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Glossary of Commonly Used Terms

“Adjusted Free Cash Flow” refers to net cash provided by (used in) operating activities, excluding cash paid for contingent consideration and changes in operating assets and liabilities, less total cash paid for capital expenditures (excluding leasehold costs and acquisitions). Adjusted Free Cash Flow is not a measure of net cash flow provided by or used in operating activities as determined by GAAP. Adjusted Free Cash Flow is a supplemental non-GAAP financial measure that is used by our management and other external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others to assess our ability to internally fund our capital program, service or incur additional debt and to pay dividends.

“Banpu” refers to our sponsor, Banpu Public Company Limited, a public company listed on the Stock Exchange of Thailand and the ultimate parent company of BKV Corporation, BNAC, Banpu Power, and BPPUS.

“Banpu Power” refers to Banpu Power Public Company Limited, a public company listed on the Stock Exchange of Thailand. Banpu owns approximately 75.5%% of Banpu Power as of December 31, 2024.

“Barnett” refers to the Barnett Shale in the Fort Worth Basin of Texas.

“Bbl” refers to one stock tank barrel, of 42 U.S. gallons liquid volume, used in this Annual Report on Form 10-K in reference to crude oil or other liquid hydrocarbons.

“Bcf” refers to one billion cubic feet of natural gas or CO2.

“Bcfe” refers to one billion cubic feet of natural gas equivalent.

“BKV dCarbon Ventures” refers to BKV dCarbon Ventures, LLC, a Delaware limited liability company and the CCUS business of BKV Corporation.

“BKV Operating” refers to BKV Operating, LLC, a Delaware limited liability company and wholly-owned subsidiary of BKV Corporation.

“BKV Upstream Midstream” refers to BKV Upstream Midstream, LLC, a Delaware limited liability company and wholly-owned subsidiary of BKV Corporation.

“BKV-BPP Cotton Cove” or “BKV-BPP Cotton Cove Joint Venture” refers to BKV-BPP Cotton Cove, LLC, a Delaware limited liability company and the joint venture between BKV dCarbon Ventures and BPPUS, in which we own an indirect 51% interest.

“BKV-BPP Power” or “BKV-BPP Power Joint Venture” refers to BKV-BPP Power, LLC, a Delaware limited liability company and the joint venture between BKV Corporation and BPPUS, in which we own a 50% interest.

“BKV-BPP Retail” refers to BKV-BPP Retail, LLC, a Delaware limited liability company and wholly-owned subsidiary of the BKV-BPP Power Joint Venture.

“BKVerde” refers to BKVerde, LLC, a Delaware limited liability company and wholly-owned subsidiary of BKV dCarbon Ventures.

“BNAC” refers to Banpu North America Corporation, a subsidiary of Banpu, our sponsor, and the majority stockholder of BKV Corporation.

“BPPUS” refers to Banpu Power US Corporation, a wholly-owned subsidiary of Banpu Power and the owner of a 50% interest in the BKV-BPP Power Joint Venture and a 49% interest in the BKV-BPP Cotton Cove Joint Venture.

“Btu” refers to British thermal unit, which is the heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit.

“Carbon Sequestered Gas” refers to a Scope 1, 2, and 3 carbon neutral natural gas product.

“CCUS” refers to carbon capture, utilization, and sequestration.

“CO2” refers to carbon dioxide.

“CO2e” refers to carbon dioxide equivalent.

“Code” means the Internal Revenue Code of 1986, as amended.

“developed reserves” are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Devon Barnett Acquisition” refers to our acquisition of more than 289,000 net acres, 3,850 producing operated wells and related upstream assets in the Barnett from Devon Energy Corporation, which closed in October 2020.

“dry hole” refers to a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Effective NRI” refers to our share of leasehold ownership after all burdens, such as royalty and overriding royalty interests, have been deducted from the working interest, weighted by our net acres owned in the Barnett from the assets acquired in the Devon Barnett Acquisition and the Exxon Barnett Acquisition.

“ERCOT” refers to the Electric Reliability Council of Texas.

“ESG” refers to environmental, social, and governance.

“Exxon Barnett Acquisition” refers to our acquisition of approximately 165,000 net acres, 2,100 operated wells and related natural gas upstream, midstream and other assets in the Barnett from XTO Energy, Inc. and Barnett Gathering LLC, subsidiaries of Exxon Mobil Corporation, which closed on June 30, 2022.

“FID” refers to final investment decision.

“GAAP” refers to generally accepted accounting principles in the United States.

“GHG” refers to greenhouse gases.

“governing documents” refers to our certificate of incorporation and our bylaws.

“gross acres,” “gross acreage” or “gross wells” refers to the total acres, acreage or wells, as the case may be, in which a working interest is owned.

“High West” refers to High West Sequestration, LLC, a Louisiana limited liability company and wholly-owned subsidiary of BKV dCarbon Ventures.

“HRCO” refers to a contract for the financial purchase and sale of power based on a floating price of natural gas at a predetermined location using a predetermined conversion factor, or heat rate, required to turn the fuel input into electricity.

“IPIECA” refers to the International Petroleum Industry Environmental Conservation Association.

“Kalnin Ventures” refers to Kalnin Ventures LLC, a Colorado limited liability company and wholly-owned subsidiary of BKV Corporation.

“lean gas” refers to natural gas that contains a few or no liquefiable liquid hydrocarbons.

“LNG” refers to liquefied natural gas.

“MBbls” refers to one thousand barrels of crude oil or other liquid hydrocarbons.

“Mcf” refers to one thousand cubic feet.

“Mcf/d” refers to one thousand cubic feet per day.

“Mcfe” refers to one thousand cubic feet of natural gas equivalent.

“MMBtu” refers to one million British thermal units, which is the heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit.

“MMcf” refers to one million cubic feet.

“MMcf/d” refers to one million cubic feet per day.

“MMcfe” refers to one million cubic feet of natural gas equivalent, calculated by converting barrels of crude oil or other liquid hydrocarbons to natural gas at a ratio of one Bbl to six Mcf of natural gas. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

“MMcfe/d” refers to one million cubic feet of natural gas equivalent per day.

“Mtpy” refers to million metric tons per year.

“NEPA” refers to the Marcellus Shale in the Appalachian Basin of Northeast Pennsylvania.

“net acres” refers to the percentage of total acres an owner has out of a particular number of acres, or a specified tract. For example, an owner who has 50% interest in 100 acres owns 50 net acres.

“net operated development well” refers to a gross operated development well that has been drilled, proportionately reduced by our working interest in such well.

“net zero” refers to the full elimination and/or offset of Scope 1, Scope 2, and/or Scope 3 emissions, as applicable, from our owned and operated upstream businesses.

“NGL” refers to natural gas liquids.

“NGP” refers to natural gas processing.

“NYMEX” refers to the New York Mercantile Exchange.

“OPEC” refers to the Organization of the Petroleum Exporting Countries.

“OPIS” refers to a Dow Jones Company that surveys and collects price information and publishes benchmarks for various energy commodities.

“proved developed producing reserves” or “PDP reserves” refers to quantities of proved developed reserves expected to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

“proved reserves” refers to quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined an HKO elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (a) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (b) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“PUCT” refers to the Public Utility Commission of Texas.

“PUD reserves” refers to proved undeveloped reserves.

“RBL Borrower” refers to BKV Upstream Midstream, LLC, a wholly-owned subsidiary of BKV Corporation.

“RBL Credit Agreement” refers to that certain reserve-based lending agreement dated as of June 11, 2024, among BKV Corporation, the RBL Borrower, Citibank, N.A., as administrative agent, and the financial institutions party thereto.

“Responsibly Sourced Gas” or “RSG” refers to natural gas produced from a well which has gone through a third party environmental assessment and verification process and has a current TrustWell rating.

“Revolving Credit Agreement” refers to $100.0 million of commitments of unsecured revolving loans with Bangkok Bank Public Company Limited (New York Branch).

“Revolving Credit Facilities” refers to an uncommitted credit facilities with Oversea Chinese Banking Corporation and Standard Chartered Bank of up to $55.0 million and $50.0 million, respectively.

“Ryder Scott” refers to Ryder Scott Company, L.P., independent petroleum engineers.

“Scope 1 emissions” refers to direct GHG emissions that occur from sources that are controlled or owned by an organization.

“Scope 2 emissions” refers to indirect GHG emissions associated with the purchase of electricity, steam, heat or cooling.

“Scope 3 emissions” refers to GHG emissions that result from the end use of an organization’s products, as estimated per Category 11 (Use of Sold Product), as well as emissions from other business activities from assets not owned or controlled by the organization but that the organization indirectly impacts in its value chain.

“Section 45Q tax credits” refers to tax credits provided under Section 45Q of the Code.

“SREC” refers to Solar Renewable Energy Credit, which represents a form of environmental attribute associated with solar energy generation, which can be marketed for financial gain to improve project economics or retired to offset the SREC owner’s Scope 2 emissions. For every 1,000 kilowatt-hours of electricity produced by an eligible solar facility, one renewable energy credit and one compliance premium is awarded. The combination of a renewable energy credit and a compliance premium is known as an SREC. For a solar facility to be credited with that SREC, the system must be certified and registered by state agencies.

“Temple I” refers to the combined gas turbine and steam turbine power plant located in Temple, Texas and owned by the BKV-BPP Power Joint Venture.

“Temple II” refers to a second combined gas turbine and steam turbine power plant located in Temple, Texas, which power plant sits on the same site as Temple I and is owned by the BKV-BPP Power Joint Venture.

“Temple Plants” refers to Temple I and Temple II, collectively.

“Term Loan Credit Agreement” refers to a credit agreement with a syndicate of banks and Bangkok Bank Public Company Limited (New York Branch), as the administrative agent, which included $600.0 million of commitments for term loans used to solely to fund a portion of the purchase price for the Exxon Barnett Acquisition.

“undeveloped acreage” refers to acreage under lease on which wells have not been drilled or completed such that there is not production of commercial quantities of hydrocarbons.

“undeveloped reserves” are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

“working interest” refers to the right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

•the volatility of natural gas and NGL prices due to factors beyond our control;

•our reliance on a single third party for all of our natural gas marketing and another third party for substantially all of our natural gas and NGL midstream services with respect to the Barnett assets we acquired from Devon Energy;

•our reserves estimates are based on assumptions that may prove to be inaccurate;

•our ability to find or acquire additional natural gas and NGL reserves that are economically recoverable, including development of our proved undeveloped reserves and associated capital expenditures;

•uncertainties in evaluating the expected benefits and potential liabilities of recoverable reserves;

•risks and uncertainties related to drilling operations, which are high-risk and operationally complex;

•the availability or cost of water, equipment, supplies, personnel, and oilfield services;

•our limited control over activities on properties we do not operate;

•extreme weather, transmission congestion, and changes to the regulatory environment;

•the operation of our power generation business through a joint venture which we do not control;

•risks and hazards related to the operation or maintenance of electric generation facilities, including disruption of the fuel supplies necessary to generate power at the Temple Plants;

•the lack of long-term power sales agreements for the Temple Plants;

•the operation of our retail power business through a joint venture which we do not control;

•our ability to attract and retain customers in the competitive retail power marketplace;

•market price risk and changes in law, regulation, or market structure resulting in unanticipated costs;

•our ability to maintain our retail electric provider certification;

•our ability to successfully pursue and develop our CCUS business, the associated material capital investments, and any changes to financial and tax incentives;

•risks and hazards related to midstream operations as complex activities;

•our dependence on our natural gas midstream system;

•the geographical concentration of substantially all of our oil and gas and midstream properties;

•the effect of a deterioration in general economic, business, or industry conditions;

•our ability to achieve our near term and long-term net zero goals on our anticipated time frame;

•our ability to generate cash flow to meet our debt obligations or fund our other liquidity needs;

•events of default if we are unable to comply with restrictions in our debt agreements (including if any person or group (other than Banpu and its controlled affiliates, excluding portfolio companies and operating companies) acquires 35% or more of our equity interests, or if any person or group acquires a greater percentage of our equity interests than are then held by Banpu and its controlled affiliates (excluding portfolio companies and operating companies of Banpu));

•risks related to our debt and debt agreements and hedging arrangements that expose us to risk of financial losses and counterparty credit risk;

•our dependence, as a holding company, on our subsidiaries and our joint venture for cash;

•operating hazards that could result in substantial losses or liabilities for which we may not have adequate insurance coverage;

•our ability to make accretive acquisitions or successfully integrate acquired businesses or assets;

•our substantial capital requirements and our ability to obtain financing or fund working capital needs;

•the intense competition in the energy industry and our ability to compete with other companies;

•cybersecurity or physical security threats or disruptions or loss of our information systems;

•increased activism and negative investor sentiment regarding upstream activities and companies;

•the loss of our executive officers and technical personnel and our ability to retain technical personnel;

•exemptions from certain reporting requirements for as long as we are an emerging growth company;

•complex laws, regulations, and initiatives related to our operations and the use of hydraulic fracturing;

•the effect of increased attention to ESG matters and environmental conservation measures;

•reductions in demand for natural gas, NGL, and oil;

•risks related to climate change, including transitional, legal, political, financial, and physical risks;

•significant costs and liabilities related to environmental, health and safety laws, and regulations;

•potential tax law changes;

•complex and evolving laws and regulations regarding privacy and data protection;

•the substantial influence of Banpu, our controlling stockholder, over us;

•our historical reliance on Banpu for capital investments to fund our business operations;

•we expect to be a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for and could rely on exemptions from certain corporate governance requirements;

•conflicts of interest between Banpu and us or our other stockholders, or conflicts of interest of our officers and/or directors as a result of their positions with, or ownership of common stock of, Banpu;

•our actual operating results and activities could differ materially from our estimates;

•the impact of our lack of dividend payments on the market price of our common stock;

•the costs of, and our ability to comply with, the requirements of being a public company;

•we identified a material weakness in our internal control over financial reporting;

•the lack of an existing market for our common stock;

•provisions in our governing documents and Delaware law that could discourage acquisition bids or merger proposals; and

•future sales of our common stock in the public market, or the perception that such sales may occur, could reduce our stock price.

We describe these risks in greater detail under Item 1A., “Risk Factors.”

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

•our business strategy;

•our reserves;

•our financial strategy, liquidity, and capital required for our development programs;

•our relationship with Banpu, including future agreements with Banpu;

•actual and potential conflicts of interest relating to Banpu, its affiliates, and other entities in which members of our officers and directors are or may become involved;

•volatility in natural gas, NGL, and oil prices;

•our dividend policy;

•our drilling plans and the timing and amount of future production of natural gas, NGL, and oil;

•our hedging strategy and results;

•competition and government regulation;

•legal, regulatory, or environmental matters;

•marketing of natural gas, NGL, and oil;

•business or leasehold acquisitions and integration of acquired businesses;

•our ability to develop existing prospects;

•costs of developing our properties and of conducting our operations;

•our plans to establish midstream contracts that allow us to supply our own natural gas directly to the Temple Plants;

•our plan to continue to build out our power generation business and to expand into retail power;

•our ability to develop, produce, and sell Carbon Sequestered Gas;

•our ability to effectively operate and grow our CCUS business;

•our ability to forecast annual CO2e sequestration rates for our CCUS projects;

•our ability to reach final investment decision and execute and complete any of our pipeline of identified CCUS projects;

•our ability to identify and complete additional CCUS projects as we expand our upstream operations;

•our ability to effectively operate and grow our retail power business;

•our anticipated Scope 1, 2, and 3 emissions from our owned and operated upstream and natural gas midstream businesses and our sustainability plans and goals, including our plans to offset our Scope 1, 2, and 3 emissions from our owned and operated upstream and natural gas midstream businesses;

•our ESG strategy and initiatives, including those relating to the generation and marketing of environmental attributes or new products seeking to benefit from ESG-related activities, and the continuation of government tax incentives applicable thereto;

•the impact of the COVID-19 pandemic and its effects on our business and financial condition;

•general economic conditions;

•cost inflation;

•credit markets;

•our ability to service our indebtedness;

•our ability to expand our business, including through the recruitment and retention of skilled personnel;

•our future operating results;

•the remediation of our material weaknesses; and

•our plans, objectives, expectations, and intentions.

Overview

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.

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

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

As of December 31, 2024, we re-certified approximately 70% of our NEPA production and 48% 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 rating from Project Canary, a strong rating that will enable us to sell Responsibly Sourced Gas. In addition, we intend to advance the market for our produced gas beyond RSG and its current certification towards “Carbon Sequestered Gas,” a Scope 1, 2, and 3 carbon neutral natural gas product. We expect that production of Carbon Sequestered Gas will be achieved by bundling RSG with carbon credits sufficient to offset the estimated emissions associated with the production, gathering, and boosting of such RSG, as well as the estimated emissions from its transmission, distribution (if applicable), and ultimate combustion, with the quantified emissions and the requisite volume of CCUS offsets being third-party certified. We 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 with the ACR (formerly American Carbon Registry), once that registry has been 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.

In March 2024, BKV entered into a contract with Kiewit Infrastructure South Co., a subsidiary of Kiewit Corporation (“Kiewit”), for the sale and purchase of up to 100 MMBtu/d of our Carbon Sequestered Gas. 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).

Natural Gas Midstream

Power Generation

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.

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 to certify and register the environmental attributes associated with our CCUS projects as tradeable carbon credits. We expect our CCUS business to contribute in significant part to our goals to fully offset our Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses by the early 2030s, and our Scope 1, 2, and 3 emissions from our owned and operated upstream and natural gas midstream businesses by the late 2030s. However, we may not receive 100% of the environmental attributes associated with CCUS projects funded in whole or in part by third parties, and, in such cases, we expect to have the right to purchase such environmental attributes BKV would not otherwise receive. 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 up to 50% of our CCUS business from a variety of external sources, which may include joint ventures, project-based equity partnerships, debt financing, and federal grants, with the remaining capital needs being funded with cash flows from operations. We are currently in non-binding exclusive discussions concerning a potential joint venture with a third-party investor with the expectation to close in the first half of 2025. 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 per ton for CO2 directly stored in geologic formations, subject to satisfaction or non-application of certain prevailing wage and apprenticeship requirements (or $17 per ton if such prevailing wage and apprenticeship requirements are not satisfied), with adjustments for inflation after 2026. 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, will receive only a corresponding percentage of the anticipated Section 45Q tax credits associated with such projects.

CCUS Projects

in three states, with total reservoir storage capacity of over 1 billion metric tons of CO2e. 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 potential projects can be placed into six categories: (i) operational projects, (ii) projects that have reached FID, but are not yet operational, (iii) identified NGP projects under evaluation, (iv) identified industrial projects under evaluation, (v) identified ethanol projects under evaluation, and (vi) other potential projects that have been identified but not yet sufficiently evaluated. We have achieved notable milestones with respect to the projects within the first five categories, as more fully described below.

(1) 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.

(2) Our projected timeline for commencement of sequestration operations at the Cotton Cove Project, the Eagle Ford Project, and all of the pre-FID projects 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.”

(3) We may not receive 100% of the environmental attributes associated with CCUS projects funded in whole or in part by third parties, and, in such cases, we expect to have the right to purchase such environmental attributes BKV would not otherwise receive. 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.

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 these identified potential CCUS projects (or any other CCUS projects) with sufficient volumes of CO2e sequestration to achieve our Scope 1, 2, and 3 emissions goals on the timelines we anticipate. There can be no assurance that any of these identified potential CCUS projects, the Barnett Zero Project, or any other CCUS project will achieve the forecasted sequestration volumes, and we may not commence sequestration operations for any of the projects identified above by the anticipated timeframe, or at all.

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 owners of sources of CO2e, landowners and other stakeholders. In order to achieve the projected timeline for commercial operations of such projects, we expect to fund up to 50% of the anticipated cost of these CCUS projects from third party sources, which may include joint ventures, project-based equity partnerships, 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.

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 EnLink’s Bridgeport natural gas processing plant and neighboring operations. In the Barnett Zero Project, EnLink transports our natural gas produced in the Barnett to its natural gas processing plant in Bridgeport, Texas, where the 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 2024, the Barnett Zero Project achieved an annual sequestration rate of approximately 165,000 metric tons of CO2e.

Cotton Cove Project. On October 18, 2022, BKV dCarbon Ventures reached internal FID to develop our second 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 multiple pore space opportunities 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 $18.4 million, of which we will be required to contribute approximately $9.4 million. 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 in the first half of 2026, subject to our ability to secure all required permits, at which point we expect this project will be the second 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.

Eagle Ford Project. On December 18, 2024, BKV dCarbon Ventures reached internal FID to develop our third CCUS project for the sequestration of waste emissions from a natural gas processing plant. This CCUS project, which 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 CO2e per year. We currently estimate the total investment required for the Eagle Ford Project to be approximately $19.8 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 2026, subject to our ability to secure all required permits, 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 and Cotton Cove Projects.

We are currently evaluating the expansion of the Barnett Zero and Cotton Cove Projects to pilot, and subsequently scale post-combustion carbon capture technology. This initiative would allow us to sequester up to an additional approximately 250,000 metric tons per year of captured CO2e from low concentration emissions from within our natural gas midstream and/or other nearby processing operations. As part of this process, we intend to capture CO2e from sources such as compressor exhaust flues and utilize compressor waste heat to reduce energy requirements and cost.

We have identified other potential NGP projects that we anticipate will achieve FID and commence initial sequestration operations at various points in 2026 through 2029. If approved and implemented, we anticipate that these projects would sequester third-party emissions, require a total capital investment by us of approximately $730.0 million by December 31, 2029, and subsequently achieve a combined forecasted annual sequestration volume of approximately 2.70 million metric tons of captured CO2e per year.

Much of the carbon capture infrastructure required for these NGP projects is already in place. For example, we have amine towers to capture and concentrate CO2 emissions to meet natural gas sales specifications. Also, we have secured definitive agreements for pore space leasehold for several projects, and have submitted or are working towards submitting well permits. 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.

Industrial Projects

We are 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 in 2027 and 2028. If approved and implemented, these projects would provide a combined forecasted annual sequestration volume of approximately 11.30 million metric tons per year of captured CO2e.

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 22 Mtpy CO2e of potential capture and sequestration located within a 20 mile radius from various emissions points. In addition, the storage site has a large CO2 storage potential, estimated to be between 140 to 1,000 Mtpy CO2, subject to further evaluation, planning and development design decisions. Under the agreement, High West will dispose of CO2e waste from local third-party emissions sources through permanent sequestration via injection wells on the designated acreage.

Ethanol Projects

We have identified potential ethanol projects that we anticipate will achieve FID and commence initial sequestration operations at various points during 2027 through 2029. If approved and implemented, we anticipate that these projects would sequester third-party emissions, require a total capital investment by us of approximately $275 million by December 31, 2029, and subsequently achieve a combined forecasted annual sequestration volume of approximately 1.36 million metric tons of captured CO2e per year.

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, and have reached FID and entered into definitive agreements with respect to the Cotton Cove Project and the Eagle Ford Project, we have not reached FID with respect to or entered into the definitive agreements necessary to execute any of the other projects identified above. 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 up to 50% of these CCUS projects from a variety of external sources, which may include joint ventures, project-based equity partnerships and federal grants, with the remaining capital needs being funded with cash flows from operations. We are targeting completion of third-party CCUS financing in 2025; however, there can be no assurance that we will be able to complete any CCUS financing on our targeted timeline, or at all. Furthermore, 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.”

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, 2021. Our assessments did not address our GHG emissions from our other business operations. Our emissions estimates presented in this Form 10-K are based on information with respect to our owned and operated upstream and natural gas midstream businesses in the Barnett and NEPA through fiscal year 2023 and reported by BKV pursuant to the requirements of the federal Clean Air Act GHG reporting program regulations for petroleum and natural gas systems, Subpart C and Subpart W, as applicable. 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.

We estimate that our annual Scope 3 emissions from our owned and operated upstream and natural gas midstream businesses were approximately 18.7 Mtpy CO2e as of December 31, 2023. 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 using source Category 11 represent the majority of Scope 3 emissions from our owned and operated upstream and natural gas midstream operations, with minor contributions from other source categories. Additionally, our estimated Scope 3 emissions calculations assume that all natural gas produced is combusted and does not account for other potential end uses of natural gas. Scope 3 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. CO2e emissions are estimated using AR4 Global Warming Potentials, similar to those used by the EPA. Our annual Scope 3 CO2e emissions for the year ended December 31, 2023 were estimated at an approximated year-end net production volume of 942 MMcfe/d of natural gas (approximately 85% methane, 5% ethane and 10% other) and approximately 139.4 MBbls of NGLs (or approximately 2 MMcfe/d), as reported to the EPA for Subpart W. Our NGL constituents are estimated based on average constituent NGL barrel. Allocating the entire 944 MMcfe/d towards combustion as the end use, applying suitable combustion emission factors from the EPA, and using AR4 GWPs, Scope 3 annual emissions from our owned and operated upstream operations are estimated to be approximately 18.7 Mtpy CO2e. We currently engage third party consultants to develop and review our Scope 3 emissions estimates.

Pad of the Future. Our “Pad of the Future” program implements pad level design improvements to reduce pad level usage of natural gas, reduce GHG emissions and maintain operational continuity. As of December 31, 2024, we had implemented elements of our “Pad of the Future” program on approximately 11,300 pneumatic devices and 1,500 pneumatic pumps of our existing wells in the Barnett and we have successfully completed the program with our upstream owned and operated assets in NEPA.

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, which completed construction and began generating power in August 2024. The BKV-BPP Power Joint Venture has obtained permits for and constructed 2.5 MW and is evaluating the option 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 up to 32% of the Scope 2 emissions from our owned and operated upstream and natural gas midstream business as of December 31, 2023.

CCUS. Further, as discussed under “— Carbon Capture, Utilization, and Sequestration” above, we believe that the Barnett Zero Project, together with the Cotton Cove Project, the Eagle Ford 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 15.63 Mtpy CO2e by 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 CO2e 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 businesses and natural gas midstream by the early 2030s.

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 18.7 Mtpy CO2e annually as of December 31, 2023. Our CCUS business of capturing and sequestering our and third-party 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 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. However, 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 and have identified additional potential CCUS projects that we believe are commercially viable and estimate would have a combined forecasted annual volume of carbon capture and sequestration of approximately 15.6 Mtpy CO2e by the early 2030s, which represents a majority of our current Scope 1, 2, and 3 annual emissions from our owned and operated upstream and natural gas midstream businesses. In addition, we are currently evaluating more than ten early-stage project opportunities that are aligned with our high concentration strategy, but are not yet sufficiently evaluated, to determine potential sequestration volumes, geologic feasibility, or timeline of completion. We also evaluate later-stage opportunistic CCUS project acquisition opportunities. In the event a potential project has not progressed for any reason, including failure to FID, or additional funding provides for greater capacity to complete projects, we may further evaluate and develop one or more of these other project opportunities. 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 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.

(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.