bcfe and 273.1 Bcfe, respectively, as a result of lower average pricing during 2023 for natural gas, NGLs, and oil. Additional downward revisions were made to proved undeveloped reserves of 521.3 Bcfe due to lower capital spend and the resulting reduction in drilling activity during 2023. Changes to our drilling schedule moved the development of 112.0 gross (104.8 net) locations in NEPA and the Barnett beyond the SEC requirement of developing PUD reserves five years from initial booking. These 112.0 gross (104.8 net) locations remain in inventory of unproved locations to be developed outside of the next five years. The drilling schedule changes reflect our ongoing commitment to optimize the long-term plan to best develop its assets, maximize cash flow, and produce economic returns.

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Extensions and discoveries primarily consisted of 226.5 Bcfe of proved undeveloped reserves, of which 197.8 Bcfe was attributable to 22.0 gross (21.2 net) locations recognized as a result of our optimized drilling program, which reduced costs and extended lateral lengths. In addition, 28.7 Bcfe was attributable to extensions related to 3.0 gross (1.1 net) locations in NEPA. Our unitization and combination of acreage with Repsol resulted in the three additional locations.

Improved recoveries consisted of 30.2 Bcfe of proved developed reserves recognized as a result of the application of improved recovery techniques to producing wells during the year ended December 31, 2023.

Conversions of proved undeveloped reserves to proved developed reserves consisted of 31.9 Bcfe related to the completion of 22.0 gross (8.1 net) wells during the year ended December 31, 2023 that were converted to proved developed wells, previously classified as proved undeveloped.

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. 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. The historical 12-month pricing average in our December 31, 2025 disclosures above does not reflect the prevailing natural gas and oil futures. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of natural gas and oil prices as of a certain date, although we caution investors that this information should be viewed as a helpful alternative, not a substitute, for the data presented based on SEC Pricing. In addition, we believe that NYMEX strip pricing provides relevant and useful information because it is widely used by investors in our industry as a basis for comparing the relative size and value of our reserves to our peers. 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. There are numerous uncertainties inherent in estimating quantities of natural gas, NGL and oil reserves and their values, including many factors beyond our control. See “Risk Factors — Risks Related to Our Upstream Business and Industry — Our estimated natural gas, NGL, and oil reserves quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in the reserves estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.”

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December 31,

2025

Estimated proved developed reserves at NYMEX Strip Pricing:

Natural gas (MMcf)3,156,787

Producing2,972,440

Non-producing184,347

Natural gas liquids (MBbls)183,504

Producing163,078

Non-producing20,426

Oil (MBbls)1,760

Producing1,597

Non-producing163

Total estimated proved developed reserves (MMcfe)4,268,371

Producing3,960,490

Non-producing307,881

Estimated proved undeveloped reserves at NYMEX Strip Pricing:

Natural gas (MMcf)1,243,920

Natural gas liquids (MBbls)74,843

Oil (MBbls)2,086

Total estimated proved undeveloped reserves (MMcfe) (1), (2)
1,705,494

Estimated total proved reserves at NYMEX Strip Pricing:

Natural gas (MMcf)4,400,707

Natural gas liquids (MBbls)258,347

Oil (MBbls)3,846

Total estimated proved reserves (MMcfe)5,973,865

Standardized Measure (millions)$2,574

PV-10 (millions) (3)
$3,082

__________________________________________________

(1) Proved undeveloped reserves December 31, 2025 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) Sustained lower prices for oil and natural gas may cause us to forecast less capital to be available for development of our proved undeveloped reserves, which may cause us to decrease the amount of our proved undeveloped reserves we expect to develop within the allowed time frame. 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.

(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. 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.

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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. Our reservoir engineering team then reviews such data and provides it to, and works closely with, our independent reserves engineers as part of their reserves evaluation process. Our internal reserves process follows a rigorous workflow where the multidisciplinary teams come together to vet our model assumptions and input and get final signoff before our technical team meets with the independent reserves engineers to review properties and discuss methods and assumptions used to prepare reserves estimates. 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. Ngo has a BS in Civil Engineering and Masters in Petroleum Engineering and International Political Economy of Resources from the Colorado School of Mines, and a MBA from the University of Colorado, Denver.

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. 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. Management is responsible for establishing internal controls used in the preparation of our oil and gas reserves, which include verification of data input into reserves forecasting and economics evaluation software and multi-discipline management reviews performed by the corporate reserves team.

Enterprise Risk Management

We have a standing risk management committee (“RMC”), which meets regularly and assesses, mitigates, and provides direction on management of key enterprise risks. Our enterprise risk management function is overseen by the Senior Director of Risk Management, who coordinates our risk assessment and monitoring processes and reports to executive leadership. The RMC is comprised of executives and senior leaders across various functions, including legal, information technology, marketing, regulatory and sustainability, safety, security, operations, finance and accounting, and land.

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 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. We do not believe the loss of any customer would have a material adverse effect on our business as other customers or markets are currently accessible to us.

Our ability to market oil and natural gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and natural gas, available storage, the proximity of our natural gas and oil production to pipelines and corresponding markets, the available capacity in such pipelines, the demand for natural gas and oil, the effects of weather, and the effects of state and federal regulation. While we have not experienced significant difficulty in finding a market for our production as it becomes available or in transporting our production to those markets, there is no assurance that we will always be able to market all of our production or obtain favorable prices.

Marketing and Differentials

In NEPA, we continually monitor ongoing market dynamics to ensure equity gas sales are well positioned in terms of market optionality and counterparty liquidity. Within our operating area, sales are generally exposed to indices (denoted in parentheses) located on Eastern Gas Pipeline (South), Millennium Pipeline (East Pool), Tennessee Gas Pipeline (Zone 4), and Transco Pipeline (Leidy). We will periodically enter into longer-term commitments with downstream pipelines for firm transportation service. 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. The remaining term on these contracts range from a few months to 10 years, with an average remaining duration of 3.6 years as of December 31, 2025.

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. We are currently

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negotiating extensions of several Barnett transportation agreements to preserve optionality to transport volumes out of the Barnett.

We were assigned 205,716 MMBtu/d of firm transport on Energy Transfer and Houston Pipe Line Company LP ("Houston Pipe Line"), which expires in 2027. We also received two firm transport contracts with these same shippers from the Bedrock Acquisition for 23,750 MMBtu/d each, both subject to yearly volume reductions that expire in 2028. These contracts with Energy Transfer and Houston Pipe Line provide access to the NGPL-TxOk market.

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. Additionally, Temple I holds 125,000 MMBtu/d of interruptible transport with Atmos Pipeline for delivery to Temple I, which terminates upon cancellation by the parties.

Unless otherwise mentioned, under all firm transportation contracts, we pay reservation fees, regardless of usage, to hold transportation rights of the contracted volume on these pipelines for the duration of the contract. As of December 31, 2025, our minimum aggregate required payments per year under firm gathering and transportation agreements were $70.2 million for 2026, $62.1 million for 2027, $53.9 million for 2028, $34.3 million for 2029, $5.9 million for 2030, and $33.0 million for 2031 and beyond. The utilization and economic optimization of the upstream business units’ firm transportation contracts are currently managed by Concord Energy, LLC, who acts as the marketing agent for all our upstream marketed volumes. We believe that all of our transport contracts for NEPA, the Barnett, and the Temple Plants are at competitive rates.

Seasonality

Weather conditions have a significant impact on the demand for natural gas used for heating loads and natural gas-fired power generation. Demand for natural gas is generally at its lowest during the spring and fall months and peaks during the summer and winter months. Demand in the winter season peaks due to residential and commercial heating load demand, while the summer season peaks due to cooling loads, which calls on increased natural gas-fired power generation loads. However, seasonal anomalies such as warmer than normal winters or cooler than normal summers can lessen the magnitude of the seasonal fluctuations in demand. In addition, natural gas storage facilities are utilized to bring additional supply to the market that is utilized to meet peak demand levels during both winter and summer seasons.

In addition to the demand side effects, specific seasonal weather events can also have an effect on available natural gas 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 may also have detrimental effects on available supply.

These seasonal anomalies can also increase competition for equipment, supplies, and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations. Similarly, winter months may bring about delays in operational capabilities and efficiency of execution related to new and existing supply.

Competition

The oil and gas industry is very competitive and we compete with a substantial number of other companies, many of which are large, well-established, and have greater financial and operational resources than we do. We compete with several other onshore unconventional natural gas producers to deliver our products to the marketplace.

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. Competition is particularly intense in the acquisition of prospective oil and gas properties. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. 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. Shortages of equipment, labor, or materials may result in increased costs or the inability to obtain such resources as needed. Many of our larger competitors may have a competitive advantage when responding to commodity price volatility and overall industry cycles. Further, inflation may affect us more than it may affect some of our larger competitors.

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. In addition, certain of our directors or officers may own disproportionate interests (in percentage or value terms) in Banpu or its related companies. These ownership

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interests and/or such disparity could create, or appear to create, potential conflicts of interest when the applicable individuals are faced with decisions that could have different implications for us, Banpu, or its related companies.

Human Capital Resources

As of December 31, 2025, we had a total of 452 employees. We hire independent contractors on an as-needed basis. We and our employees are not subject to any collective bargaining agreements.

Safety. Safety is our highest priority, including the prevention of any releases from our operations. We conduct routine maintenance and inspections at our facilities, and we have established practices and operational infrastructure to control and mitigate potential spills or discharges. We also offer annual specialized training to staff on spill prevention and host routine meetings to ensure our teams are fully trained on our response plan in the event of any releases. We believe these measures continue to strengthen our safety culture.

Compensation and Benefits. We recognize that our employees are our most valuable resource and that we must provide competitive compensation to ensure we attract and retain top talent. As part of our commitment to these efforts, we underwent a third-party evaluation in 2024 and again in late-2025 to confirm our compensation was both competitive and reflective of the work our employees were performing. We have standardized our job and pay structure based on best practices and market data. We continue to survey and update our pay structure to stay competitive with our peers. We have implemented a compensation framework that strives to pay employees fairly and consistently based on their skills, experience, and performance, which we believe is competitive compared to other companies in our industry.

To foster the health and well-being of our employees and their families, we offer all of our full- and part-time employees access to various financial, health, and/or wellness programs. We also offer short-term and long-term incentive plans, medical insurance coverage, parental leave, and paid time off for holidays, personal days, and vacation.

Diversity and Inclusion. We strongly believe that a diverse workforce fosters new ideas and makes us stronger as a company. Providing a safe, inclusive working environment for our employees and contractors is among our top priorities. Our executive leaders are committed sponsors and supporters of programs that foster an increase in diverse demographic representation, nurture the careers of underrepresented groups, and create a greater sense of inclusion and belonging.

We have a whistleblower policy supported by a confidential ethics and compliance hotline (available via call-in or an online submission portal) and a required manager and employee online training program that includes topics such as business ethics, human rights and diversity, equity, and inclusion. Completion of this training is tracked on a quarterly basis to ensure accountability.

Human Rights. Providing a safe, inclusive working environment for our employees and contractors is a priority. We do not tolerate discrimination or harassment of any kind. We also have a Human Rights Policy that applies to all of our employees and is aligned with the UN Declaration of Human Rights and the UN Guiding Principles on Business and Human Rights. We continue to monitor the effectiveness of our human rights policy to ensure alignment with the dynamic rights of our workforce. Our Human Rights Policy extends to all our operations, as well as partners, contractors, and suppliers, including security providers.

Recruitment, Retention and Development. We provide equal opportunity for all employees and consultants regardless of race, religion, gender, sexual orientation, age, ethnic or national origin, social origin, disability, family status, or any other protected status and personal characteristics for all aspects of employment. This applies to recruitment and talent attraction, training and professional development opportunities, promotions, and all employee benefits. Additionally, we prioritize local hiring for both employees and contractors, particularly in areas of field operations, to support employment opportunities in our local communities.

Government Regulation and Environmental Matters

Our operations are subject to extensive federal, state, and local laws and regulations that govern oil and natural gas operations, regulate the discharge of materials into the environment, or otherwise relate to the protection of the environment. These laws, rules, and regulations may, among other things:

•require the acquisition of various permits before drilling commences;

•require notice to stakeholders of proposed and ongoing operations;

•require the installation of expensive pollution control equipment;

•restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with oil and gas drilling and production and the disposal or other disposition of produced water;

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•limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas, or otherwise restrict or prohibit activities that could impact the environment, including water resources; and

•require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to plug and abandon wells.

Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil, and even criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities for failure to comply. Violations and liabilities with respect to these laws and regulations could also result in remedial clean-up obligations, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns, and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations, and cash flows. In certain instances, citizens or citizen groups also have the ability to bring legal proceedings against us if we are not in compliance with environmental laws or to challenge our ability to receive environmental permits that we need to operate. Some laws, rules, and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules, and regulations may restrict the rate of oil and gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. 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 believe that we are in material compliance with current applicable environmental laws, rules, and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition, results of operations, or cash flows. Nevertheless, changes in existing environmental laws or regulations or the adoption of new environmental laws or regulations, including any significant limitation on the use of hydraulic fracturing, could have the potential to adversely affect our financial condition, results of operations, and cash flows. Federal, state, or local administrative decisions, developments in the federal or state court systems or other governmental or judicial actions may influence the interpretation or enforcement of environmental laws and regulations and may thereby increase compliance costs. Environmental regulations have historically become more stringent over time, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation.

The following is a summary of the significant environmental laws to which our business operations are subject.

CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, is also known as the “Superfund” law. CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on parties that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Such “responsible parties” may be subject to joint and several liability under CERCLA for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own or lease properties that have been used for the exploration and production of natural gas, NGLs, and oil for a number of years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other wastes may have been disposed of or released on or under the properties currently owned or leased by us. Many of these properties have been operated by third parties whose management or possible release of hydrocarbons or other wastes was not under our control. These properties, and any wastes that may have been released on them, have the potential to be sources of CERCLA liability, and we could potentially be required to investigate and remediate such properties, including soil or groundwater contamination by prior owners or operators, or to perform remedial plugging or pit closure operations to prevent future contamination. States, including Texas, also have environmental cleanup laws analogous to CERCLA.

RCRA. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, the individual states administer some or all of the provisions of RCRA. While there is currently an exemption from regulation as hazardous waste under RCRA for drilling fluids, produced waters and most of the other wastes associated with the exploration and production of oil or gas, it is possible that some of these wastes could be classified as hazardous waste in the future and therefore be subject to more stringent regulation under RCRA. For example, in December 2016, the EPA and certain environmental organizations entered into a consent decree to address the EPA’s

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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. The consent decree required the EPA to propose a rulemaking no later than March 15, 2019, for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary; the EPA ultimately determined that a revision was not necessary. 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 Act. The Oil Pollution Act of 1990, or the OPA, contains numerous restrictions relating to the prevention of and response to oil spills into waters of the United States. The term “waters of the United States” has been interpreted broadly to include inland water bodies, including wetlands and intermittent streams. The OPA imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and gas facilities must develop, implement, and maintain facility response plans, conduct annual spill training for certain employees, and provide varying degrees of financial assurance. Owners or operators of a facility, vessel, or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs, and certain other damages arising from a spill. As such, a violation of the OPA has the potential to adversely affect our business, financial condition, results of operations and cash flows.

Clean Water Act. The Clean Water Act, or CWA, and implementing regulations, which are primarily executed through a system of permits, also govern the discharge of certain pollutants into waters of the United States. Enforcement for failure to comply strictly with the CWA are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities or to cease hauling wastewaters to facilities owned by others that are the source of water discharges to resolve non-compliance. The CWA also requires the preparation and implementation of Spill Prevention, Control and Countermeasure Plans in connection with on-site storage of significant quantities of oil. In 2016, the EPA promulgated wastewater pretreatment standards that prohibit onshore unconventional oil and gas extraction facilities from sending wastewater to publicly-owned treatment works. This restriction of disposal options for hydraulic fracturing waste may result in increased costs. In addition, state laws analogous to the CWA also may require permits for certain of our operations. For additional information, see “Risk Factors - Risks Related to Environmental, Legal Compliance and Regulatory Matters - We may face unanticipated water and other waste disposal costs as a result of increased water-related regulations.”

Safe Drinking Water Act. The Safe Drinking Water Act, or SDWA, and comparable local and state provisions restrict the disposal, treatment, or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including oil and gas wastewater disposal wells or enhanced oil recovery) is governed by U.S. federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. The SDWA’s UIC Program requires that we obtain permits from the EPA or delegated state agencies for our disposal and other injection wells, establishes minimum standards for UIC well operations, restricts the types and quantities of fluids that may be injected, and prohibits the migration of fluid containing any contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the UIC wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources, and imposition of liability by landowners or other parties claiming damages for the procurement of alternative water supplies, property damages, and personal injuries. In addition, in some instances, the operation of UIC wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of UIC wells, and regulators in some states have imposed or are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. The adoption of federal, state, and local legislation and regulations intended to address induced seismic activity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays.

We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells in which we act as operator. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional plays, and is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. Concerns have been raised that hydraulic fracturing activities, separate and apart from use of UIC wells, may be correlated to induced seismicity. In addition, the EPA conducted a comprehensive study of the potential adverse impacts of hydraulic fracturing on drinking water and ground water and released its final report on this study in December 2016. The report found that hydraulic fracturing

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activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. 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. Such costs and burdens could delay the development of unconventional gas resources from shale formations, which are not commercially feasible without the use of hydraulic fracturing.

Additionally, the EPA has established the Class VI well classification under the SDWA UIC for wells used for long-term geologic sequestration of CO2. We will be required to obtain a Class VI permit for our CCUS projects that do not meet the criteria for Class II oil and gas related acid gas injection wells. The Class VI UIC permit program is currently administered by the EPA in all states except for Louisiana, Texas, Wyoming, North Dakota, West Virginia, and Arizona, which have assumed primacy for Class VI permitting. Class VI permits currently require a lengthy permitting process, and the costs and regulatory burdens associated with obtaining Class VI permits could delay development of our CCUS projects.

Chemical Disclosures Related to Hydraulic Fracturing. A number of states, including Texas, have implemented chemical disclosure requirements for hydraulic fracturing operations. We currently disclose all hydraulic fracturing additives we use on www.FracFocus.org, a website created by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission.

Prohibitions and Other Regulatory Limitations on Hydraulic Fracturing. There have been a variety of regulatory initiatives at the state level to restrict oil and gas drilling operations in certain locations.

In addition to rules requiring the disclosure of chemicals used in hydraulic fracturing fluids, some states have implemented permitting, well construction or water withdrawal regulations that may increase the costs of hydraulic fracturing operations. For example, Texas has water withdrawal restrictions allowing suspension of withdrawal rights in times of shortages while other states require reporting on the amount of water used and its source.

Increased regulation of and attention given by environmental interest groups, as well as state and federal regulatory authorities, to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and gas, including from developing shale plays, or could make it more difficult to perform hydraulic fracturing. These developments could also lead to litigation challenging proposed or existing wells. The adoption of federal, state, or local laws or the implementation of regulations regarding hydraulic fracturing that are more stringent could cause a decrease in the completion of new oil and gas wells, as well as increased compliance costs and time, which could adversely affect our financial position, results of operations, and cash flows. We use hydraulic fracturing extensively and any increased federal, state, or local regulation of hydraulic fracturing could reduce the volumes of oil and gas that we can economically recover.

Clean Air Act. Our operations are subject to the Clean Air Act, or the CAA, and comparable state and local requirements to control emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements, including additional permitting requirements. Federal and state laws designed to control toxic air pollutants and GHGs might require installation of additional controls. Payment of fines and correction of any identified deficiencies generally resolve any failures to comply strictly with air regulations or permits. However, in the event of non-compliance, regulatory agencies could also require us to cease construction or operation of certain facilities or to install additional controls on certain facilities that are air emission sources. Further, stricter requirements could negatively impact our production and operations.

In 2012, the EPA published final New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) that amended the existing NSPS and NESHAP for the oil and natural gas sector. In June 2016, the EPA published a final rule that updated and expanded the NSPS by setting additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. In June 2017, the EPA proposed a two-year stay of certain requirements contained in the June 2016 rule. In March 2018, the EPA published a final rule that amended two narrow provisions of the NSPS, removing the requirement for completion of delayed repair during emergency or unscheduled vent blowdowns. In September 2020, the EPA published a final rule amending the 2012 and 2016 NSPS for the oil and natural gas sector that removed transmission and storage sources from the oil and natural gas industry source category and rescinded the methane requirements applicable to the production and processing sources. On June 30, 2021, former President Biden signed into law a joint Congressional resolution under the Congressional Review Act nullifying the September 2020 rule amending the EPA’s 2012 and 2016 NSPS standards for the oil and natural gas sector and effectively reinstating the prior standards. More recently, on March 8, 2024, the EPA

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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. In late 2025, the EPA issued final rules extending certain compliance deadlines in the Methane Rule and the NSPS rules for the oil and gas sector. It remains to be seen what impact the Trump Administration ultimately will have on these and other climate-related measures taken under the Biden Administration. The reinstatement of direct regulation of methane emission for new sources, promulgation of requirements for existing oil and gas sources, and enhanced requirements for new sources and the expansion of sources covered by the EPA’s rules, could result in increased compliance costs or otherwise impact our results of operations. For additional information, see “Risk Factors — Risks Related to Environmental, Legal Compliance and Regulatory Matters — 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.”

In October 2015, the EPA revised the existing National Ambient Air Quality Standards for ground level ozone to make the standard more stringent. The EPA finished promulgating final area designations under the new standard in 2018, which, to the extent areas in which we operate have been classified as non-attainment, may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. Generally, it will take the states several years to develop compliance plans for their non-attainment areas. In December 2020, the EPA completed its review of the currently available scientific evidence and risk information and decided to retain the existing ozone National Ambient Air Quality Standards. While we are not able to determine the extent to which this standard will impact our business at this time, it has the potential to have a material impact on our operations and cost structure.

Collectively, these rulemaking actions, as well as any future laws and their implementing regulations, may require a number of modifications to our operations. We may, for example, be required to install new equipment to control emissions from our well sites or compressors at initial startup or by the applicable compliance deadline. We may also be required to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

Greenhouse Gas and Climate Change Laws and Regulations. Scientific studies have concluded that increasing concentrations of GHGs in the Earth’s atmosphere are producing climate changes that have significant physical effects. Potential physical risks resulting from climate change may be event driven (including increased severity of extreme weather events, such as hurricanes, droughts, or floods) or longer-term shifts in climate patterns that may cause sea level rise or chronic heat waves. Potential physical risks may cause direct damage to our assets as well as indirect impacts such as supply chain disruption and also could include changes in water availability, sourcing, and quality, which could impact drilling and completion operations. These physical risks could cause increased costs, production disruptions, lower revenues and substantially increase the cost or limit the availability of insurance. In response to studies indicating that emissions of carbon dioxide and certain other GHGs, including methane, are contributing to global climate change, there is increasing focus by local, state, regional, national and international regulatory bodies as well as by investors and the public on GHG emissions and climate change issues.

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. For example, in response to 2009 findings that emissions of CO2, methane and other GHGs present an endangerment to public health and the environment, the EPA issued regulations to restrict emissions of GHGs under existing provisions of the CAA, commonly known as the “Endangerment Finding,” which underpins the EPA’s regulation of greenhouse gas emissions. On February 18, 2026, the EPA published a final rule rescinding the Endangerment Finding. The rescission has been challenged in court, which could result in the rescission being stayed, overturned or limited in scope or effect. If the rescission remains in effect, the EPA may seek in the future to repeal or lessen the stringency of regulations affecting the oil and natural gas industry that are based, at least in part, on the Endangerment Finding. Further, it is possible that efforts to regulate GHGs at the national level in the United States, which could include reconsidering the Endangerment Finding, could occur in the future. The ultimate outcome and long-term effect of the rescission of the Endangerment Finding, as well as its impact on regulation of the oil and natural gas industry, remains uncertain.

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. The EPA widened the scope of annual GHG reporting to include not only activities associated with completion and workover of gas wells with hydraulic fracturing and activities associated with oil and gas production operations, but also completions and

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workovers of oil wells with hydraulic fracturing, gathering and boosting systems, and transmission pipelines. These rules do not require control of GHGs. On September 12, 2025, the EPA issued a proposed rule that would rescind the GHG reporting rule, other than for natural gas systems subject to waste emission charges, and would delay requirement or these systems until 2034. It remains to be seen what the ultimate outcome of this proposal will be and what the ultimate impact and long-term effect the Trump Administration rollback initiatives will have on this and other climate-related measures taken under the Biden Administration. For more information, see “Risk Factors — Risks Related to Environmental, Legal Compliance and Regulatory Matters — 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.”

In certain circumstances, large sources of GHG emissions are subject to preconstruction permitting under the EPA’s Prevention of Significant Deterioration program. This program historically has had minimal applicability to the oil and gas production industry. However, there can be no assurance that our operations will avoid applicability of these or similar permitting requirements, which impose costs relating to emissions control systems and the efforts needed to obtain the permit.

In April 2016, the United States signed the Paris Agreement, which requires countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”), which set GHG emission reduction goals, every five years beginning in 2020. In November 2019, the Trump Administration formally moved to exit the Paris Agreement, initiating the treaty-mandated one-year process at the end of which the United States officially exited the agreement. The United States officially rejoined the Paris Agreement on February 19, 2021, and in April 2021 submitted its NDC, which set an economy-wide target of net GHG emissions reduction from 2005 levels of 50-52% by 2030. However, effective on January 26, 2026, the Trump Administration again formally exited the Paris Agreement. It remains to be seen what the long-term effect of this action will be.

The United States Congress (“Congress”) has also passed a number of bills in recent years aimed at addressing climate change in a limited manner, primarily directed at funding climate change initiatives. The 2021 Infrastructure and Investment Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) included measures aimed at decarbonization to address climate change, including funding for replacing transit vehicles, including buses, with zero- and low-emission vehicles and for the deployment of an electric vehicle charging network nationwide. This legislation, and other future laws, that promote a shift toward electric vehicles could adversely affect the demand for our products. Similarly, the Inflation Reduction Act imposed several new climate-related requirements on oil and gas operations and the Inflation Reduction Act of 2022 appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on GHG emissions from certain facilities. The emissions fee and funding provisions of the law, if and when they take effect, could increase our operating costs and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations. The Trump Administration has delayed or rolled back most of the climate-related measures taken under the Biden administration, but it is possible that future administrations could again pursue these or other climate-related initiatives.

In the absence of comprehensive climate change legislation at the federal level, a number of state and regional efforts have emerged. These include measures aimed at tracking and/or reducing GHG emissions through cap-and-trade programs, which typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting GHGs. In addition, a coalition of over 20 U.S. state governors formed the United States Climate Alliance to advance the objectives of the Paris Agreement, and several U.S. cities have committed to advance the objectives of the Paris Agreement at the state or local level as well. To this end, the California governor issued an executive order on September 23, 2020 ordering actions to pursue GHG emissions reductions, including a direction to the California State Air Resources Board to develop and propose regulations to require increasing volumes of new zero-emission passenger vehicles and trucks sold in California over time, with a targeted ban of the sale of new gasoline vehicles by 2035. In addition, California enacted two new climate disclosure laws in September 2023 that (1) require U.S.-based businesses with total annual revenues over one billion dollars and doing business in California to annually report their Scope 1, 2, and 3 GHG emissions, and (2) require U.S.-based businesses with total annual revenues over five hundred million dollars and doing business in California to prepare biennial risk reports disclosing the entity’s climate-related financial risk and measures adopted to reduce and adapt to climate-related financial risk. Litigation challenging the California climate disclosure laws is ongoing. Although reporting under both laws was slated to commence in 2026, on November 18, 2025, the U.S. Court of Appeals for the Ninth Circuit issued an injunction prohibiting enforcement of the climate-related financial risk disclosure law pending its consideration of a First Amendment challenge to the law. The California Air Resources Board has issued guidance on compliance with the disclosure laws and is in the process of developing regulations to implement the California climate-related disclosure requirements. Furthermore, if the SEC’s climate disclosure requirements remain in place and are ultimately enforced by the SEC or if similar requirements are put in place

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in the future, we will be required to incur significant time and money to comply with the disclosure requirements and may be required to modify certain of our operations. 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. Any future laws or regulations that limit emissions of GHGs from our equipment and operations could require us to both develop and implement new practices aimed at reducing GHG emissions, such as emissions control technologies, which could increase our operating costs and adversely affect demand for the oil and gas that we produce. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of, and access to, capital. Future implementation or adoption of legislation or regulations adopted to address climate change could also make our products more or less desirable than competing sources of energy. At this time, it is not possible to quantify the impact of any such future developments on our business.

OSHA. We are subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations, and the provision of such information to employees, state and local government authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations.

Endangered Species Act. The Endangered Species Act, or ESA, was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas it believes are necessary for survival of a threatened or endangered species. While some of our facilities are in areas that may be designated as a habitat for endangered species, we believe that we are in substantial compliance with the ESA. The presence of any protected species or the final designation of previously unprotected species as threatened or endangered in areas where we operate could result in increased costs from species protection measures or could result in limitations, delays, or prohibitions on our exploration and production activities that could have an adverse effect on our ability to develop and produce our reserves.

National Environmental Policy Act. Oil and gas exploration and production activities on federal lands trigger review under the National Environmental Policy Act. The National Environmental Policy Act requires federal agencies, including the U.S. Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment of the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process has the potential to delay or even halt development of some of our oil and gas projects.

Environmental Justice Considerations. Attention to environmental justice considerations — from activist groups and/or government regulators — may impede or otherwise have an adverse effect on our ability to develop both our fossil fuel assets and our proposed CCUS projects. For example, the Biden Administration created a White House Office of Environmental Justice in April 2023, and all federal agencies were directed to make environmental justice a central part of each agency’s mission by publishing an environmental justice strategic plan for the agency. Although this office no longer exists and environmental justice considerations are not a focus of the Trump Administration, a future administration could change course and, if so, the development and application of environmental justice requirements may result in permit uncertainty and delays for our activities that require federal approvals.

Operating Hazards and Insurance

Natural gas and NGL operations are subject to many risks, including well blowouts, craterings, explosions, uncontrollable flows of natural gas, NGLs or well fluids, fires, pipe, casing or cement failures, abnormal pressure, pipeline leaks, ruptures or spills, vandalism, pollution, releases of toxic gases, adverse weather conditions or natural disasters, and other environmental hazards and risks. In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot provide assurance that any insurance we obtain will be adequate to cover our losses or liabilities. We have elected to self-insure for certain items for which we have determined that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position, results of operations, and cash flows.

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

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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. Our corporate headquarters are leased and our field office facilities are owned, and we believe that they are adequate for our current needs.

Title to Properties

Title to our oil and gas properties is subject to royalty, overriding royalty, carried, net profits, working, and similar interests customary in the oil and gas industry. Our properties may also be subject to liens incident to operating agreements, as well as other customary encumbrances, easements, and restrictions, and for current taxes not yet due. Our general practice is to conduct title examinations on material property acquisitions. Prior to the commencement of drilling operations, a title examination and, if necessary, curative work is performed. The methods of title examination that we have adopted are reasonable in the opinion of management and are designed to ensure that production from our properties, if obtained, will be salable by us. We believe that title to our oil and natural gas properties is good and defensible, subject only to such exceptions that we believe do not materially interfere with the use of such properties.

Address, Internet Website, and Availability of Public Filings

Our principal executive offices are located at 1200 17th Street, Suite 2100, Denver, Colorado 80202, and our telephone number is (720) 375-9680. We also maintain an offices in Fort Worth, Texas as well as several regional field offices. Our website is www.bkv.com.

We furnish or file our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K, and amendments to such reports and other documents with the SEC under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. We also make these documents available free of charge at www.bkv.com under the “Investors” link as soon as reasonably practicable after they are filed or furnished with the SEC. Our Sustainability Report is also available on our website.

Information on our website is not incorporated into this Annual Report on Form 10-K or our other filings with the SEC and is not a part of them.

Information about our Executive Officers (as of March 6, 2026)

Name
Age
Current Title (Year Initially Elected an Executive Officer)

Christopher P. Kalnin 48Chief Executive Officer (2020)

David R. Tameron58Chief Financial Officer (2025)

Eric S. Jacobsen
55
President — Upstream (2020)

Barry S. Turcotte55Chief Accounting Officer (2022)

Lindsay B. Larrick43
Chief Legal and Chief Administrative Officer (2022)

Ethan Ngo44
Chief Corporate Development Officer (2022)

Dilanka Seimon45Chief Commercial Officer (2025)

______________________________________

Christopher P. Kalnin has served as Chief Executive Officer and a director of the Company since its formation in May 2020 and founded the Company in 2015. In September 2023, he was appointed as a member of a newly established Executive Committee of Banpu, with the delegation of authority to manage all aspects of Banpu’s businesses in North America, among other things, and has served as a member of the board of managers of the BKV-BPP Power Joint Venture since October 2021. He also worked at Kalnin Ventures, the fund manager of BKV Oil and Gas Capital Partners, L.P., owned by Banpu (SET: BANPU), as Managing Director from June 2014 to May 2020 and Group CEO from January 2019 to May 2020. Prior to that, Mr. Kalnin served in multiple roles at Level 3 Communications, Inc., a global provider of high-capacity communications services to businesses, serving as Vice President of Strategic Business Operations and Planning from January 2014 to June 2014 and Senior Director from February 2012 to December 2013. From January 2010 to July 2011, he served as a Strategy Advisor and Chief of Staff to the Chief Executive Officer at PTT Exploration (SET: PTTEP), a petroleum exploration and production company based in Thailand. Additionally, he served as Engagement Manager at McKinsey & Company, a management consulting firm, from October 2005 to January 2010 and Senior Analyst at Credit Suisse First Boston, the investment banking division of Credit Suisse Group, from July 2000 to July 2003. Mr. 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.

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David R. Tameron has served as Chief Financial Officer of the Company since April 2025. Mr. Tameron previously served as the Company’s Vice President, Strategic Finance and Investor Relations from August 2022 to March 2025. Prior to joining BKV in August 2022, Mr. Tameron served in various roles at Wells Fargo & Company, including as Managing Director of Denver-based Corporate Banking, from September 2017 to August 2022, and as Managing Director, Institutional Equity Research, from July 2006 to August 2017. Mr. Tameron earned an MBA from the Fuqua School of Business at Duke University and a BA in Finance from Arizona State University.

Eric S. Jacobsen has served as President — Upstream of the Company since February 2025 and as a member of the board of managers of the BKV-BPP Power Joint Venture since March 2025. Mr. Jacobsen previously served as Chief Operating Officer of the Company from its formation in May 2020 to February 2025. He also served as Chief Operating Officer of Kalnin Ventures from February 2020 to May 2020. Prior to that, he served as Senior Vice President of Extraction Oil & Gas, Inc. (previously NASDAQ: XOG), an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves, from October 2016 to December 2019 and Director of Planning and Development, Director of Exploration and Production and Well Engineering Manager of Noble Energy, Inc. (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. Jacobsen worked at BP (NYSE: BP) and its heritage companies, Atlantic Richfield Company and Vastar Resources, Inc., in Montana, Texas, Louisiana, Gulf of Mexico, Algeria, Azerbaijan and other locations and in various positions, including Operations Manager, Offshore Installation Manager and Reservoir Engineer. Mr. Jacobsen received a BS in Environmental Engineering and an MS in Petroleum Engineering from Montana Tech University.

Barry S. Turcotte has served as Chief Accounting Officer of the Company since December 2022. Prior to joining the Company, he most recently served as Senior Vice President and Chief Financial Officer of Crestone Peak Resources, a privately held oil and natural gas company, from May 2017 to November 2021. In addition, Mr. Turcotte served as Chief Accounting Officer of RSP Permian, Inc. (NYSE: RSPP), a publicly listed oil and natural gas company, from April 2014 to May 2017. Prior to that, he served in various positions at Swift Energy Company (NYSE: SFY), a publicly listed oil and natural gas exploration and production company, including Vice President of Accounting and Controller from December 2009 to April 2014, Assistant Controller from April 2005 to November 2009 and other progressive positions of responsibility after joining Swift Energy Company in 2001. He also served in various progressive accounting positions at Westlake Group of Companies, a global chemical manufacturer, from 1995 to 2001. Mr. Turcotte began his career as an auditor in the energy group of Ernst & Young LLP from 1993 to 1995. He has over 30 years of experience in the accounting and finance professions, including in the oil and gas industry. Mr. Turcotte is a Certified Public Accountant and received a BBA from the University of Houston and an Executive MBA from the University of Houston.

Lindsay B. Larrick has served as Chief Administrative Officer of the Company since February 2025 and as Chief Legal Officer of the Company since July 2022. She has also served as a member of the board of managers of the BKV-BPP Power Joint Venture since February 2025. Ms. Larrick previously served as Vice President, General Counsel and Corporate Secretary of the Company from its formation in May 2020 to July 2022, and as Vice President and General Counsel of Kalnin Ventures from October 2018 to May 2020. Prior to that, she was a partner at national law firms Fox Rothschild LLP from July 2016 to October 2018 and Lathrop & Gage LLP from January 2007 to July 2016. During her time at such law firms, she specialized in the energy practice, served in various management positions, including Chair of the Energy Practice Group for both firms, and gained experience in structuring private equity funds and mergers, acquisitions and divestitures in the oil and gas industry. Ms. Larrick received a BS in Business Administration and a JD from the University of Denver.

Ethan Ngo has served as Chief Corporate Development Officer of the Company since February 2025 and as a member of the board of managers of the BKV-BPP Power Joint Venture since June 2024. Mr. Ngo previously served as Chief Technical Resources Officer of the Company from July 2022 to February 2025 and, prior to that, as Senior Vice President, Engineering of the Company from its formation in May 2020 to July 2022. He served at Kalnin Ventures as Senior Vice President, Engineering since December 2017 and Vice President, Engineering from March 2015 to December 2017. Prior to that, Mr. Ngo served as A&D Reservoir Engineer of Fidelity Exploration and Production Company, which is involved in the acquisition, exploration, development and production of natural gas and oil resources, from July 2014 to March 2015, Reservoir Engineer of Liberty Resources LLC, a Denver-based private equity backed oil and gas company, from April 2013 to June 2014 and Reservoir Engineer of Newfield Exploration Company (previously NYSE: NFX), an independent energy company, from April 2011 to April 2013. 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.

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Dilanka Seimon has served as Chief Commercial Officer of the Company since April 2025. Prior to joining the Company, Mr. Seimon served as Executive Vice President and Chief Commercial Officer at EnLink Midstream (now, ONEOK) from August 2023 to February 2025, and as Vice President of Alternative Energy at Energy Transfer (NYSE: ET), from January 2022 to August 2023. From March 2013 through December 2021, Mr. Seimon served at BHP Group Limited (NYSE: BHP), the world's largest mining company by market capitalization, working his way up to Vice President of Sales and Marketing. Earlier in his career, he held various roles in business development, natural gas trading, marketing, and origination. Mr. Seimon completed the General Management Program at Harvard Business School, earned an MBA from the Fuqua School of Business at Duke University, and received a BS in Economics from Georgia College & State University.