BKV Corp (BKV) Risk Factors

ITEM 1A. RISK FACTORS

The following risk factors should be considered in evaluating our business and future prospects, in addition to other information included in this Annual Report on Form 10-K. Additional risk factors not presently known to us, or currently considered immaterial, may also have an adverse impact on our business, financial condition, and results of operations. If any of the events described below occur, our business, financial condition, or results from operations may suffer and the trading price of our common stock could be adversely affected.

Risks Related to Our Upstream Business and Industry

The volatility of natural gas and NGL prices due to factors beyond our control may materially and adversely affect our business, financial condition, or results of operations and our ability to make capital expenditures and meet our debt service obligations.

Our revenues, operating results, available cash, and the carrying value of our natural gas properties, as well as our ability to make capital expenditures (including amounts we expect to invest in connection with our efforts to develop potential CCUS projects) and meet our debt service obligations and other financial commitments, depend significantly upon the prevailing market prices for natural gas and NGLs. According to the U.S. Energy Information Administration (the “EIA”), the historical high and low Henry Hub natural gas spot prices per MMBtu for the following periods were as follows: in 2023, high of $3.78 and low of $1.74; in 2024, high of $13.20 and low of $1.21; and in 2025, high of $9.86 and low of $2.65.

Prices for natural gas and NGLs are subject to wide fluctuations in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors beyond our control. These factors include, but are not limited to:

• worldwide and regional economic conditions impacting the global supply of, and demand for, natural gas and NGLs, including inflation;

• the price, amount, timing and, quantity of foreign imports and exports of natural gas and NGLs;

• political conditions or conflicts in or affecting other producing regions or countries, including the Middle East, South America, Russia, Ukraine, and China;

• the ongoing military conflicts between Russia and Ukraine and in the Middle East, as well as the related actions of the United States and other governments and governmental organizations relating to oil, natural gas and NGLs, including through sanctions, embargoes, import restrictions and commodity price caps;

• the threat of terrorism and the impact of military action and civil unrest;

• the level of global drilling, exploration, and production;

• the level of global inventories;

• prevailing market prices on local price indexes in the areas in which we operate and expectations about future commodity prices;

• increased associated natural gas and NGL production resulting from higher oil prices and the related increase in oil production;

• the proximity of our natural gas and NGL production to, and capacity and cost of, natural gas and NGL pipelines and other transportation and storage facilities, and other factors that result in differentials to benchmark prices;

• local and global supply and demand fundamentals and transportation availability;

• United States storage levels of natural gas and NGLs;

• weather conditions and natural disasters, including floods, fires, tornadoes, droughts, hurricanes, tropical storms, and severe cold weather;

• domestic and foreign governmental regulations, including environmental initiatives and taxation;

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• tariffs, trade restrictions, and other supply chain constraints;

• overall domestic and global economic conditions;

• the value of the dollar relative to the currencies of other countries;

• stockholder activism or activities by non-governmental organizations to restrict the exploration, development, and production of natural gas, NGLs, and oil to minimize emissions of carbon dioxide, a GHG;

• the actions of OPEC and other oil producing countries, including Russia;

• speculative trading of, and other financial market conditions affecting natural gas and NGL derivative contracts;

• technological advances affecting energy consumption and energy supply;

• the price, availability, and acceptance of alternative energy sources; and

• the impact of energy conservation efforts.

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas price movements accurately. Changes in natural gas and NGL prices have a significant impact on the amount of natural gas and NGLs that we can produce economically, the value of our reserves, our cash flows, and our ability to satisfy obligations under our firm transportation and storage agreements. Historically, natural gas and NGL prices and markets have been volatile, and those prices and markets are likely to continue to be volatile in the future. For example, during the period from January 1, 2023 through December 31, 2025, the Henry Hub natural gas spot price reached a high of $13.20 per MMBtu on January 13, 2024 and a low of $1.21 per MMBtu on November 11, 2024. The average Henry Hub natural gas spot prices in 2023, 2024 and 2025 were$2.57 per MMBtu, $2.21 per MMBtu, and $3.52 per MMBtu, respectively, with 2024 being the lowest on record, adjusted for inflation. During the year ended December 31, 2025, there were record high production and less gas consumption, resulting in lower prices, but in the final months of 2025, natural gas prices rose due to weather impacts such as the polar vortex.

A substantial percentage of our natural gas and NGL production is gathered, processed, and transported by a single third party and all of our natural gas production is marketed by a single third party.

Approximately 99% of our natural gas and NGL production for the assets we acquired in the Devon Barnett Acquisition, which comprised approximately 64%, 62%, and 61%, for the years ended December 31, 2025, 2024, and 2023, respectively, of our total natural gas and NGL production was gathered, processed, and transported by ONEOK (formerly EnLink) using its gas gathering systems, gas transportation system, and gas processing facilities. Any termination or sustained disruption in the gathering, processing, and transportation of our natural gas and NGL production by ONEOK on its systems and in its facilities would materially and adversely affect our financial condition and results of operations.

We utilize an unaffiliated third party to market all of our natural gas production to various purchasers, which consist of credit-worthy counterparties, including utilities, LNG producers, industrial consumers, major corporations, and super majors in our industry. We rely on the creditworthiness of such third-party marketer, who collects directly from the purchasers and remits to us the total of all amounts collected on our behalf less their fee for making such sales. Our business, financial condition, and results of operations would be materially adversely affected if such third party fails to remit to us amounts collected by it on our behalf for such sales or, if in the future, it becomes necessary or advisable for us to replace our third-party marketer and we experience disruption in the marketing and sale of our natural gas production for so long as we are unable to find a replacement marketer.

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.

Numerous uncertainties are inherent in estimating quantities of natural gas, NGL, and oil reserves. The process of estimating natural gas, NGL, and oil reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering, and economic data for each reservoir, including assumptions regarding future natural gas, NGL, and oil prices, subsurface characterization, production levels and operating and development costs. For example, our estimates of our reserves at SEC pricing are based on the unweighted first-day-of-the-month arithmetic average commodity prices over the prior 12 months in accordance with SEC guidelines. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of those estimates. Sustained lower natural gas, NGL and oil prices will cause the 12-month unweighted arithmetic average of the first-of-the-day price for each of the 12 months preceding to decrease over time as the lower natural gas, NGL, and oil prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced. To the extent that natural gas, NGL, and oil prices become depressed or decline materially from current levels, such conditions could

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render uneconomic a portion of our proved natural gas, NGL, and oil reserves, and we may be required to write down our proved reserves.

Furthermore, SEC rules require that, subject to limited exceptions, PUD reserves may only be recorded if they relate to wells scheduled to be drilled within five years after the date of booking. This rule may limit our potential to record additional PUD reserves as we pursue our drilling program. To the extent that natural gas, NGL, and oil prices become depressed or decline materially from current levels, such condition could render uneconomic a number of our identified drilling locations, and we may be required to write down our PUD reserves if we do not drill those wells within the required five-year timeframe or choose not to develop those wells at all.

As a result, estimated quantities of natural gas, NGL, and oil reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to our reserves estimates. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas, NGLs, and oil attributable to any particular group of properties, the classifications of reserves based on risk of non-recovery and estimates of future net cash flows.

The present value of future net revenues from our proved natural gas, NGL, and oil reserves, or PV-10, will not necessarily be the same as the current market value of our estimated proved natural gas, NGL and oil reserves.

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated natural gas, NGL, and oil reserves. We currently base the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months. Actual future net revenues from our natural gas, NGL, and oil reserves will be affected by factors such as:

• actual prices we receive for natural gas, NGLs, and oil;

• actual cost of development and production expenditures;

• the amount and timing of actual production;

• transportation and processing; and

• changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of our natural gas, NGL, and oil properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas, NGL, and oil industry in general. Actual future prices and costs may differ materially from those used in the present value estimate.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

Recovery of PUD reserves requires significant capital expenditures and successful drilling operations. As of December 31, 2025, approximately 2,021.8 Bcfe, or 15.2%, of our total estimated proved reserves were undeveloped or behind pipe. The reserves data included in our reserves report assumes that substantial capital expenditures will be made to develop non-producing reserves. We cannot be sure that the estimated costs attributable to our natural gas, NGL and oil reserves are accurate. We may need to raise additional capital to develop our estimated PUD reserves over the next five years and we cannot be certain that additional financing will be available to us on acceptable terms or at all. Additionally, sustained or further declines in commodity prices may require us to revise the future net revenues of our estimated PUD reserves and may result in some projects becoming uneconomical. Further, our drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than current estimated reserves, which could have a material adverse effect on our financial condition, future cash flows, and results of operations.

As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures, as compared to the completion cost of a vertical well and therefore may result in fewer wells being completed in any given year. The incremental required capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

In general, the volume of production from natural gas, NGL, and oil properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. Except to the extent that we conduct successful

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exploration, exploitation, and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future natural gas and NGL production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves the pace of drilling and completion of new wells and our ability to secure necessary services and labor. Additionally, the business of exploring for, exploiting, developing, or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and NGL reserves would be impaired.

If natural gas and NGL prices become depressed for extended periods of time or decline materially from current levels, we may be required to record write-downs of the carrying value of our proved natural gas and NGL properties.

We follow the successful efforts method of accounting for natural gas producing activities. Impairment is indicated when a triggering event occurs and the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset’s carrying value. If undiscounted future cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in our results of operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. Triggering events could include, but are not limited to, an impairment of natural gas and NGL reserves caused by mechanical problems, faster-than-expected decline of reserves, lease-ownership issues, declines in commodity prices and changes in the utilization of midstream gathering and processing assets. If impairment is indicated, fair value is calculated using a discounted-cash flow approach and any excess of carrying value is expensed. Undeveloped natural gas and NGL properties are evaluated for impairment on a regular basis, based on the results of the exploratory activity and management’s evaluation. If the assessment indicates an impairment, an impairment loss is recognized. Future price decreases could result in reductions in the carrying value of our assets and an equivalent charge to earnings.

We periodically evaluate our unproved natural gas, NGL, and oil properties to determine recoverability of our costs and could be required to recognize non-cash charges in the earnings of future periods.

As of December 31, 2025, we carried unproved natural gas, NGL, and oil property costs of $13.2 million. GAAP requires periodic evaluation of unproved natural gas, NGL, and oil property costs on a project-by-project basis. These evaluations are affected by the results of exploration activities, commodity price outlooks, planned future sales, or expirations of all or a portion of these leases and the contracts and permits relevant to such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the costs invested in each project, we will recognize non-cash charges in future periods.

Properties that we have acquired or which we may acquire in the future may not produce as projected, and we may be unable to determine reserves potential, identify liabilities associated with such properties, or obtain protection from sellers against such liabilities.

Acquiring natural gas and NGL properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs, and potential liabilities, including environmental liabilities. Such assessments are inherently inexact and uncertain. For these reasons, the properties we have acquired, or will acquire in the future, may not produce as projected. Further, the annual decline rates of reserves are estimated decline rates, which could ultimately be materially different than actual annual decline rates. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. We perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline, or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Our failure to correctly assess reservoir and infrastructure characteristics of the natural gas and NGL properties that we acquire or have acquired, or to identify material defects or liabilities associated with such properties, or actual decline rates that differ materially from estimated decline rates, could have a material adverse effect on our financial condition, results of operations and cash flows.

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

Market conditions or the unavailability of natural gas and NGL processing, transportation, or storage arrangements may hinder our access to natural gas and NGL markets or delay or curtail our production. The availability of a ready market for our natural gas and NGL production depends on a number of factors, including the demand for and supply of

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natural gas and NGLs, the proximity of our natural gas and NGL production to and capacity of pipelines and storage facilities, gathering systems and other transportation, processing, fractionation, refining and export facilities, competition for such facilities, and the inability of such facilities to gather, transport, store, or process our natural gas and NGL production due to shutdowns or curtailments arising from mechanical, operational, or weather related matters, including hurricanes, floods, fires, tornadoes, droughts, hurricanes, tropical storms, and severe cold weather.

Our firm transportation and storage agreements require us to pay demand charges for firm transportation and storage capacities that we do not utilize. If we fail to utilize our firm transportation and storage capacities due to production shortfalls or otherwise, then our margins, results of operations, and financial performance could be adversely affected.

We enter into long-term firm transportation agreements, which provides us with a network of combined firm transportation capacity to East Coast, Gulf Coast, and Southeast markets as it relates to our upstream business units. Additionally, BKV-BPP Power has long-term firm transportation and storage agreements with Atmos and Energy Transfer and firm storage with Energy Transfer. We are obligated under these arrangements to pay a demand charge for firm transportation and storage capacity rights on most of these pipeline and storage systems regardless of the amount of pipeline or storage capacity we utilize, subject to our right to release all or a portion of our firm transportation or storage capacities to other shippers and reduce our exposure to demand charges.

If our anticipated production does not exceed the minimum quantities provided in the agreements, and we are unable to purchase natural gas and NGLs from third parties or release our capacity to other shippers, then our margins, results of operations, and financial performance could be adversely affected.

Drilling for natural gas wells is a high-risk activity with many uncertainties that could adversely affect our business, financial condition or results of operations.

Drilling natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive natural gas and NGL reserves (including “dry holes”). We must incur significant expenditures to drill and complete wells, the costs of which are often uncertain. It is possible that we will make substantial expenditures on drilling and not discover reserves in commercially viable quantities.

Specifically, we often are uncertain as to the future cost or timing of drilling, completing, and well operations, and our drilling operations and those of our third-party operators may be curtailed, delayed, or canceled. The cost of our drilling, completing, and well operations may increase and our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:

• general economic and industry conditions;

• unexpected drilling conditions;

• potential drainage of natural gas from our properties by operations on adjacent properties;

• title problems;

• pressure or irregularities in formations;

• equipment failures or accidents;

• adverse weather conditions, such as floods, fires, tornadoes, droughts, hurricanes, tropical storms and severe cold weather, and changes in weather patterns;

• compliance with, or changes in, environmental laws and regulations relating to air emissions, hydraulic fracturing and disposal of produced water, drilling fluids and other wastes, laws and regulations imposing conditions and restrictions on drilling and completion operations, and other laws and regulations, such as tax laws and regulations;

• the availability and timely issuance of required governmental permits and licenses; and

• the availability of costs associated with, and terms of contractual arrangements for, properties, including mineral licenses and leases, pipelines, facilities, and equipment to gather, process, compress, store, transport, and market natural gas, NGLs, and related commodities.

For instance, in our drilling operations across NEPA and the Barnett from time to time we experience certain issues and the occurrence of risks, including, for example, mechanical and instrument or tool failures, drilling difficulties associated with drilling in swelling clay or shales and unconsolidated formation, particularly in certain parts of our Barnett development acreage, wellbore instability and other geological hazards, loss of well control, loss of drilling fluids, inability to establish fluid circulation, loss of drill pipe, loss of casing integrity, stuck tools and drill pipes, insufficient cementing of casing, among other typical shale drilling challenges.

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Our failure to recover our investment in wells, increases in the costs of our drilling operations, or those of our third-party operators, and/or curtailments, delays or cancellations of our drilling operations, or those of our third-party operators in each case due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations.

Drilling, completions, workover, and hydraulic fracturing operations are operationally complex activities which present certain risks that could adversely affect our business, financial condition, or results of operations.

We may experience certain issues and encounter risks in our drilling operations, including:

•mechanical and instrument or tool failures;

•drilling difficulties associated with drilling in swelling clay or shales and unconsolidated formation, particularly in select parts of our Barnett development acreage;

•wellbore instability and other geological hazards;

•loss of well control and associated hydrocarbon release and/or natural gas clouds;

•loss of drilling fluids circulation; surface spills of various drilling, or well fluids;

•subsurface collision with existing wells;

•proximity of adjacent water wells or aquifers;

•inability to establish drilling fluid circulation;

•loss or compromise of drill pipe or casing integrity;

•surface pumping operations and associated pressure and hydrocarbon hazards;

•stuck and lost-in-hole tools, drill pipe, or casing;

•large drilling equipment and machinery, including electrical hazards;

•insufficient cementing of casing causing unwanted casing pressure or fluid migration;

•surface overpressure events from large machinery (horsepower), equipment, or well pressure;

•fines and violations related to relevant laws and regulations;

•fires and explosions;

•personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation, and trenching;

•structural damage and collapse to large equipment and machinery;

•major damage or malfunction to key equipment or processes;

•in certain instances, close proximity of operations to residences and/or communities; and

•other typical shale basin drilling challenges and risks.

We experience certain issues and encounter risks in our hydraulic fracturing, workover, and completions activities, including:

•mechanical and instrument or tool failures;

•loss of well control and associated hydrocarbon release and/or natural gas clouds;

•well kick or flowback during completion or fracturing operations;

•lost or stuck in hole wireline, coiled tubing, or workover strings and tools;

•loss or compromise of workover string, tubing, or casing integrity;

•large completions, wireline, coiled tubing, and workover rig equipment and machinery, including electrical hazards;

•insufficient cementing of casing causing unwanted casing pressure or fluid migration while fracturing or thereafter;

•proximity of adjacent water wells or aquifers and adjacent producing wells;

•surface spills of various fracturing, freshwater, or well fluids or chemicals;

•surface pumping and flowback operations and associated pressure and hydrocarbon hazards;

•surface overpressure events from large machinery (horsepower), equipment, or well pressure;

•fines and violations related to relevant laws and regulations;

•fires and explosions;

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•personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation, and trenching;

•structural damage and collapse to large equipment and machinery;

•major damage or malfunction to key equipment or processes;

•in certain instances, close proximity of operations to residences and/or communities; and

•other typical fracturing, workover, and completion challenges and risks.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease or other interest in a specific mineral interest. The existence of a material title deficiency can render a lease or other interest worthless and can adversely affect our results of operations and financial condition. The failure of title on a lease, in a unit or any other mineral interest may, not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of factors, including commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling conditions, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals, urban growth, and other factors. If commodity prices become depressed or decline materially from current levels, the number of locations would decrease as increasing numbers of locations would become uneconomic, and any such decrease may be significant. Even to the extent any locations remain capable of economic production, we may determine not to drill such locations until commodity prices recover. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce natural gas and NGLs from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acreage on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.

Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involves risks and uncertainties in their application.

To the extent we target emerging areas, the results of our horizontal drilling efforts in such areas will generally be more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which may be subject to well spacing, density and proration requirements, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, access to gathering systems, takeaway capacity constraints or otherwise, availability of drilling surface acreage, or commodity prices decline, our investment in these areas may not be as economic as we anticipate, and we could incur material write-downs of unevaluated properties, which may cause the value of our undeveloped acreage to decline in the future.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations, and cash flows.

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local landowners and other sources for use in our operations. Some areas in which we have operations have experienced or may in the future experience drought conditions that could result in restrictions on water availability or use. Such drought conditions and water stress may become more frequent or intense as a result of climate change. If we are unable to obtain water to use in our operations from local sources or are unable to transport and store

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such water, we may be unable to economically produce natural gas and NGLs in the affected areas, which could have an adverse effect on our financial condition, results of operations, and cash flows.

The unavailability or high cost of equipment, supplies, personnel, and oilfield services could adversely affect our ability to execute our development and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.

We utilize third-party services to maximize the efficiency of our operations. The cost of oilfield services typically fluctuates based on demand for those services. While we currently have excellent relationships with oilfield service companies, there is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages, quality, or the high cost of equipment, supplies or personnel could delay or adversely affect our development and exploitation operations, which could have a material adverse effect on our business, financial condition, or results of operations. Further, supply chain disruptions, tariffs and trade restrictions and other inflationary pressures affecting the United States and global economy and the oil and gas industry may limit our ability to procure the necessary products and services for drilling and completing wells in a timely and cost effective manner, which could result in reduced margins and delays in our drilling and completion activities which, in turn, could adversely affect our business, financial condition, or results of operations.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

As of December 31, 2025, we operated approximately 97% of our net (81% of our gross) acreage. With respect to our natural gas midstream business, we do not operate the NEPA midstream entities, and in the Barnett, during the year ended December 31, 2025, approximately 80% of our gross operated production volumes were gathered and processed by a third party. If we do not operate or otherwise control the properties and midstream facilities in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of wells in which we own a non-operating interest or an operator of midstream facilities in which we have an interest to adequately perform operations, an operator’s financial difficulties, including as a result of price volatility or an operator’s breach of the applicable agreements, could reduce our production and revenues. The success and timing of the drilling and development activities on properties operated by third parties, as well as the midstream operations involving our assets depend upon a number of factors outside of our control. These factors include the operator’s schedule and level of capital investment, expertise, financial resources, collaboration with other participants in drilling wells, and the use of technology.

Even though the Bedrock Acquisition is completed, we may be unable to successfully integrate the assets held by BKV Barnett II into our business or achieve the anticipated benefits of the Bedrock Acquisition.

The success of the Bedrock Acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from integrating the assets and operations of Bedrock into our business, and there can be no assurance that we will be able to successfully integrate or otherwise realize the anticipated benefits of the Bedrock Acquisition. Difficulties in integrating Bedrock into our company and our ability to manage the combined company may result in us performing differently than expected, in operational challenges or in the delay or failure to realize anticipated expense-related efficiencies and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Potential difficulties that may be encountered in the integration process include, among others:

•the inability to successfully integrate Bedrock operationally, in a manner that permits us to achieve the full revenue, expected cash flows and cost savings anticipated from the Bedrock Acquisition;

•not realizing anticipated operating synergies; and

•potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the Bedrock Acquisition.

Risks Related to Our Power Generation Business

We incurred significant costs in connection with the BKV-BPP Power Joint Venture Transaction.

We incurred significant costs associated with the BKV-BPP Power Joint Venture Transaction. Our fees and expenses related to the BKV-BPP Power Joint Venture Transaction include financial advisor fees, filing fees, taxes and legal and accounting fees. Following the closing, we expect to consolidate our financial statements with those of the BKV-BPP Power Joint Venture. In addition, we expect that with our increased ownership of the BKV-BPP Power Joint Venture, certain expenses related to operating the BKV-BPP Power Joint Venture will increase. It is difficult to predict the total amount of costs related to the BKV-BPP Power Joint Venture Transaction and the increased ownership of the BKV-BPP Power Joint Venture following the closing. Such costs may be significant and could have an adverse effect on our future results of operations, cash flows and financial condition.

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We operate our power generation business through a joint venture that requires the consent of BPPUS for certain material actions.

As of December 31, 2025, we and BPPUS each had a 50% interest in the BKV-BPP Power Joint Venture. For the years ended December 31, 2025, 2024, and 2023, the portion of BKV's earnings in the BKV-BPP Power Joint Venture were $14.9 million, $10.4 million, and $16.9 million, respectively, and our interest in the earnings on the BKV-BPP Power Joint Venture represented approximately 1.5%, 1.8%, and 1.7% of our revenues, which includes derivative gains (losses), net, respectively.

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. In accordance with the terms of the Amended and Restated Limited Liability Company Agreement of the BKV-BPP Power Joint Venture (the “BKV-BPP Power LLC Agreement”), which we entered into with BPPUS at the closing of the BKV-BPP Power Joint Venture Transaction, the BKV-BPP Power Joint Venture is managed by a board of managers (the “BKV-BPP Power Board”), which consists of twelve members, nine of whom are appointed by us and three of whom are appointed by BPPUS. Of the nine members who are appointed by us, one or more may be a director of Banpu.

As of January 30, 2026, the BKV-BPP Power LLC Agreement provides that we are delegated the authority and responsibility for the day-to-day operation of the business affairs of BKV-BPP Power. However, for as long as BPPUS maintains an ownership interest in the BKV-BPP Power Joint Venture of at least 10%, consent from at least one member of the BKV-BPP Power Board appointed by BPPUS is required for, and we are not entitled to unilaterally cause the BKV-BPP Power Joint Venture to take, certain specified actions, such as: (i) any sale of the BKV-BPP Power Joint Venture or certain significant subsidiaries, or transfer of substantially all assets, merger, consolidation, amalgamation or similar business combination of the BKV-BPP Power Joint Venture, subject to certain exceptions; (ii) any winding up, dissolution or liquidation or any commencement of or any filing or petition for a voluntary bankruptcy or reorganization; (iii) any amendment, restatement, or revocation of organizational documents, subject to certain exceptions; (iv) any material change in the nature of the business or purpose of the BKV-BPP Power Joint Venture; (v) entry into certain related party transactions; (vi) the issuance, sale, repurchase, or redemption of any of the equity interests of the BKV-BPP Power Joint Venture; (vii) the admission of any new member to the BKV-BPP Power Joint Venture, subject to certain exceptions; (viii) the early termination without the BKV-BPP Power Board approval of, or the execution or material amendment of, any material contract, subject to certain exceptions; (ix) the incurrence of certain indebtedness beyond certain thresholds; and (x) the making of certain capital calls.

We face certain risks associated with shared control of the BKV-BPP Power Joint Venture, and BPPUS may at any time have economic, business, or legal interests or goals that are inconsistent with ours.

Operation of electric generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

The ongoing operation of the Temple Plants involves risks that include performance below expected levels of output or efficiency, as well as the unavailability of key equipment or breakdown or failure of equipment or processes (including an inability to obtain key equipment from Siemens natural gas generators and steam turbines and Benson heat recovery steam generators, which are used by the Temple Plants), due to wear and tear, latent defect, design error or operator error, or force majeure events, among other things. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the business. Unplanned outages typically increase operation and maintenance expenses and capital expenditures and may reduce revenue available to be distributed to BPPUS and us as a result of selling fewer megawatt hours or require us to incur significant costs as a result of obtaining replacement power from third parties in the open market to satisfy forward power sales obligations. Our inability to operate the BKV-BPP Power electric generation assets efficiently, manage capital expenditures and costs, and generate distributions from the Temple Plants could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Maintenance, expansion and refurbishment of electric generation facilities involve significant risks that could result in unplanned power outages or reduced output.

The Temple Plants may require periodic upgrading and improvement. Any unexpected operational or mechanical failure, including failure associated with breakdowns and forced outages, could reduce the Temple Plant’s generating capacity below expected levels, reducing potential cash distributions to BPPUS and us. Unanticipated capital expenditures associated with maintaining, upgrading, or repairing the Temple Plants may also reduce profitability.

If we make any major modifications to Temple I or Temple II, we may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under and determined pursuant to the new source review provisions of the CAA at the time of such modifications. Any such modifications could likely result

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in substantial additional capital expenditures. We may also choose to repower, refurbish, or upgrade these facilities based on our assessment that such activity will provide adequate financial returns. The modifications to these facilities require time for development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices. These events could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, and cash flows.

The Temple Plants may operate, wholly or partially, without long-term power sales agreements.

The Temple Plants may operate without long-term power sales agreements for some or all of their generating capacity and output and therefore be exposed to market fluctuations. Without the benefit of long-term power sales agreements for the facility, we cannot be sure that the BKV-BPP Power Joint Venture will be able to sell any or all of the power generated by the facility at commercially attractive rates or that either facility will be able to operate profitably. This could lead to less predictable revenues, future impairments of either facility’s property, plant and equipment or the closing of the facility, resulting in economic losses and liabilities, which could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations and cash flows.

We do not currently supply our own natural gas directly to the Temple Plants or their firm natural gas storage service at the Bammel storage facility. We cannot ensure that we will be successful in the future in obtaining the commercial contracts necessary to facilitate direct delivery of our natural gas production to the Temple Plants on commercially reasonable terms or at all.

We cannot ensure that we will succeed in any effort to establish midstream contracts that would allow us to supply our own natural gas directly to Temple I, Temple II, or their firm natural gas storage service at the Bammel storage facility. Although the physical infrastructure exists to supply our own natural gas directly to the Temple Plants and the Bammel storage facility, our ability to utilize that infrastructure depends on whether we can successfully negotiate and enter into new midstream contracts on satisfactory terms or at all. If we fail to enter into such contracts on satisfactory terms or at all, we may be unable to achieve the synergistic cost savings we anticipated in connection with the BKV-BPP Power Joint Venture, which could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, and cash flows.

BKV-BPP Power may enter into financially settled HRCOs that may expose it to basis and buyback risk in its operations.

To reduce its exposure to fluctuations in the market price of electricity and natural gas, BKV-BPP Power may enter into financially settled HRCOs, which are contracts 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. BKV-BPP Power is exposed to basis risk in its operations when its derivative contracts settle financially, and it delivers physical electricity on different terms. For example, if BKV-BPP Power enters into an HRCO, it hedges its electricity production based on an agreed price for that electricity, but physical electricity must be delivered to delivery points in the market it serves. BKV-BPP Power is exposed to basis risk between the hub price specified in the HRCO and the price that it receives for the sales of physical electricity. BKV-BPP Power attempts to hedge basis risk where possible, but hedging instruments may not be economically feasible or available in the quantities that it requires. BKV-BPP Power’s hedging activities do not provide it with protection for all of its basis risk and could result in economic losses and liabilities, which could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, and cash flows.

Additionally, by using derivative instruments to economically hedge exposure to changes in power prices, we could limit the benefit we would receive from increases in power prices, which could have an adverse effect on our financial condition. For example, as of December 31, 2025, BKV-BPP Power had unrealized losses of $19.6 million on its derivative instruments as a result of increased power prices; of the $19.6 million, $13.3 million of these losses pertain to four open HRCOs. In the event BKV-BPP Power enters into an HRCO and is not able to satisfy its obligations, it must purchase power at prevailing market price to satisfy the HRCO. Likewise, increases in power pricing could limit the benefit we receive under HRCOs and may result in losses. Either such event could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, and cash flows.

Our costs, results of operations, financial condition, and cash flows could be adversely impacted by the disruption of the fuel supplies necessary to generate power at Temple I or Temple II, whether as a result of failure of contractual counterparties, disruption in fuel delivery infrastructure, or otherwise.

Delivery of natural gas to fuel the Temple Plants is dependent upon the infrastructure (including natural gas pipelines) available to serve such generation facilities as well as upon the continuing financial viability of contractual counterparties. As a result, the BKV-BPP Power Joint Venture is subject to the risks of disruptions or curtailments in the production of

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power at the Temple Plants if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure. Any such disruptions or curtailments could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, and cash flows.

Risks Related to Our Retail Power Business

We operate our retail power business through a joint venture which we share control.

Our retail energy business is operated through BKV-BPP Retail, a wholly-owned subsidiary of the BKV-BPP Power Joint Venture. As of December 31, 2025, we and BPPUS each owned 50% of the BKV-BPP Power Joint Venture. 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.

We face certain risks associated with shared control and BPPUS may, at any time, have economic, business, or legal interests or goals that are inconsistent with ours. For additional information, see “— Risks Related to Our Power Generation Business — We operate our power generation business through a joint venture that requires the consent of BPPUS for certain material actions.”

Our retail power business operates in a highly competitive environment, which may make it difficult to grow without reducing prices or incurring additional costs.

Our retail business faces substantial competition from other retail electric providers. As a result, we may be forced to reduce prices or incur increased acquisition costs in order to attract and maintain customers. Present and future competitors may have greater name recognition, long-standing customer and broker relationships, greater-financial strength, or other resources that could put us at a disadvantage.

Our retail power business is subject to market price risk.

Our retail business is required to purchase sufficient energy and ancillary services at wholesale to serve its retail customers. Although wholesale prices fluctuate based on market conditions, our retail business has contracted to provide 100% of our customers with fixed power prices. As a result, BKV-BPP Retail is exposed to fluctuations in wholesale energy and ancillary service prices. BKV-BPP Retail seeks to hedge this exposure whenever possible, but hedging instruments may not be economically feasible or available in the required quantities. Additionally, certain components of energy prices cannot be hedged, and there is risk that hedge providers may fail to fulfill their obligations. BKV-BPP Retail’s hedging activities do not prevent it from exposure to risk, primarily price fluctuations, including those caused by transmission congestion or extreme weather, which may result in economic losses and liabilities, which could have a material adverse effect on BKV-BPP Retail.

Our retail power business is vulnerable to changes in law, regulation, or market structure resulting in unanticipated costs that cannot be passed through to customers.

Our retail business operates in a highly regulated environment. It is directly regulated by both the PUCT and ERCOT. Changes in regulation could create increased costs that BKV-BPP Retail might be unable to pass through to customers, particularly those on fixed-priced contracts. For example, ERCOT introduced a new ancillary service product — ERCOT Reserve Contingency Service (“ECRS”) — in June 2023. Although ERCOT began assessing ECRS charges to BKV-BPP Retail, the PUCT prevented retail suppliers such as BKV-BPP Retail from passing these costs onto existing customers on fixed price contracts. Future changes in law or regulation resulting in increased costs could impact our retail business.

Our retail business, including our relationship with our supplier, is dependent on access to capital and liquidity.

Our business involves entering into contracts to purchase large quantities of electricity. Because of seasonal fluctuations, we often have to purchase electricity and hedges for future periods and finance the purchases upfront until we can recover such amounts from our customers. We also rely on an energy supplier to facilitate our energy and hedge our purchases. If we are unable to renew this agreement or if our energy supplier's credit rating declines, our ability to economically purchase energy and hedges could be impacted. Further, any challenges in securing credit or liquidity on commercially reasonable terms could adversely impact our retail business.

Our retail business depends on our ability to attract and retain personnel with retail market experience.

Our success depends on the expertise of key members of our management team whose loss could disrupt our business operations. Additionally, the PUCT requires us to have one or more officers or managers with at least 15 years of combined experience in the competitive energy industry. Losing certain key personnel could impact our ability to continue operating a retail electric business and jeopardize our retail electric provider (“REP”) certificate.

Our retail business depends on maintaining regulated permits and any loss of these permits would adversely affect our business.

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Our business requires a REP certificate from the PUCT and a load serving entity (“LSE”) registration and qualified scheduling entity (“QSE”) registration with ERCOT. Both the PUCT and ERCOT impose various requirements to maintain these permits. Any negative publicity regarding the retail industry in general could result in agencies or the state legislature imposing additional regulations on the retail business and increasing our compliance obligations. Additionally, customer complaints and compliance violations could damage our relationship with the PUCT and potentially jeopardize our REP certificate. Losing our REP certificate, LSE registration, or QSE registration would prevent us from continuing to operate in the retail business.

Risks Related to Our CCUS Business

Our ability to establish and operate large scale CCUS projects is subject to numerous risks and uncertainties. We may be unsuccessful in developing our CCUS business as currently anticipated, either wholly or in significant measure.

A key element of our business strategy includes the development of a CCUS business. We have limited experience in the development and operation of a CCUS business, which poses different challenges and risks than our existing upstream and natural gas midstream businesses. We may be unable to execute on our business plans, demand for these new services may not develop on a large or economic scale, or we may fail to operate our CCUS business effectively. Our CCUS business may also present novel issues in law, taxation, emission offset accounting and accreditation, safety or environmental policy, subsurface storage, supply chain, project design, and other areas that we may not be able to manage effectively or that could change considerably. Management’s assessment of the risks in this line of business may be inexact and not identify or resolve all the problems that we may face. If we are unsuccessful in timely developing a commercially successful CCUS business, our future growth and results of operations may be materially and adversely affected, and we may be unable to realize much of our current business plans, including timely reaching our goal of net zero Scope 1, 2, and 3 emissions across our owned and operated upstream businesses, either by the dates projected or at all.

Due to the early stage nature of CCUS projects and the sector generally, CCUS projects face considerable risks. In particular, the Barnett Zero Project, the Eagle Ford Project, the Cotton Cove Project, and the East Texas Project face, and any of our potential future CCUS projects, including the pipeline of CCUS projects currently under evaluation, will face operational, technological, regulatory, and financial risks. These risks include the possibility that CIP, ONEOK, BPPUS, or any of our other future counterparties to a CCUS project, may not meet their financial or performance obligations related to the CCUS project. Moreover, the economics of our operational and potential CCUS projects depend on financial and tax incentives, including Section 45Q tax credits. If we are unable to obtain the Section 45Q tax credits included in our financial assumptions for any reason, including as a result of any change in policy changes, government spending measures, or U.S. presidential executive actions, any of our proposed CCUS projects may no longer be commercially viable and may not be completed.

Although we have identified potential CCUS projects in addition to the Barnett Zero Project, the Eagle Ford Project, Cotton Cove Project, and the East Texas Project, these additional potential projects are in different stages of the evaluation process. In most cases, emitters have required extended periods of time to evaluate potential projects and participate in negotiations. We have not entered into the definitive agreements necessary to execute any of the other potential projects we have identified and, as such, we cannot guarantee that any of those potential projects will reach FID or be completed. Additionally, we cannot ensure we will be able to source and identify additional emitters willing to enter into CCUS project agreements with us. 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. Our stated goals of timely achieving net zero Scope 1, 2, and 3 emissions from our owned and operated upstream businesses are dependent, in part, on being able to commercially develop our existing pipeline of CCUS projects.

Further, our ability to successfully operate the Barnett Zero Project with ONEOK, or successfully develop the Eagle Ford Project and the Cotton Cove Project with BPPUS, and the East Texas Project, or any future potential CCUS projects, depends on a number of factors that we are not able to fully control, including the following:

• Commercial scale carbon capture is an emerging sector, and there are no substantial precedents to gauge the likely range of structures or economic terms that will be necessary to reach agreeable terms.

• CCUS injection wells are currently subject to overlapping state and federal jurisdiction and new and evolving regulatory frameworks. The timetable for issuance of permits and authorizations required for a CCUS project is uncertain and could entail a multi-year process. The issuance of permits may be subject to regulatory delays and third-party challenges. We cannot guarantee that we will be able to obtain necessary permits on a timely basis, on favorable terms, or at all.

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• As CCUS and carbon management represent an emerging sector, regulations may evolve rapidly, which could impact the feasibility of one or more of our anticipated projects. To the extent regulatory requirements are amended or more stringently enforced, or new regulatory requirements are added, we may incur additional delays and/or costs in the pursuit of one or more of our carbon capture projects, which costs may be material or may render any one or more of our projects uneconomical.

• We may not own the pore space at all of our CCUS project sites, which may require us to enter into agreements with multiple owners to secure the necessary real estate rights needed for the entire geologic formation. The failure to obtain necessary pore space rights from all owners, in the absence of a state law mechanism for eminent domain or forced amalgamation, could have a material adverse effect on any proposed CCUS project.

• Robust monitoring, recordkeeping, and reporting required in connection with CCUS projects may increase the costs of such operations. Different methodologies may be required to satisfy various regulatory and non-regulatory requirements regarding GHG emissions/sequestration at one or more of our projects, including, but not limited to, compliance with any greenhouse gas reporting requirements.

• CCUS injection wells and carbon sequestration reservoirs or formations may experience integrity, operating, or boundary breaches resulting in additional costs, liability and risk from undesired well casing pressures, breakthrough of injected CO2 to the land surface, CO2 plume migration outside of expected or modeled results into undesired or unwanted surface or subsurface areas, well integrity issues, or various other outcomes.

• Carbon capture may be viewed as a pathway to the continued use of fossil fuels, notwithstanding that CO2 emissions are intended to be captured. There may be organized opposition to carbon capture, including our projects, alleging concerns relating to the environment, environmental justice, health or safety, or the federal and/or state governments may cease supporting carbon capture and sequestration.

• In addition to the BKV-CIP Joint Venture and the BKV-BPP Cotton Cove Joint Venture, the development of a CCUS project may require us to enter into long-term joint ventures with large carbon emitters (which may need to finance and build, often over a multi-year period, the equipment to capture CO2 emissions from various industrial processes) and operators of infrastructure for transporting CO2 (or other GHGs), and we may not be able to do so on agreeable terms, or at all.

The development of our CCUS business is expected to require material capital investments.

Our CCUS projects are expected to have material capital requirements, and 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, debt financing, and federal grants, with the remaining capital needs being funded with cash flows from operations. We anticipate that some of these project costs will be borne by third-party investors in these projects, including emitters, landowners and other stakeholders. However, there is no certainty that we will be able to obtain external funding on a timeline sufficient to achieve our goals, on commercially reasonable terms or at all. Our access to external funding depends on a number of factors, including general market conditions, potential investors’ confidence in our CCUS program, business model, growth potential, and our current and expected future earnings as well as the liquidity needs of the external funding sources themselves. We may face intense competition from a variety of other companies and financing structures for such limited investment capital. If we are unable to obtain a sufficient level of external funding for our CCUS projects, we may be required to abandon or materially delay certain projects, which in turn could negatively impact our ability to realize our business plan or to reach our near-term and long-term net zero goals on our anticipated time frame or at all. We similarly may not be able to reach our positive net income goals for our CCUS business on the timeline we have predicted, which may likewise adversely impact our business or financial condition. CCUS activities subject us to the financial risks of rising costs of equipment and capital, possible delays in acquiring them, along with the financial impact of our expending capital on these activities in advance of realizing any CCUS cash flows, any of which could negatively impact our financial condition and operational results in future periods.

To the extent CO2 transportation pipelines are not already present in proposed project areas, or if they do not extend to one or more of our project sites, we may be required to convert existing non-CO2 pipelines, or build new CO2 pipelines or lateral connections, which will require more time before we can bring together captured CO2 emissions and transport them to appropriately tested and prepared sequestration sites, require much larger capital expenditures and may be subject to various environmental and other permitting requirements and authorizations as well as third-party easements that could be difficult or costly to obtain, which may render one or more projects uneconomical or impractical. The availability of eminent domain for carbon capture pipelines varies by state and can be highly controversial; there may be organized opposition to eminent domain for carbon capture pipelines, including those associated with our projects, from environmental or landowner groups. Additionally, even in areas where such pipelines are in place, our use of them may require reaching agreements on CO2 transportation with operators of the pipelines.

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Additionally, the development of CCUS projects through our current or potential future joint ventures involves risks not present in investments in which a third party is not involved, including the possibility that:

• we and a co-venturer or partner may reach an impasse on a major decision that requires the approval of both parties;

• we may not have exclusive control over the development, financing, management, and other aspects of the joint venture, which may prevent us from taking actions that are in our best interest but opposed by a co-venturer or partner;

• a co-venturer or partner may encounter liquidity or insolvency issues or may become bankrupt, which may mean that we and any other remaining co-venturers or partners generally would remain liable for the joint venture’s liabilities;

• a co-venturer or partner may at any time have economic or business interests or goals that are or may become inconsistent with ours;

• a co-venturer or partner may be in a position to take action contrary to our instructions, requests, policies, or investment objectives, including our current policy with respect to maintaining our qualification for enhanced Section 45Q tax credits under the Code;

• a co-venturer or partner may take actions that subject us to liabilities in excess of, or other than, those contemplated;

• in certain circumstances, we may be liable for actions of our co-venturer or partner;

• our joint venture agreements may restrict the transfer of a co-venturer’s or partner’s interest or otherwise restrict our ability to sell the interest when we desire or on advantageous terms;

• our joint venture agreements may contain buy-sell provisions pursuant to which one co-venturer or partner may initiate procedures requiring the other co-venturer or partner to choose between buying the other co-venturer’s or partner’s interest or selling its interest to that co-venturer or partner;

• if a joint venture agreement is terminated or dissolved, we may not continue to own or operate the interests or investments underlying the joint venture relationship or may need to purchase such interests or investments at a premium to the market price to continue ownership; or

• disputes between us and a co-venturer or partner may result in litigation or arbitration that could increase our expenses and prevent our management from focusing their time and attention on our business.

Any of the above could materially and adversely affect our ability to execute on our CCUS strategy, the value of any CCUS project we develop through a current or potential future joint venture, and our ability to reach our near-term and long-term net zero goals on our anticipated time frame or at all, as well as on our liquidity, financial condition, and results of operations.

We operate the Barnett Zero Project through a joint venture that requires the consent of CIP for certain material actions.

The BKV-CIP Joint Venture is owned 51% by BKV dCarbon Ventures and 49% by CIP and was formed on May 8, 2025 for the purpose of developing CCUS projects. In accordance with the terms of the Limited Liability Company Agreement of BKV dCarbon Project (the “BKV-CIP LLC Agreement”), the BKV-CIP Joint Venture is governed by a board of managers (the “BKV-CIP Board”) consisting of five members, three of whom are designated by dCarbon Ventures and two of whom are designated by CIP. Most operational decisions and activities of the BKV-CIP Joint Venture are reserved for approval by a majority of the members of the BKV-CIP Board, but CIP has customary minority investor rights, including veto rights with respect to, among other things, (i) the amount and timing of distributions to the members of BKV dCarbon Project, (ii) BKV dCarbon Project’s annual budget, (iii) any sale or initial public offering of BKV dCarbon Project, (iv) any change in senior management of the BKV dCarbon Project, and (v) other significant and related party transactions entered into by the joint venture. Other than quarterly tax distributions and distributions in respect of a deemed liquidation event (as defined in the BKV-CIP LLC Agreement), distributions will be made in accordance with a waterfall until specified minimum return targets are achieved by CIP.

We have agreed that BKV and its affiliates will develop CCUS projects exclusively through the BKV-CIP Joint Venture except that any CCUS projects that are rejected by CIP for development by the BKV-CIP Joint Venture may be developed solely through dCarbon Ventures outside of the BKV-CIP Joint Venture. In addition, 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, which may negatively impact our net-zero strategy, including by delaying or preventing our achievement of net zero. As of December 31, 2025, dCarbon Ventures has contributed the BKV dCarbon Barnett Zero, LLC and BKV dCarbon Las Tiendas, LLC and related assets (including

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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 to the BKV-CIP Joint Venture.

We face certain risks associated with shared control, and BPPUS may at any time have economic, business, or legal interests or goals that are inconsistent with ours.

We operate the Cotton Cove Project through a joint venture that requires the consent of BPPUS for certain material actions.

The BKV-BPP Cotton Cove Joint Venture is owned 51% by BKV dCarbon Ventures and 49% by BPPUS and was formed on August 25, 2023 to own the Cotton Cove Project. In accordance with the terms of the Limited Liability Company Agreement of BKV-BPP Cotton Cove (the “BKV-BPP Cotton Cove LLC Agreement”), the BKV-BPP Cotton Cove Joint Venture is managed by a board of managers (the “Cotton Cove JV Board”) consisting of six members, four of whom are appointed by BKV dCarbon Ventures and two of whom are appointed by BPPUS. Of the four members appointed by BKV dCarbon Ventures, none are employees of Banpu who also serve on our board of directors. Additionally, certain material actions require the unanimous consent of the Cotton Cove JV Board and consequently, BKV-BPP Cotton Cove may not take certain material actions without the consent of BPPUS, such as (i) making certain elections available to BKV-BPP Cotton Cove with respect to the monetization of Section 45Q credits; (ii) approving certain final investment decisions related to the Cotton Cove Project; (iii) directing transfers of BKV-BPP Cotton Cove membership interests to unaffiliated third parties; (iv) entering into any merger, consolidation, amalgamation, conversion of BKV-BPP Cotton Cove or any of its subsidiaries, into another form or entity, or any other business combination of any nature; (v) causing the wind up, dissolution, liquidation, commencement, or any filing or petition for a voluntary bankruptcy, reorganization, debt arrangement involving BKV-BPP Cotton Cove; (vi) authorizing any amendment, restatement or revocation of the organizational documents of BKV-BPP Cotton Cove or its subsidiaries; (vii) authorizing increases or decrease of the required capital contributions; (viii) determining the location of the wells associated with the Cotton Cove Project; (ix) making decisions related to a possible initial public offering of BKV-BPP Cotton Cove; or (x) causing BKV-BPP Cotton Cove to make distributions.

We face certain risks associated with shared control, and BPPUS may at any time have economic, business, or legal interests or goals that are inconsistent with ours.

The commercial viability of our CCUS projects depends, in part, on certain financial and tax incentives provided by the U.S. federal government.

The economics of CCUS projects depend on financial and tax incentives that could be changed or terminated and that may not currently be sufficient for our CCUS projects to be economical. In addition, our qualification for enhanced Section 45Q tax credits is dependent upon our ability to meet certain wage and apprenticeship requirements. If we are unable to obtain the Section 45Q tax credits included in our financial assumptions for any reason, including as a result of policy changes, government spending adjustments, or U.S. presidential executive actions, many of our proposed CCUS projects may no longer be commercially viable and may not be completed. As an example, the EPA has proposed to rescind the greenhouse gas reporting program, compliance with which is necessary to qualify for the Section 45Q tax credits; if the EPA proceeds with this proposal, we may not be able to comply with the Section 45Q tax credit requirements that are proposed by the Treasury Department as a replacement. We cannot ensure that we will be successful in obtaining any or all of the Section 45Q tax credits currently available. Additionally, we may not receive 100% of the Section 45Q tax credits associated with CCUS projects funded in whole or in part by third parties and, in such cases, will receive only a corresponding percentage of the anticipated Section 45Q tax credits associated with such projects. Moreover, for CCUS facilities that begin construction after 2025, federal tax legislation enacted on July 4, 2025 provides new foreign entity of concern requirements that restrict availability of Section 45Q credits if the entity that owns the facility has certain relationships with or makes certain payments to foreign entities of concern.

CCUS projects will require storage of CO2 in subterranean reservoirs over long periods of time. If accidental releases or subsurface migration of CO2 from our CCUS activities were to occur in the course of operating one or more of our CCUS sites, there is the risk of government recapture of Section 45Q tax credits previously claimed by or issued to us, as well as a risk of trespass or other tort or property claims related to the accidental release or migration of CO2 beyond the permitted boundaries of any anticipated project, as well as the potential for fines and penalties for violations of environmental requirements.

A successful CCUS project in the United States must comply with what we anticipate will be a stringent regulatory scheme involving multiple federal and state permits applicable to the subsurface injection of CO2 for geologic sequestration. Moreover, when we are the operator of a CCUS project, we must demonstrate and maintain levels of financial assurance sufficient to cover the cost of corrective action, injection well plugging, post-injection site care and site closure and emergency and remedial response. There is no assurance that we will be successful in obtaining permits or

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adequate levels of financial assurance for one or more of our CCUS projects or that permits can be obtained in a timely manner, whether due to difficulty with the technical demonstrations required to obtain such permits, public opposition, undeveloped regulatory framework, or otherwise.

There can be no assurances that we will be able to execute on our CCUS strategy and continue to successfully operate the Barnett Zero Project with ONEOK in the Barnett, or successfully develop the Eagle Ford Project and the Cotton Cove Project with BPPUS, or any future CCUS projects and any failure to do so in whole or in any significant part could have a material adverse effect on our ability to reach our near-term and long-term net zero goals on our anticipated time frame or at all, as well as on our liquidity, financial condition, and results of operations.

Risks Related to Our Midstream Business

Midstream operations are complex activities which present certain risks that could adversely affect our business, financial condition, or results of operations.

In operating our midstream and production facilities, from time to time we experience certain issues and encounter risks, which include the following:

•mechanical and instrument or tool failures;

•loss of well, pressure vessel, tank, or other related equipment control and associated hydrocarbon release and/or natural gas clouds;

•loss or compromise of casing integrity during production;

•unwanted casing pressure or fluid migration during production operations;

•unwanted migration of sequestered carbon dioxide or other fluids in injection wells;

•temporary and permanent surface facility operations and associated pressure and hydrocarbon hazards;

•surface overpressure events and other hazards resulting from machinery (horsepower), equipment, or well pressure;

•fines and violations related to relevant laws and regulations;

•fires and explosions;

•pipeline loss of containment due to integrity issues, pipeline strikes, or other reasons and associated hydrocarbon release;

•personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation, and trenching;

•major damage or malfunction to key equipment or processes;

•structural damage and collapse to equipment and machinery;

•in certain instances, close proximity of operations to residences, and/or communities; and

•other typical midstream and production facilities challenges and risks.

We depend on our natural gas midstream system for the gathering and processing of a substantial percentage of our natural gas production.

In the event that our natural gas midstream system is unable to process our natural gas production, or its operations are otherwise disturbed or curtailed, we could experience a disruption in our ability to transport our natural gas production, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Construction of midstream projects subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations, cash flows and liquidity.

From time to time, we may plan and construct midstream projects, some of which may take a number of months before commercial operation, such as construction of natural gas, NGL, and produced water gathering or transportation systems and related facilities. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, government and regulatory approval, compliance with laws, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our financial condition, results of operations, and cash flows. The construction of these midstream facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs, and financing for these development projects may not be available on economically acceptable terms or at all. Moreover, our revenues may not increase immediately, or at all, upon the expenditure of funds on a particular project. Should the actual costs of these

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projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions.

We do not own all of the land on which our pipelines and other midstream facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipelines and other midstream facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to construct and operate our assets on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases, or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere, and reduce our revenue.

Risks Related to Our Business Generally

Substantially all of our oil, gas, and midstream properties are concentrated in Texas and Northeast Pennsylvania, making us vulnerable to risks associated with operating in only two geographic areas.

Substantially all of our oil, gas, and midstream properties are located in Texas and Northeast Pennsylvania. As a result of this geographic concentration, an adverse development in the natural gas, NGLs, and oil and/or midstream business in either or both of these operating areas could have a greater impact on our financial condition, results of operations, and cash flows than if we were more geographically diversified. Due to the concentrated nature of our properties, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by governmental regulation, processing or transportation capacity constraints, water shortages or other drought related conditions, availability of equipment, facilities, personnel, or services market limitations, or interruption of the processing or transportation of natural gas, NGLs, and oil.

In addition, the weather in these areas can be extreme and can cause interruption in our operations. Severe weather can result in damage to our facilities entailing longer operational interruptions and significant capital expenditures.

The effect of fluctuations on supply and demand may become more pronounced within specific geographic natural gas, NGL, and oil producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. A number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition, results of operations, and cash flows.

A financial crisis, armed conflict, or deterioration in general economic, business, or industry conditions could materially adversely affect our results of operations and financial condition.

Concerns over global economic conditions, stock market volatility, energy costs, geopolitical issues, inflation and the U.S. Federal Reserve interest rate adjustments in response, the availability and cost of credit, and the slowing of economic growth in the United States, and fears of a recession have contributed and may continue to contribute to economic uncertainty and diminished expectations for the global economy.

Our business has also been impacted by economic conditions and disruptions in global financial markets such as reduced energy demand, inflation, and labor shortages. There was uncertainty during 2024 and 2025 with potential economic downturns or recessions in parts of the United States and globally, which continues into 2026 with global conflicts involving Russia, Ukraine, the Middle East, among others. Due to uncertainty in inflation, we may continue to see global, industry-wide supply chain disruptions and widespread shortages of labor, materials, and services. Such shortages have resulted in our facing significant cost increases for labor, materials, and services, and we expect these shortages and cost increases to continue. We are currently in a period of marginally increasing natural gas prices; however, the cost of labor, materials, and services remains high and may not adjust in proportion to increases in natural gas prices. We cannot predict the future inflation rate but if inflation elevates, we may experience further cost increases in our operations, including costs for drill rigs, workover rigs, hydraulic fracturing fleets, tubulars and other well equipment, as well as increased labor costs. If we are unable to recover from higher costs through increases in commodity prices or from our current revenue stream, then our estimates of future reserves, impairment assessments of natural gas and oil properties, and values of properties in purchase and sale transactions may all be significantly impacted. Although macroeconomic inflation is easing, these inflationary pressures may have an impact on our liquidity position when combined with the impact of rising interest rates on our variable rate debt. We expect to continue to achieve our business strategy by remaining vigilant in maintaining a disciplined financial strategy and in optimizing the value of our core business. We will also continue to

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monitor the impacts of inflation and commodity price volatility and the effects on our business, including to our customers and our partners.

The occurrence or threat of terrorist attacks in the U.S. or any of the major energy producing regions of the world or elsewhere, anti-terrorist efforts and other armed conflicts involving the U.S. or other countries, including the conflicts between Russia and Ukraine and in the Middle East, which may include further sanctions, embargoes, export controls, supply chain disruptions, regional instability and geopolitical shifts, may have adverse effects on global macroeconomic conditions, increase volatility in the price and demand for oil and natural gas, increase exposure to cyberattacks (including cyberattacks targeting energy and pipeline infrastructure), cause disruptions in global supply chains, increase transportation and insurance costs, increase foreign currency fluctuations, cause constraints or disruption in the capital markets and limit sources of liquidity. Additionally, destructive forms of protest and opposition by extremists and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural gas activities could potentially result in personal injury to persons, damages to property, natural resources or the environment, or lead to extended interruptions of our or our customers’ operations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and gas. Oil and gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our or our customers’ operations is destroyed or damaged. Expenses related to security and costs for insurance may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. We cannot predict the extent of these events’ effects on our business and results of operations as well as on the global economy and energy markets.

Concerns about global economic growth can result in a significant adverse impact on global financial markets and commodity prices. In addition, any financial crisis may cause us to face limitations on our ability to borrow under our debt agreements, service our debt obligations, access the debt and equity capital markets, and complete asset purchases or sales and may cause increased counterparty credit risk on our derivative instruments and such counterparties to cause us to post collateral guaranteeing performance.

Further, if there is a financial crisis, or the economic climate in the United States or abroad deteriorates, worldwide demand for hydrocarbon-based products could materially decrease, which could impact the price at which natural gas and NGLs from our properties are sold, affect the ability of vendors, suppliers, and customers associated with our properties to continue operations, and ultimately materially adversely impact our results of operations and financial condition. If a material adverse change occurs in our business such that an event of default occurs under our debt agreements, the lenders under such agreements may be able to accelerate the maturity of our debt.

Events outside of our control, including an epidemic or outbreak of an infectious disease, could have a material adverse effect on our business, liquidity, financial condition, results of operations and cash flows.

We face risks related to pandemics, epidemics, outbreaks or other public health events, or the threat thereof that are outside of our control, and could significantly disrupt our business and operational plans and adversely affect our liquidity, financial condition, results of operations, and cash flows. The extent to which any future pandemic, epidemic, outbreak, or other public health event could impact our business will depend on numerous evolving factors that we may not be able to accurately predict.

The success of our business plan depends, in part, on achieving our near-term and long-term net zero goals on our anticipated time frame.

The development of our CCUS business, as well as the expansion of our Pad of the Future program and the effectiveness of our leak detection and repair emissions monitoring program and the BKV-BPP Power Joint Venture’s solar facility, are each important factors to our potential ability to achieve our emissions goal of net zero Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses during the early 2030s and aspirations to offset Scope 3 emissions from our owned and operated upstream and natural gas midstream businesses by the late 2030s. We may not meet our near-term or long-term goals by our target date or at all.

Our estimated sequestration rates from our CCUS business and our emissions reduction expected from our initiatives and our associated expected emission offsets and/or other environmental attributes may turn out to be inaccurate. The standards and expectations regarding carbon accounting and the processes for measuring and counting GHG emissions and GHG emission reductions are evolving. Changes in GHG emission accounting methodologies, regulatory changes addressing the use of “net zero” in environmental marketing claims, or new developments related to climate science could impact our ability to claim emissions reductions related to our CCUS business or otherwise. For more information, see “— Risks Related to Environmental, Legal Compliance, and Regulatory Matters.” As a result, it is possible that factors outside of our control could give rise to the need to restate or revise our emissions reduction goals, cause us to miss them altogether, or limit the impact of success of achieving our goals.

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Our ability to develop and operate large-scale CCUS projects involves significant risks and uncertainties, and we may be unable to execute some or all of these projects, including those for which we have reached FID, within the expected timeline, on terms acceptable to us, or at all. Our CCUS business and nearly 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 Eagle Ford Project, the Cotton Cove Project, and the East Texas Project, we have not reached FID with respect to or entered into the definitive agreements necessary to execute any of the other potential projects described in “Business - Our Operations - Carbon Capture, Utilization, and Sequestration” and may not be able to reach agreements on terms acceptable to us, or to achieve our projected timeline for commercial operations. 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. 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. We may not be successful in developing any of our currently identified potential CCUS projects or others, our actual costs with respect to any CCUS projects may exceed our current estimate, and we may not be able to realize the anticipated reductions and offsets in emissions.

Even if we are able to successfully develop and operate such projects, we may not receive 100% of the environmental attributes associated with CCUS projects funded in whole or in part by third parties. 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, which may negatively impact our net zero strategy, including by delaying or preventing our achievement of net zero.

We have already had to extend out the timing for our achievement of our net zero goals and we may have to do so again in the future. Any disputes or ambiguities regarding the right to claim environmental attributes, may also increase the risk of double-counting of such attributes, which may negatively affect our ability to reach our net zero goals and negatively affect perceptions of our operations and products. Additionally, we may purchase various credits or offsets that may be deemed to mitigate our emissions impact instead of actual changes in our emissions reduction performance in order to meet our emissions reduction goals. However, we cannot guarantee that there will be sufficient offsets available for purchase given the increased demand from numerous businesses implementing net zero goals, that the offsets we do purchase will successfully achieve the emissions reductions they represent or that such offsets will be deemed sufficient by third parties to whom we may seek to market our products with certain environmental attributes or product claims. There can be no assurances that we will be able to execute on our strategy to meet our Scope 1, 2, and 3 owned and operated upstream and natural gas midstream emissions goals.

We may not be able to generate enough cash flow to meet our debt obligations or fund our other liquidity needs.

As of March 6, 2026, we had outstanding long-term debt of $610.0 million, which consisted of $110.0 million of borrowings under the RBL Credit Agreement and $500.0 million of borrowings under the 2030 Senior Notes. We intend, from time to time, to use borrowings available under the RBL Credit Agreement for working capital purposes, to fund capital expenditures for the acquisition, development, and exploration of oil and gas properties, and for general company purposes.

In addition to interest expense and principal on our long-term debt, we have demands on our cash resources including, among others, operating expenses and capital expenditures.

Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon future performance and our ability to repay or refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, the syndicated bank market, fluctuations in commodity prices, results of operations, and other factors, many of which are beyond our control. Our ability to meet our debt service obligations also may be impacted by changes in prevailing interest rates, as borrowings under the RBL Credit Agreement bear interest at floating rates.

We may not generate sufficient cash flow from operations. Without sufficient cash flow, there may not be adequate future sources of capital to enable us to service our indebtedness or to fund our other liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be required to adopt alternative strategies that may include:

• reducing or delaying capital expenditures;

• seeking additional debt financing or equity capital;

• selling assets; and/or

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• restructuring or refinancing debt.

We may not be able to complete such alternative strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations and fund our liquidity needs, or to refinance our indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations.

We may be unable to achieve or maintain a low target level of indebtedness, which may limit our liquidity, financial flexibility, and future operations.

Subject to the terms of the agreements governing our existing debt, we may incur significant additional indebtedness in the future in order to make acquisitions or to develop our properties or for other general corporate purposes.

Our level of indebtedness could affect our operations in several ways, including the following:

• a significant portion of our cash flows could be used to service our indebtedness;

• a high level of debt would increase our vulnerability to general adverse economic and industry conditions, and increase our interest rates;

• the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay dividends on our common stock, and make certain investments;

• a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

• our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; and

• a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate, or other purposes.

An increase in our level of indebtedness may further reduce our financial flexibility. Further, a high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, commodity prices, and financial, business, and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings, or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions (including any financial crisis), the value of our assets, and our performance at the time we need capital. The amount available for borrowing under the RBL Credit Agreement is subject to a borrowing base, which is determined by the lenders under the RBL Credit Agreement, taking into account our estimated proved reserves and related properties and is subject to periodic re-determinations based on pricing models determined by the lenders at such time. Declines in natural gas and oil prices adversely impact the value of our oil and gas properties and, in turn, the market values used by our lenders to determine our borrowing base and could result in a determination to lower our borrowing base, reducing our financial flexibility and liquidity.

The agreements governing our indebtedness contain restrictive covenants that may limit our ability to respond to changes in market conditions, pursue business opportunities or pay dividends to our stockholders.

The agreements governing our indebtedness contain restrictive covenants that limit our ability to, among other things:

• incur additional debt;

• incur additional liens;

• sell, transfer, or dispose of assets;

• merge or consolidate, wind-up, dissolve or liquidate;

• pay dividends and distributions on, or repurchases of, equity;

• make acquisitions and investments, other than direct investments in natural gas, NGL, and oil properties and other assets in permitted lines of business;

• enter into certain transactions with our affiliates;

• enter into sale-leaseback transactions;

• make optional or voluntary payment of subordinated debt and certain other debt;

• change the nature of our business;

• change our fiscal year to make changes to the accounting treatment or reporting practices;

• amend constituent documents; and

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• enter into certain hedging transactions.

The agreements governing our existing indebtedness contain, and any future debt agreement may contain, covenants that prohibit us from paying dividends on our common stock under certain circumstances. For additional information regarding the restrictions contained in the agreements governing our existing indebtedness on BKV Upstream Midstream's and its restricted subsidiaries’ ability to pay dividends to their stockholders (including to BKV Corporation), see “— Risks Related to Our Common Stock — The agreements governing our indebtedness impose restrictions on dividend payments.”

In addition, the agreements governing our existing indebtedness require BKV Upstream Midstream and its restricted subsidiaries to maintain, and future debt agreements may require us to maintain, compliance with covenants and, in certain instances, including the RBL Credit Agreement financial ratios.

The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures, withstand a continuing or future downturn in our business, or pay dividends to our stockholders.

If we are unable to comply with the restrictions and covenants in our debt agreements, there could be an event of default under the terms of such agreements, which could result in an acceleration of repayment and the foreclosure of liens on our assets.

If we are unable to comply with the restrictions and covenants in any of our existing debt agreements or any future debt agreement, or if we default under the terms of any of our existing debt agreements, or any future debt agreement, there could be an event of default under our debt agreements. Our ability to comply with these restrictions and covenants, including meeting any financial ratios and covenants, may be affected by events beyond our control. Further, if, any person or group (other than Banpu and its controlled affiliates, excluding portfolio companies and operating companies) acquires 35% or more of BKV’s equity interests, or if any person or group acquires a greater percentage of BKV’s equity interests than are then held by Banpu and its controlled affiliates (excluding portfolio companies and operating companies of Banpu), such event will be an event of default under the RBL Credit Agreement, which may result in amounts owed by us thereunder to become immediately due and payable. In addition, if any person or group (other than Banpu and its controlled affiliates) acquires more than 50% of BKV’s equity interests, unless Banpu and its controlled affiliates retain the right to appoint a majority of the directors of BKV Upstream Midstream, and Moody’s or S&P decreases their rating of the 2030 Senior Notes as a result thereof within 60 days, holders of the 2030 Senior Notes will be entitled to require BKV Upstream Midstream to repurchase all or any part of that holder’s 2030 Senior Notes pursuant to an offer on the terms set forth in the indenture governing the 2030 Senior Notes. Banpu has no obligation to maintain any particular percentage of equity ownership in the Company and may at any time sell all or any portion of its equity interests in us. As a result, we cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. In the event of a default under our existing debt agreements or any future debt agreement, the debt holders could terminate their commitments to lend or accelerate the debt and declare all amounts borrowed due and payable, as applicable. Our obligations under the RBL Credit Agreement are secured by liens on substantially all of BKV’s and BKV Upstream Midstream's assets and those of BKV Upstream Midstream’s restricted subsidiaries that guarantee our obligations under the RBL Credit Agreement, and an event of default under the RBL Credit Agreement could result in the foreclosure of such liens. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our existing debt agreements or any future debt agreement or obtain needed waivers on satisfactory terms.

Sustained, decreased natural gas prices could cause non-compliance with the Company’s financial covenants. Non-compliance with financial debt covenants would limit the Company’s ability to draw on its existing credit facility under the RBL Credit Agreement and could also result in our debt agreements being called early, which would move certain noncurrent financial obligations to current. As a result, the Company would have insufficient liquidity and capital resources to be able to repay those obligations. Additionally, the Company’s reduced cash flow from operations could cause the Company not to meet its current and noncurrent financial obligations based on our current forecasts.

As a result of cross-default provisions in our debt agreements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.

The terms of our existing debt agreements, including the RBL Credit Agreement and the indenture governing the 2030 Senior Notes, contain cross-default provisions which provide that we could be in default under such agreements in the event of certain defaults under our other debt agreements. Accordingly, should an event of default above certain thresholds occur under any of those agreements, we face the prospect of being in default under all of our debt agreements, obligated in such instance to satisfy all of our outstanding indebtedness but in all probability unable to satisfy all of our outstanding

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obligations simultaneously. In such an event, we might not be able to obtain alternative financing or, if we are able to obtain such financing, we might not be able to obtain it on terms acceptable to us, which would negatively affect our ability to continue our business plan, make capital expenditures and finance our operations.

Our borrowings under the RBL Credit Agreement expose us to interest rate risk.

Our results of operations are exposed to interest rate risk associated with borrowings under the RBL Credit Agreement, which bear interest at rates based on SOFR or an alternative floating interest rate benchmark. In 2025, the U.S. Federal Reserve lowered interest rates three times. Interest rates are currently expected to continue to decrease in 2026 and possibly into 2027. Raising or lowering of interest rates by the U.S. Federal Reserve generally causes an increase or decrease, respectively, in SOFR and other floating interest rate benchmarks. As such, if interest rates increase, so will our interest costs. If interest rates increase in the future, or such interest rates do not decrease over the next few years, it may have a material adverse effect on our results of operations and financial condition.

Our hedging activities do not provide downside protection for all of our production and could result in financial losses or could reduce our net income. Further, our derivative contracts contain certain restrictions and covenants.

We enter into derivatives contracts in connection with our natural gas and NGLs, including, for instance, commodity price swaps, basis swaps, put and call options, and producer collars. These derivative arrangements are subject to mark-to-market accounting treatment, and the changes in fair market value of our derivative contracts are reported in our consolidated statements of operations each quarter, which may result in significant non-cash gains or losses. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

These derivative arrangements are designed to reduce our exposure to commodity price decreases. Therefore, to the extent our production is not hedged, we are exposed to declines in commodity prices. In addition, our derivative arrangements may be inadequate to protect us from continuing and prolonged declines in commodity prices. Further, while designed to reduce our exposure to commodity price decreases, these derivatives arrangements may also limit the potential gains we might otherwise receive from increases in commodity prices if such prices rise over the price established by our derivative contracts. For example, for the years ended December 31, 2025, 2024, and 2023, we had realized losses of $8.1 million, and realized gains of $112.5 million, and $90.2 million, respectively, of which $13.3 million of the $112.5 million and $46.7 million of the $90.2 million of gains related to early termination of hedges. For the years ended December 31, 2025, 2024, and 2023, we incurred unrealized gains on derivatives of $113.2 million, unrealized losses on derivatives of $146.7 million, and unrealized gains on derivatives of $148.6 million, respectively. In trying to manage our exposure to commodity price risk, we may end up with too many or too few derivative contracts, depending upon where commodity prices settle relative to our derivative price thresholds and how our natural gas and NGL volumes fluctuate relative to our expectations when the derivatives were established.

As of December 31, 2025, we have hedged 965,286 MMBtu/d, 305,180 MMBtu/d, and 172,535 MMBtu/d for 2026, 2027, and 2028, respectively, of which 471,105 MMBtu/d, 112,174 MMBtu/d, and 2,541 MMBtu/d, respectively, represented basis swaps. In addition, as of December 31, 2025, we have hedged 16,614 Bbl/d and 7,164 Bbl/d of NGLs for 2026 and 2027, respectively. Our results of operations, liquidity, and financial condition would be negatively impacted if prices of natural gas and NGLs were to become depressed or decline materially from current levels, or there is otherwise an unexpected material impact on commodity prices, and we have experienced variances in our results of operations and financial condition due to our hedging transactions.

Our hedging activities do not provide downside protection for all of our production. In addition, our ability to use hedging transactions to protect us from future commodity price declines will be dependent upon commodity prices at the time we enter into future hedging transactions and our future levels of hedging and, as a result, our future net cash flows may be more sensitive to commodity price changes. Further, if commodity prices decline materially, we will not be able to replace our hedges or enter into new hedges at favorable prices.

Subject to restrictions in the RBL Credit Agreement, our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. In the future, we may enter into additional derivative arrangements or reduce our derivative arrangements. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from future commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged, as compared with the next few years, which would result in our natural gas and NGL revenues becoming more sensitive to commodity price fluctuations.

Our hedging transactions could expose us to counterparty credit risk.

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Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. The risk of counterparty nonperformance is of particular concern in the event of disruptions in the financial markets or the significant decline in commodity prices, which could lead to sudden changes in a counterparty’s liquidity and impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of our hedge providers or some other similar proceeding or liquidity constraint might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities.

During periods of falling commodity prices, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

We may experience difficulty in achieving and managing future growth.

Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition, results of operations, and cash flows. Our ability to grow will depend on a number of factors, including:

• our ability to acquire additional assets and to successfully integrate acquisitions we may make;

• the results of our drilling program;

• commodity prices;

• our ability to develop existing prospects;

• our ability to obtain leases or options on properties for which we have seismic data;

• our ability to acquire additional seismic data;

• our ability to identify and acquire new exploratory prospects;

• our ability to continue to retain and attract skilled personnel;

• our ability to maintain or enter into new relationships with project partners and independent contractors; and

• our access to capital.

We are a holding company with no operations of our own, and we depend on our subsidiaries and our joint venture for cash to fund all of our operations, taxes and other expenses, and any dividends that we may pay.

Our operations are conducted entirely through our wholly-owned subsidiaries and joint ventures, including the BKV-BPP Power Joint Venture and the BKV-BPP Cotton Cove Joint Venture. Our ability to generate cash to meet our debt and other obligations, to cover all applicable taxes payable, and to declare and pay any dividends on our common stock is dependent on the earnings and the receipt of funds through distributions from our subsidiaries and joint ventures. Our subsidiaries’ and joint ventures’ respective abilities to generate adequate cash depends on a number of factors, including development of reserves, successful acquisitions of complementary properties, advantageous drilling conditions, natural gas, NGL, and oil prices, successful production and sales of electricity, compliance with all applicable laws and regulations, and other factors.

Our business is subject to operating hazards that could result in substantial losses or liabilities for which we may not have adequate insurance coverage.

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. If any of these hazards occur, we could sustain substantial losses as a result of:

• injury or loss of life;

• severe damage to or destruction of property, natural resources, and equipment;

• pollution or other environmental damage;

• investigatory, monitoring, and cleanup responsibilities;

• regulatory investigations and penalties or lawsuits;

• loss of, or delay in revenue;

• suspension or impairment of operations; and

• repairs to resume operations.

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We maintain insurance against some, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. Our insurance includes deductibles that must be met prior to recovery, as well as sub-limits and/or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and the proceeds of any insurance may not be received in a timely manner. Our insurance does not cover every potential risk associated with our operations, including the potential loss of significant revenues. We can provide no assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses.

We currently have insurance policies covering our operations that include coverage for general liability, property damage to certain of our real and personal property, and certain personal property of others, excess liability, physical damage to our upstream and natural gas midstream properties, operational control of wells, redrilling expenses, pollution and cleanup, site pollution incidents, damage to lease property, business and contingent business interruption, including cybersecurity, management liability, automobile liability, third-party liability, workers’ compensation, employer’s liability, and other coverages. Our insurance policies provide coverage for losses or liabilities relating to pollution, but are largely limited to coverage for sudden and accidental occurrences. For example, the site pollution incident policy we maintain includes coverage for obligations, expenses or claims that we may incur from a sudden incident that results in negative environmental effects, including obligations, expenses or claims related to seepage and pollution, cleanup and containment, evacuation expenses, and control of the well (subject to policy terms and conditions). In the specific event of a well blowout or out-of-control well resulting in negative environmental effects, such operator’s extra expense coverage would be our primary source of coverage, with the general liability and excess liability coverage referenced above also providing certain coverage.

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. Some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. If we incur substantial liability from a significant event and the damages are not covered by insurance or are in excess of policy limits, then we would have lower revenues and funds available to us for our operations, that could, in turn, have a material adverse effect on our business, financial condition, and results of operations.

Additionally, we rely to a large extent on transportation owned and operated by third parties and damage to, or destruction of, those third-party facilities could affect our ability to process, transport, and sell our production. To a limited extent, we maintain business interruption insurance related to our processing plants where we are insured for potential losses from the interruption of production caused by loss of or damage to the processing plant.

We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our ability to grow.

There is intense competition for acquisition opportunities in our industry and we may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. We may not be able to obtain contractual indemnities from sellers for liabilities incurred prior to our purchase of the business, asset or property. No assurance can be given that we will be able to identify additional suitable acquisition or asset exchange opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. In addition, there can be no assurance that Banpu will not engage in competition with us in the future. See “— Risks Related to Our Relationship with Banpu and its Affiliates — Banpu’s interests, including interests in certain corporate opportunities, may conflict with our interests and the interests of our other stockholders. Conflicts of interest between us and Banpu could be resolved in a manner unfavorable to us and our other stockholders.” Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.

We have and may continue to make acquisitions of properties or businesses that complement or expand our current business in the future. The successful acquisition of natural gas and NGL properties requires an assessment of several factors, including:

• recoverable reserves;

• future commodity prices;

• operating costs; and

• potential environmental and other liabilities.

These assessments are inherently uncertain and rely on numerous assumptions and we may not be able to identify accretive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties

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that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Reviews may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when a review is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Market forces often prevent us from negotiating contractual indemnification for environmental liabilities and require us to acquire properties on an “as is” basis.

The success of any of our acquisitions will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen liabilities, environmental issues, or other difficulties and may require a disproportionate amount of our managerial and financial resources which may divert management’s attention from other business concerns. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully, or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations, and cash flows.

In addition, the RBL Credit Agreement (solely with respect to BKV Upstream Midstream and its restricted subsidiaries) and the indenture governing the 2030 Senior Notes prohibits us from entering into certain mergers or combination transactions. These debt arrangements also limit our ability to incur indebtedness and liens, which could indirectly limit our ability to engage in acquisitions.

Our business requires substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms or be able to fund our working capital needs from cash flow from operations, which could lead to a decline in our reserves.

The energy industry is capital intensive. We have made and expect to continue to make substantial capital expenditures in our businesses for the acquisition, exploration, production and development of natural gas and NGL reserves, as well as the gathering, processing and transportation of natural gas and NGLs and the development of our CCUS business.

The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of CO2 transportation pipelines in proposed CCUS project areas, and legal, regulatory, environmental, technological and competitive developments. A sustained decline in commodity prices may result in further decreases in our actual capital expenditures, which would negatively impact our ability to grow production. Although we intend to finance our future capital expenditures primarily through cash flow from operations and through available capacity under the RBL Credit Agreement, our future needs may require us to alter or increase our capitalization substantially through the increase in the size of our working capital facilities, issuance of additional debt or equity securities, or the sale of assets.

Our cash flow from operations and access to capital are subject to a number of variables, including:

• the estimated quantities of our natural gas and NGL reserves;

• the amount of hydrocarbon we produce from existing wells;

• the prices at which we sell our production and prevailing basis differentials;

• the levels of our operating expenses;

• take-away and storage capacity;

• our ability to acquire, locate, develop, and produce new reserves; and

• our ability to borrow under the RBL Credit Agreement and any additional working capital facilities that we obtain.

If our revenues decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our planned capital budget or operations at current levels. For example, a decline in commodity prices may reduce the amount of capital the Company can raise through debt or equity financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available capacity under the RBL Credit Agreement is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties or our CCUS business, which in turn could lead to a decline in our reserves and production and a failure to meet our net zero goals, and could adversely affect our business, financial condition, and results of operations.

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We may be unable to dispose of nonstrategic assets on attractive terms and may be required to retain liabilities for certain matters.

We regularly review our asset base to assess the market value versus holding value of existing assets with a view to optimizing deployed capital. Our ability to dispose of nonstrategic assets or complete dispositions, such as acreage that we do not intend to place on our production schedule prior to lease expirations, could be affected by various factors, including the availability of buyers willing to purchase the nonstrategic assets at prices acceptable to us. Sellers typically retain certain liabilities or agree to indemnify buyers for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets.

As a result, after a sale, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenues.

The energy industry is intensely competitive, and we compete with other companies that have greater resources than we do. Our ability to acquire additional properties, to discover reserves in the future and to execute on potential CCUS projects will be dependent upon our ability to evaluate and select suitable properties to consummate transactions in a highly competitive market. Many of our larger competitors not only drill for and produce natural gas, NGLs, and oil, but they also engage in refining operations and market petroleum and other products on a regional, national, or worldwide basis. Our competitors may be able to pay more for natural gas and NGL properties, evaluate, bid for and purchase a greater number of properties than our financial or human resources permit, and attract capital at lower rates. In addition, these companies may have a greater ability to continue drilling, production, and workover activities during periods of low natural gas and NGL prices. They may also be better positioned to contract for drilling, production and workover equipment, pay higher wages to secure trained personnel, and absorb the burden of current and future federal, state, local, and other laws and regulations. The natural gas, NGL, and oil industry has periodically experienced shortages of drilling rigs, equipment, hydraulic fracturing fleets, supply chain resources, pipelines and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments. Additionally, there is strong competition for desirable natural gas, NGL, and oil-producing properties, energy companies, undeveloped leases, drilling rights, and CCUS projects. Further, inflation may affect us more severely than it may affect some of our larger competitors. Our inability to compete effectively with our competitors could have a material adverse impact on our business activities, financial condition, and results of operations.

The energy industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. Further, competitors may obtain patents which might prevent us from implementing new technologies. In addition, other energy companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may, in the future, allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.

The inability of one or more of our significant counterparties to meet their payment or performance obligations may adversely affect our financial results.

We are subject to certain credit risks associated with nonpayment or nonperformance by our counterparties, including joint interest partners and customers. Joint interest receivables arise from billing our joint interest partners who own a partial working interest in our natural gas and NGL wells. These entities participate in our natural gas and NGL wells primarily based on their ownership in leases on which we operate, and we have limited ability to control their participation in our natural gas and NGL wells. Sales receivables arise from the sale of our natural gas and NGL production to our customers. We currently market, directly or indirectly, our natural gas and NGL production to energy marketing companies, refineries, gas processors, petrochemical companies, local distribution companies, power plants, and other end users.

We maintain credit procedures and policies to mitigate the credit risks posed by our counterparties. However, our credit procedures and policies may not be adequate to fully eliminate the risk and we do not require all of our

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counterparties to post collateral. If we fail to adequately assess the creditworthiness of our existing or future significant counterparties, or their creditworthiness unexpectedly materially deteriorates, any resulting nonpayment or nonperformance by them could have a materially adverse effect on our financial condition and results of operations.

Our business could be negatively affected by security threats and disruptions, including electronic, cybersecurity or physical security threats and other disruptions.

Our business faces various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks, including but not limited to human error, power outages, computer and telecommunication failures, natural disasters, fraud or malice, social engineering or phishing attacks, viruses or malware, and other cyberattacks, such as denial-of-service or ransomware attacks. Reports indicate that certain entities or groups, including cybercriminals, competitors, and nation state actors, have mounted cyber-attacks on businesses and other organizations solely to disable or disrupt computer systems, disrupt operations, and, in some cases, steal data. While we maintain a robust cybersecurity program, which includes administrative, technical, and organizational safeguards, a significant cyberattack or other cyber incident (whether involving our systems, those of a critical third-party, or both) could disrupt our operations and result in downtime, loss of revenue, harm to the Company’s reputation, or the loss, theft, corruption, or unauthorized release of critical data of us or those with whom we do business, as well as result in higher costs to correct and remedy the effects of such incidents, including potential extortion payments associated with ransomware or ransom demands. Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities, and infrastructure may also result in increased capital and operating costs. As of March 6, 2026, we were not aware of any cybersecurity threats or incidents that have materially affected or are reasonably likely to materially affect the Company, including our business strategy, results of operations or financial standing. However, there can be no assurance that our procedures and controls will be sufficient to prevent or mitigate security breaches, which could lead to losses of sensitive information, critical infrastructure, or capabilities essential to our operations, all of which could have a material adverse effect on our business, financial position, results of operations, and cash flows. In addition, to assist in conducting our business, we rely on information technology systems and data hosting facilities, including systems and facilities that are hosted by third parties to which we have limited visibility and control. Even though we carry cyber insurance that may provide insurance coverage under certain circumstances, we might suffer losses as a result of a security breach or cyber incident that exceeds the coverage available under our policy or for which we do not have coverage, and we cannot be certain that cyber insurance will continue to be available to us on commercially reasonable terms, or at all. The use by BKV and its third-party service providers to a hybrid systems model, including on-premises and cloud environments, has transformed how systems interconnect, how data is stored, how users interact with applications, and what end user devices are utilized. This hybrid systems model has resulted in additional cybersecurity risk, and cybersecurity attacks, particularly amidst the increased adoption of artificial intelligence technologies, are becoming more sophisticated. These events could damage our reputation and lead to financial losses from remedial actions, loss of business, or potential liability.

Moreover, the rapid advancement and increased adoption of artificial intelligence and machine learning technologies have given rise to additional vulnerabilities and potential entry points for cyberattacks, including a risk of exposure of confidential, proprietary or other sensitive information through the inadvertent use of open artificial intelligence tools. These technologies can be exploited by malicious actors to enhance the sophistication, scale or intensity of cyberattacks, making it more challenging to detect and mitigate such threats.

We may face various risks associated with the long-term trend toward increased activism against natural gas, NGL, and oil exploration and development activities.

Opposition toward natural gas, NGL, and oil drilling and development activity has been growing globally. Companies in the natural gas, NGL, and oil industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, environmental compliance, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain projects such as the development of natural gas, NGL, and oil shale plays. For example, environmental activists continue to advocate for increased regulations or bans on shale drilling and hydraulic fracturing in the United States, even in jurisdictions that are among the most stringent in their regulation of the industry. Future activist efforts could result in the following:

• delay or denial of drilling permits;

• shortening of lease terms and reduction in lease size;

• restrictions on installation or operation of production, gathering, or processing facilities;

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• restrictions on the use of certain operating practices, such as hydraulic fracturing, or disposal of related waste materials, such as hydraulic fracking fluids and production;

• increased severance and/or other taxes;

• cyber-attacks;

• legal challenges or lawsuits;

• negative publicity about our business or the natural gas, NGL, and oil industry in general;

• increased costs of doing business;

• reduction in demand for our products; and

• other adverse effects on our ability to develop our properties and expand production.

Similarly, some activists view CCUS as a means to either promote the fossil fuel industry or avoid transition to other sources of energy, and thus, are often opposed to such projects regardless of any potential environmental benefits. We may need to incur significant costs associated with responding to these or other initiatives, and there is no guarantee that our responses will produce favorable outcomes or results. Complying with any resulting additional legal or regulatory requirements that are substantial could have a material adverse effect on our business, financial condition, cash flows, and results of operations.

Prolonged negative investor sentiment toward upstream natural gas, NGL, and oil focused companies could limit our access to capital funding, which would constrain liquidity.

Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other sectors have led to lower natural gas, NGL, and oil representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the natural gas, NGL and oil sector based on social and environmental considerations. Certain other stakeholders have pressured commercial and investment banks to stop funding natural gas, NGL, and oil projects. If this negative sentiment continues for a prolonged period of time, it may reduce the availability of capital funding for potential development projects, each of which could have a material adverse effect our financial condition, results of operations, and cash flows.

We may be involved in legal proceedings that could result in substantial liabilities.

Like many energy companies, in the ordinary course of our business, we are from time to time involved in various disputes and disagreements that may lead to legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters, and personal injury or property damage matters. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management, and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties, or sanctions, as well as judgments, consent decrees, or orders requiring a change in our business practices, which could materially and adversely affect our business, prospects, financial condition, results of operations, and cash flows. Accruals for such liability, penalties, or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could materially change from one period to the next.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing, and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process, and sell natural gas and NGLs, and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

We are highly dependent on our executive officers and technical personnel, the loss of any of whom could adversely affect our operations. Additionally, the continued success of our business depends on our ability to attract and retain experienced technical personnel.

We depend on the services of our senior management and technical personnel. There can be no assurance that we would be able to replace such members of management with comparable replacements or that such replacements would integrate well with our existing team. Further, the loss of the services of our senior management could have a material adverse effect on our business, financial condition, and results of operations. We do not maintain, nor do we plan to obtain, any “key-man” life insurance against the loss of any of these individuals. As a result, we are not insured against any losses resulting from the death of our key employees. The loss of the services of our senior management or technical personnel

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could have a material adverse effect on our business, future business prospects, financial condition, results of operations, and cash flows.

Our continued success will depend, in part, on our ability to attract and retain experienced technical personnel, including geologists, engineers, and other professionals. Competition for these professionals is strong and will likely intensify as a significant portion of today’s engineers, geologists, and other professionals working within the oil and natural gas industry will reach the age of retirement in the coming years. Acquiring and retaining these personnel could prove more difficult or cost substantially more than estimated.

In addition, Christopher Kalnin serves as a member of Banpu’s Executive Committee with responsibilities to Banpu to, among other things, manage all aspects of Banpu’s business in North America. Although our corporate opportunity policy requires Mr. Kalnin to present applicable business opportunities sourced by him to BKV before such opportunities may be presented to Banpu, Banpu or its affiliates may compete with us for acquisition or other business opportunities. Our independent directors also serve, or may in the future serve, as officers and board members for other entities. If our officers’ and directors’ other business affairs require them to devote substantial amounts of time to such affairs, it could limit their ability to devote time to our affairs which may have a negative impact on our ability to compete or follow the elements of our business strategy.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including disclosure about our executive compensation, that apply to other public companies.

We are classified as an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act, including as modified by the JOBS Act. In addition, we have reduced Sarbanes-Oxley Act compliance requirements, as discussed elsewhere, for as long as we are an emerging growth company, which may be up to five full fiscal years. Unlike other public companies, we will not be required to, among other things, (i) comply with any new requirements adopted by the Public Company Accounting Oversight Board ("PCAOB") requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (ii) provide certain disclosure regarding executive compensation required of larger public companies, or (iii) hold nonbinding advisory votes on executive compensation.

To the extent that we rely on any of the exemptions available to emerging growth companies, less information will be provided about our executive compensation and internal control over financial reporting compared to non-emerging growth companies. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

We expect to lose emerging growth company status as of December 31, 2026.

Risks Related to Environmental, Legal Compliance, and Regulatory Matters

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner, or feasibility of conducting our operations.

Our natural gas and NGL exploration and production operations are subject to complex and stringent laws and regulations. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals, and certificates from various federal, state, and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling and related permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling and related permits with onerous conditions could increase our compliance costs or decrease our opportunities to execute projects and develop acreage. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of natural gas and NGLs we may produce and sell.

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of natural gas and NGLs. The possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs or cause us to cease operations. If we are not able to recover the resulting costs through insurance or increased revenues, our financial condition could be adversely affected.

Changing sentiments towards ESG matters and environmental conservation measures may adversely impact our business.

Changing sentiments towards climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG initiatives and disclosures, and consumer demand for alternative forms of energy may result in increased costs (including, but not limited to, increased costs related to compliance, stakeholder engagement, contracting and insurance), reduced demand for our products, reduced profits, increased investigations and

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litigation, and negative impacts on our access to capital markets. Changing sentiments towards climate change, environmental justice, and environmental conservation, for example, may result in demand shifts for natural gas, NGL, and oil products and additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of, or contribution to, the asserted damage, or to other mitigating factors.

Moreover, while we may occasionally create and publish voluntary disclosures regarding ESG matters, many of the statements in these disclosures are based on hypothetical expectations and assumptions, which may not be representative of current or actual risks or events, or forecasts of expected risks or events, including the associated costs. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring, and reporting on many ESG matters. Such disclosures may also be at least partially reliant on third-party information that we have not verified, or cannot verify, independently. ESG programs and disclosures are currently in disfavor at the federal level as well as in some states, which may cause other states to increase levels of ESG-related regulation, along with increased stakeholder and non-governmental organizational engagement in ESG matters. Increased regulation will likely lead to increased compliance costs as well as scrutiny that could heighten all of the risks identified in this risk factor. We may also take certain actions to improve the ESG profile of our Company and/or products, but we cannot guarantee that such actions will have the desired effect.

In addition, we recognize that standards and expectations for carbon accounting as well as the methods for measuring GHG emissions and environmental attributes, such as offsets and renewable energy credits, are evolving. Our current and future approaches to measuring and implementing reductions and achieving goals like "net zero" or a "closed-loop" system may be viewed by some stakeholders as inconsistent with emerging or common best practices depending on individual interpretations or expectations. If our approaches to such matters are inconsistent with particular stakeholder expectations, we may face increased scrutiny, criticism, regulatory actions, and investor concerns, or litigation, any of which may adversely impact our business, financial condition or results of operations. For example, there has been increasing scrutiny on and criticism of the certification or labeling of certain fossil fuel products as “responsible” or similar labels, as well as on various marketing or other claims related to the use of offsets or the emission profile of products, given alleged deficiencies in the monitoring processes used to support such certifications or claims, which may adversely impact demand for, and any premium associated with, such certifications and claims. Our plans and claims regarding our Pad of the Future and RSG programs, and our intent to produce Carbon Sequestered Gas, may come under criticism, expose us to potential litigation, or otherwise impact our reputation and financial performance. For example, our plan to retire carbon credits against our Scope 1 and Scope 3 emissions instead of transferring such credits with our produced natural gas may impact certain customers’ willingness or ability to use Carbon Sequestered Gas to meet their own emissions goals, and thus adversely impact demand for such product. Additionally, disputes or ambiguities regarding the methodologies used to certify and register carbon credits associated with CCUS projects could delay or prevent our efforts to certify and register the environmental attributes associated with our CCUS projects as tradeable carbon credits, including the development of a blockchain ledger and tokens to facilitate the transfer of environmental attributes, which may negatively impact our net zero strategy, including by delaying or preventing our achievement of net zero. Such failure may also otherwise impact our operations to the extent such certification or similar condition is required, such as with our contract with a subsidiary of Kiewit. In certain cases, our emissions reduction and other ESG efforts rely on third parties, whose actions or timelines may not align with our expectations. Additionally, even if we achieve our net zero goals as described herein, we may not fully realize the intended benefits if other stakeholders disagree with our goals, structure, methodology, accounting practices, or data sources in achieving them.

Additionally, various regulators have adopted, or are considering adopting, regulations on environmental marketing claims, including, but not limited to, the use of climate-related language such as “net zero” in product marketing. These requirements may use different criteria or methodologies than we currently use in assessing our net zero strategy or products, such as our intentions to develop Carbon Sequestered Gas. Any new regulations adopted, or reinterpretations of new ones, may require us to change our internal assessment criteria, limit the use of certain marketing claims, reduce the benefit of initiatives we implemented, or adversely affect our operations.

Changing sentiments towards global climate change has resulted in increased investor attention and risk of public and private litigation, which could increase our costs or otherwise adversely affect our business. A number of parties have sought to bring suit against the largest oil and gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing, handling, or marketing fuels that contributed to global warming effects, such as rising sea levels, are responsible for roadway and infrastructure damages, or alleging that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose those impacts. The ultimate outcome and impact to us of these allegations cannot be predicted with certainty, and we could incur substantial legal costs associated with defending these and similar lawsuits in the future.

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In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Stockholder activism has also recently been increasing in our industry, and stockholders may attempt to effect changes to our business or governance, whether by stockholder proposals, public campaigns, proxy solicitations, or otherwise. Any of these risks could result in unexpected costs, negative sentiments about us, disruptions in our operations, increases to our operating expenses, and reduced demand for our products, which in turn could have an adverse effect on our business, financial condition, and results of operations.

There are also increasing financial risks for fossil fuel producers as stockholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into other sectors. Institutional lenders and institutional investors who provide financing to fossil-fuel energy companies also have become more attentive to sustainable financing practices and some of them may elect not to provide funding for fossil fuel energy companies, which could result in the restriction, delay, or cancellation of drilling or development programs or production activities and affect our access to capital for potential growth projects. For example, the international community gathered in Glasgow, Scotland, U.K. at the 26th Conference to the Parties (“COP26”) on the UN Framework Convention on Climate Change (“UNFCCC”), and the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. On January 7, 2026, President Trump issued a Presidential Memorandum entitled “Withdrawing the United States from International Organizations, Conventions, and Treaties that Are Contrary to the Interests of the United States,” which directs executive agencies to take immediate steps to remove the United States from 66 listed treaties or organizations, including the UNFCCC and the Intergovernmental Panel on Climate Change. Although the Trump Administration has shifted policies at the federal level, risks identified in this section resulting from other drivers are expected to persist in any event, and there could be another shift at the federal level in the future.

Moreover, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees. Such ESG matters may also impact our suppliers or customers, which may adversely impact our business, financial condition, or results of operations.

Energy conservation measures and technological advances could reduce demand for natural gas, NGLs, and oil.

Energy conservation measures, alternative fuel requirements, governmental requirements for renewable energy resources, increasing consumer demand for alternatives to natural gas, NGLs, and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas, NGLs, and oil. The impact of the changing demand for natural gas, NGL, and oil services and products may have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities, and cause us to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes, droughts, floods, and freezes), sea levels, the arability of farmland, changes in temperature and other meteorological patterns, and water availability and quality. If such effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse effects may include damages to our facilities from powerful winds or rising waters in low lying areas, disruption to production due to climate-related damages or increased operational costs, the need for less efficient or non-routine operating practices caused by climate effects, or increased insurance costs resulting from such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies, or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change. We have developed and are continuously implementing plans that address the potential impacts of climate change on our operations, but we cannot guarantee that our operations will not be negatively impacted by climate change.

Federal, state, and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of natural gas and NGL wells and adversely affect our production.

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Hydraulic fracturing is used in many of our operations to stimulate production of hydrocarbons, particularly natural gas and NGLs. The process involves the injection of water, sand, and additives under pressure into a targeted subsurface formation to fracture the surrounding rock and stimulate production. Congress, from time to time, has considered legislation to amend the SDWA to remove the exemption currently available to hydraulic fracturing, which would place additional regulatory burdens upon hydraulic fracturing operations, including requirements to obtain a permit prior to commencing operations adhering to certain construction requirements, to establish financial assurance, and to require reporting and disclosure of the chemicals used in those operations. Such legislation has not passed.

Hydraulic fracturing (other than that using diesel) is currently generally exempt from regulation under the SDWA’s UIC program and is typically regulated by state oil and natural gas commissions or similar agencies. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the process.

For example, in June 2016, the EPA adopted effluent limitations for the treatment and discharge of wastewater resulting from onshore unconventional natural gas, NGL, and oil extraction facilities to publicly owned treatment works and, in 2014, the EPA asserted regulatory authority pursuant to the UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities.

Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances.” The final report identified the following risks: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. To date, EPA has taken no further action in response to the December 2016 report.

In addition, some states have adopted, and other states may consider adopting, regulations that restrict or could restrict hydraulic fracturing in certain circumstances. Further, state and local governmental entities have exercised the regulatory powers to regulate, curtail, or in some cases prohibit hydraulic fracturing. New laws or regulations that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material adverse effect on our business, prospects, financial condition, results of operations, and cash flow.

Regulatory action may cause us to shut in or curtail production.

Our rate of production and access to transportation and storage options may also be affected by U.S. federal and state regulation of oil and natural gas production. In 2020, actions of foreign oil producers, such as Saudi Arabia and Russia, and the impact on global demand of the COVID-19 pandemic, materially decreased global crude oil prices and generated a surplus of oil. As a result, regulatory action to curtail production was contemplated, but ultimately rejected in Texas. If Texas were to decide to limit the production of crude oil in the future, our business and results of operations are not likely to be materially and adversely impacted given that our production comes from dry gas wells.

Any such production limitations that apply to our operations will likely force us to shut in production. If we are forced to shut in production as a result of regulatory actions or otherwise, we will likely incur greater costs to bring the associated production back online. Cost increases necessary to bring the associated wells back online may be significant enough that such wells would become uneconomic at low commodity price levels, which may lead to decreases in our proved reserves estimates and potential impairments and associated charges to our earnings. If we are able to bring wells back online, there is no assurance that such wells will be as productive following recommencement as they were prior to being shut in. Any shut in or curtailment of the natural gas and NGLs produced from our fields could adversely affect our financial condition, results of operations, cash flows, and ability to fulfill our obligations under our firm transportation service agreements.

Our operations are subject to a series of risks relating to climate change that could result in increased compliance or operating costs, limit the areas in which we may conduct natural gas and NGL exploration and production activities, and reduce demand for the natural gas and NGLs we produce.

Climate change continues to attract considerable public, political, and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of carbon dioxide, methane, and other GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting, and tracking programs and regulations that directly limit GHG emissions from certain sources.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, in August 2022, Congress passed, and former President Biden signed into law, the Inflation Reduction Act of 2022, which, for the first time ever, imposes a fee on GHG emissions from certain facilities. However, the OBBBA delayed

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implementation of these emissions fees for the oil and gas industry until 2034. The emissions fee requirements, if they ultimately 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.

Moreover, following the U.S. Supreme Court finding in 2007 that GHG emissions constitute a pollutant under the CAA and the EPA's subsequent Endangerment Finding, the EPA adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the U.S. Department of Transportation (“DOT”), imposing GHG emissions and fuel economy standards for vehicles in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. The EPA previously had promulgated New Source Performance Standards (“NSPS”) imposing limitations on methane emissions from sources in the oil and gas sector. Subsequently, in September 2020, the Trump Administration rescinded those methane standards and removed the transmission and storage segments from the oil and gas source category under the CAA’s NSPS. However, on June 30, 2021, former President Biden signed a resolution passed by Congress under the Congressional Review Act nullifying the September 2020 rule, effectively reinstating the prior standards. On March 8, 2024, the EPA published its Methane Rule, which took effect on May 7, 2024 and established requirements for methane emissions from existing and modified oil and gas sources and imposed additional requirements for new sources with respect to methane emissions, including sources not previously regulated under the oil and gas source category. However, on December 3, 2025, the EPA issued a final rule delaying by 18 months key compliance deadlines in the March 8, 2024 Methane Rule. Further, the Methane Rule and the December 2025 rule delaying its implementation are currently being challenged in the federal courts. In addition, on May 6, 2024, the EPA released its revised regulations for GHG emissions reporting (“Subpart W Regulations”) that will have an impact on the quantity of GHG emissions reported and the associated payment of fees under the Waste Emissions Charge imposed by the IRA that may be applicable to our operations. However, on September 16, 2025, the EPA proposed a rollback of the GHG reporting regulations that would end reporting under the GHG emissions reporting program for the natural gas distribution industry and for all sectors other than those subject to the Subpart W Regulations and would pause reporting under the Subpart W Regulations until 2034. Separately, on February 18, 2026, the EPA published a final rule rescinding the Endangerment Finding, which underpins the EPA's regulation of GHGs. The rescission has been challenged in court, which could result in the rescission being stayed, overturned, or limited in scope or effect. For more information, see “Business - Government Regulation and Environmental Matters.” We continue to review additional changes to rules, such as the revised regulations issued by the Bureau of Land Management to reduce flaring and natural gas waste on federal leases or updates to its onshore oil and gas leasing rules that may impact our current or future operations.

While the Trump administration has rolled back or is proposing to roll back many regulations and findings related to GHG emissions and their effects on public health and welfare, a future administration may seek to impose new legislation or rules related to GHG emissions that could impact our operations. Further, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, several states, including Pennsylvania and New Mexico, have proposed or adopted regulations restricting the emission of methane from exploration and production activities. At the international level, the United States was an original party to the Paris Agreement, but withdrew in 2020, rejoined in 2021, and withdrew again, effective January 27, 2026, pursuant a January 2025 order issued by President Trump. It is possible that the United States will rejoin the Paris Agreement in the future and make commitments to reduce GHG emissions and move toward a global net zero economy as it has done in the past. To the extent developments result in new restrictions on natural gas and NGL operations, increase operational costs, or otherwise reduce the demand for natural gas and NGLs, our business could be materially adversely effected. For more information, see “Business - Government Regulation and Environmental Matters.”

Additionally, in March 2024, the SEC finalized a new rule that would require the reporting of climate-related risks and financial impacts, as well as GHG emissions for larger companies. On April 4, 2024, the SEC issued an order staying implementation of the SEC climate disclosure rule pending judicial review of various legal challenges to the rule, which were consolidated into the Eighth Circuit Court of Appeals. On March 27, 2025, the SEC voted to end the defense of the rules in the litigation and, on July 23, 2025, it filed a status report requesting that the Eighth Circuit proceed with the case and issue an opinion on the challenges to the climate disclosure rule. On September 12, 2025, the Eighth Circuit denied the SEC’s request to proceed with the case and indicated that the case would be held in abeyance until the SEC either renews its defense of the rules or revises the rules via notice-and-comment rulemaking. We continue to monitor the status of this rule, but we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. In addition, other policymakers, including the State of California, have adopted (or are considering adopting) similar or more stringent regulations. Enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive sectors. The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and gas sector or otherwise restrict the areas in which this sector may produce oil and gas or generate GHG emissions could result in increased costs of

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compliance or costs of consuming, and thereby reduce demand for, oil and gas. Additionally, political, litigation and financial risks may result in us restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operations.

Our ability to pursue our business strategies may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental, health and safety laws or regulations or a release into the environment.

We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental, health and safety laws and regulations, including, for example, the following federal laws and their state counterparts, as amended from time to time:

• the CAA, which regulates the emission of air pollutants from many sources, imposes various preconstruction, monitoring and reporting requirements and is relied upon by the EPA as authority for adopting climate change regulatory initiatives relating to GHG emissions;

• the Federal Water Pollution Control Act, also known as the CWA, which regulates the discharge of pollutants from facilities to state and federal waters and establishes the extent to which waterbodies are subject to federal jurisdiction and rulemaking as protected waters of the United States;

• the SDWA, which is designed to protect the quality of the nation’s public drinking water through adoption of drinking water standards and UIC over the subsurface injection of fluids into belowground formations;

• the RCRA, which imposes requirements for the generation, treatment, storage, transport, disposal, and cleanup of nonhazardous and hazardous wastes;

• the CERCLA, which imposes liability on generators, and those who arrange for the transportation, treatment or disposal, of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur as well as on present and certain past owners and operators of those sites;

• the Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees, and response departments about toxic chemical uses and inventories; and

• the ESA, which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal, or permanent ban on operations in affected areas.

These U.S. laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water, and disposals or other releases or threats of release to surface, soils, and groundwater. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the incurrence of capital expenditures, the occurrence of delays in the permitting, development, or expansion of projects, and the issuance of orders enjoining some or all of our future operations in a particular area. Certain environmental laws impose strict joint and several liability, without regard to fault or legality of conduct, for costs required to clean up and restore sites where hazardous substances or other wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, wastes, or other materials into the environment. In addition, these laws and regulations may restrict the rate of natural gas and NGL production or underground injection, disposal, and sequestration of CO2. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results.

In addition, as a result of these environmental, health and safety laws and regulations, and their impact on our operations, we rely on specialized contracted companies to perform the majority of the specialized services inherent in the oil and gas industry. As such, we depend on these contractors to provide trained labor as well as equipment that is properly designed, maintained, and tailored to their specific services. With the cyclical nature of the oil and gas business, the personnel used by these specialized contractors to perform these services may differ significantly in experience levels. From time to time, these specialized contractors may use new personnel that are still in training or may further sub-contract these services to other companies or personnel. There is a risk that these sub-contractors are unqualified or under-trained, or that their equipment is not properly designed or maintained, which could result in work being performed inadequately or unsafely.

Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the oil and gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or

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other governmental action is taken that restricts drilling or production or imposes more stringent and costly operating, waste handling, disposal, and cleanup requirements, our business, prospects, financial condition, or results of operations could be materially adversely affected.

Our gathering systems and processing, treating, and fractionation facilities are subject to state regulation that could have a material adverse effect on our operations and cash flows.

State regulation of gathering systems and processing, treating, and fractionation facilities includes safety and environmental requirements. In addition, several of our gas gathering systems are also subject to non-discriminatory delivery requirements and complaint-based state regulation regarding our rates, terms, and conditions of service. Our NGL gathering pipelines and operations may also fall under state public utility or related jurisdiction, which could impose additional safety and operational regulations relating to the design, siting, installation, testing, construction, operation, replacement, and management of NGL gathering facilities. State and local regulation may cause us to incur additional costs, limit our operations, or prevent us from choosing the customers to which we provide service, any or all of which could have a material adverse effect on our operations and revenue.

The Temple Plants are subject to the rules and regulations of the PUCT and ERCOT, which could have a material adverse effect on our operations and cash flows.

The Temple Plants are subject to the rules and regulations of the PUCT and ERCOT. These regulations can impact the operations of generation facilities, which in turn can impact associated costs and revenues. For example, the PUCT implemented rules regarding weatherization of power plants in the aftermath of Winter Storm Uri. Such rules increased capital, operational, and maintenance costs for many generation facilities. Additionally, the PUCT is currently weighing a redesign of the ERCOT market that is intended to retain existing generation facilities and encourage the construction of new generation facilities. This process could lead to decreased revenue, increased operating costs, and adversely affect our business, financial condition, and results of operations.

In addition, from time to time, ERCOT makes changes to its protocols or takes out of market actions that impact the wholesale power market. These regulations may cause us to incur additional costs or face delays, or otherwise could have a material adverse effect on our operations and cash flows.

We may face unanticipated water and other waste disposal costs as a result of increased water-related regulations.

We may be subject to regulation that restricts our ability to discharge water produced as part of our natural gas and NGL production operations. Productive zones frequently contain water that must be removed for the natural gas and NGLs to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce natural gas and NGLs in commercial quantities. The produced water must be transported from the leasehold and/or injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability. We may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment if any of the following occur: (i) water produced from our projects fails to meet the quality requirements set by relevant regulatory agencies, (ii) our wells produce water in excess of the allowed volumetric permit limits, (iii) the disposal wells fail to comply with applicable regulatory requirements, or (iv) we are unable to secure access to disposal wells with sufficient capacity to handle all of the produced water. The costs to dispose of this produced water may increase if any of the following occur:

• we cannot obtain future permits from applicable regulatory agencies;

• water of lesser quality or requiring additional treatment is produced;

• our wells produce excess water;

• new laws and regulations require water to be disposed in a different manner; or

• costs to transport the produced water to the disposal wells increase.

In June 2016, the EPA adopted effluent limitations for the treatment and discharge of wastewater resulting from onshore unconventional natural gas, NGL, and oil extraction facilities to publicly owned treatment works. The disposal of fluids gathered from natural gas, NGL, and oil producing operations in underground disposal wells has been pointed to by some groups and regulators as a potential cause of increased induced seismic events in certain areas of the U.S., particularly in Oklahoma, Texas, Colorado, Kansas, New Mexico, and Arkansas. Certain states have begun to consider or adopt laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing those requirements may issue orders directing certain wells in areas where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. Additionally, regulators in some states have modified their regulations or guidance to mitigate potential causes of induced seismicity. Any one or more of these developments could also increase our cost to dispose of our produced water.

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A change in the jurisdictional characterization of some of our assets by federal, state, or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Our natural gas gathering operations are generally exempt from the jurisdiction and regulation of the Federal Energy Regulatory Commission (“FERC”), except for certain anti-market manipulation provisions. Section 1(b) of the Natural Gas Act (“NGA”) exempts natural gas gathering facilities from regulation by FERC as a natural gas company as defined under that statute. We believe the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gathering pipeline not subject to regulation by FERC. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is fact intensive and the subject of ongoing litigation. If FERC were to consider the status of our gathering systems and determine that they are subject to FERC regulation, the rates for, and terms and conditions of, services provided by those gathering systems would be subject to modification by FERC under the NGA or the Natural Gas Policy Act (“NGPA”). Such regulation could decrease revenue, increase operating costs, and adversely affect our business, financial condition, and results of operations. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, it could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such services in excess of the rates established by FERC.

The pipelines used to gather and transport natural gas we produce are subject to regulation by the DOT under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In April 2016, pursuant to one of the requirements of the 2011 Pipeline Safety Act, PHMSA issued a notice of proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currently regulated gas gathering and transmission pipelines. The proposal would also significantly expand the regulation of gas gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, and maximum allowable operating pressure limits, among others. To implement these changes outlined in the 2016 notice of proposed rulemaking, PHMSA promulgated three separate major rules (collectively referred to as the “Gas Mega Rule”), which include rules focused on: the safety of gas transmission pipelines, the safety of hazardous liquid pipelines, and enhanced emergency order procedures.

The first component of the Gas Mega Rule, the gas transmission rule, was finalized in October 2019 and requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA promulgated the second component of the Gas Mega Rule in November 2021, extending federal safety requirements to onshore gas gathering pipelines with large diameters and high operating pressures.

The final of the three components of the Gas Mega Rule was published on August 24, 2022 and took effect on May 24, 2023 and imposes new standards for pipeline inspections and repairs and empowers PHMSA with expanded authority to issue emergency orders.

The adoption of laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operating costs that could be significant. In addition, should we fail to comply with PHMSA or comparable state regulations, we could be subject to substantial fines and penalties. As of January 2025, the maximum civil penalties PHMSA can impose are $272,926 per pipeline safety violation per day, with a maximum of $2,729,245 for a related series of violations. However, the proposed Pipeline Safety Act of 2025, S. 2975, would increase these maximum civil penalty amounts to $400,000 and $4,000,000, respectively.

Restrictions on drilling, completion, production or related activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Natural gas and NGL operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect migratory birds or various threatened or endangered species, such as those restrictions imposed under the ESA. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies, and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species as threatened or endangered in areas where we operate could cause us to

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incur increased costs arising from species protection measures or could result in limitations on our exploration, development, and production activities that could have an adverse impact on our ability to develop and produce our reserves. To the extent species are listed or re-designated under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us to incur costs or take other measures which may materially impact our business or operations.

Potential transactions that could benefit our stockholders may be subject to regulatory review and approval requirements, including pursuant to foreign investment regulations and review by governmental entities such as the Committee on Foreign Investment in the United States (“CFIUS”), or may be ultimately prohibited.

Potential transactions we consider may be subject to regulatory review and approval requirements by governmental entities, or ultimately prohibited. For example, CFIUS has authority to review direct or indirect foreign investments in U.S. companies. Among other things, CFIUS is empowered to require certain foreign investors to make mandatory filings, to charge filing fees related to such filings, and to self-initiate national security reviews of foreign direct and indirect investments in U.S. companies if the parties to that investment choose not to file voluntarily. In the case that CFIUS determines an investment to be a threat to national security, CFIUS has the power to unwind or place restrictions on the investment. Whether CFIUS has jurisdiction to review an acquisition or investment transaction depends on, among other factors, the nature and structure of the transaction, including the level of beneficial ownership interest and the nature of any information or governance rights involved. For example, investments that result in “control” of a U.S. business by a foreign person are always subject to CFIUS jurisdiction. CFIUS’s expanded jurisdiction under the Foreign Investment Risk Review Modernization Act of 2018 and implementing regulations that became effective on February 13, 2020 further includes investments that do not result in control of a U.S. business by a foreign person but afford certain foreign investors certain information or governance rights in a U.S. business that has a nexus to “critical technologies,” “critical infrastructure,” and/or “sensitive personal data.”

For so long as Banpu retains a material ownership interest in us, we may be deemed a “foreign person” under the regulations relating to CFIUS. As such, potential transactions involving a U.S. business or foreign business with U.S. subsidiaries that we may wish to pursue may be subject to CFIUS review. If a particular transaction falls within CFIUS’s jurisdiction, we may either determine that we are required to make a mandatory filing, submit to CFIUS review on a voluntary basis, or proceed with the transaction without submitting to CFIUS and risk CFIUS intervention, before or after closing the transaction. CFIUS may decide to block or delay transactions that could benefit our stockholders, impose conditions with respect to such transactions or request the President of the United States to order us to divest all or a portion of the assets or companies we acquired without first obtaining CFIUS approval, which may limit the attractiveness of, delay or prevent us from pursuing certain target companies or assets that we believe would otherwise be beneficial to us and our stockholders, any of which could have a material adverse effect on our financial condition, results of operations, and cash flows.

Our sales of natural gas and NGLs, and any hedging activities related to such commodities, expose us to potential regulatory risks.

Sales of natural gas and NGLs are not currently regulated and are made at negotiated prices. However, the federal government historically has been active in the area of natural gas and NGL sales regulation. We cannot predict whether new legislation to regulate natural gas and NGL sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures and, what effect, if any, the proposals might have on our operations.

Additionally, the Federal Trade Commission and the Commodity Futures Trading Commissions (the “CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of natural gas and NGLs, and any hedging activities related to these energy commodities, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect our financial condition, results of operations, and cash flows.

The adoption of derivatives legislation and regulations by Congress related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price

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volatility through the OTC market. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized or implemented, and it is not possible at this time to predict when, or if, this will be accomplished.

Effective March 15, 2021, the CFTC implemented its final rule concerning speculative position limits, adopting new and amended federal spot-month limits for 25 physical commodity derivatives. Under this rule, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions.

The CFTC has also adopted final rules regarding aggregation of positions under which a party that controls the trading of, or owns 10% or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. The CFTC’s aggregation rules are now in effect. With the implementation of the final aggregation rules and adoption of the final CFTC position limits rules, our ability to execute our hedging strategies described above could be limited.

The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016. This final rule was amended on February 24, 2021 to permit the application of a minimum transfer amount of up to $50,000 for each separately managed account of a legal entity that is a counterparty to a swap dealer or a major swap participant in an uncleared swap transaction and to permit the application of separate minimum transfer amounts for initial margin and variation margin.

In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types of swap transactions. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.

All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. While it is not possible at this time to predict when the CFTC will issue or amend final rules applicable to position limits or capital requirements, depending on our ability to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate our commercial risks, these rules and regulations may require us to comply with position limits and with certain clearing and trade-execution requirements in connection with our financial derivative activities. When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require our current financial counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the costs to us of future financial derivatives transactions. The Volcker Rule provisions of the Dodd-Frank Act may also require our current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, who may not be as credit-worthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us, as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.

As a result, the Dodd-Frank Act and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect our capital available for other commercial operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.

If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of commodity prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to natural gas, NGLs, and oil. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial condition, results of operations, and cash flows.

Potential future legislation or the imposition of new or increased taxes or fees may generally affect the taxation of natural gas, NGL and oil exploration and development companies and may adversely affect our cash flows.

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Since 2020, there have been a significant number of federal and state level legislative proposals that, if enacted into law, would make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently available to natural gas, NGL, and oil exploration and development companies. Such proposals include, but are not limited to, (i) an increase in the U.S. federal income tax rates applicable to corporations, (ii) the repeal of the percentage depletion allowance for certain natural gas, NGL, and oil properties, (iii) the elimination of current deductions for intangible drilling and development costs, and (iv) an increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, natural gas, NGL, and oil within the United States. It is unclear whether these, or similar changes, will be enacted and, if enacted, how soon any such changes could take effect. Additionally, the states in which we operate or own assets may impose new or increased taxes or fees on natural gas, NGL, and oil extraction. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws or the imposition of new or increased taxes or fees on natural gas, NGL, and oil extraction could adversely affect our operations and cash flows.

Our tax liabilities potentially are subject to periodic audits by U.S. federal, state, and local taxing authorities. Although we believe we have used reasonable interpretations and assumptions in calculating our tax liabilities, the final determination of these tax audits and any related proceedings cannot be predicted with certainty. Any adverse outcome of any such tax audits or related proceedings could result in unforeseen tax-related liabilities that may, individually or in the aggregate, materially affect our cash tax liabilities, and, as a result, our business, financial condition, results of operations, and cash flows.

Our business is subject to complex and evolving laws and regulations regarding privacy and cybersecurity.

The regulatory environment surrounding cybersecurity, data privacy and protection, and the unauthorized disclosure of personal or confidential information is constantly evolving and can be subject to significant change. New laws and requirements pose increasingly complex compliance challenges and could potentially elevate our costs. Any failure or perceived failure to comply with these laws and regulations could result in significant penalties, legal liability, judgments, and negative publicity, changes in our business practices, and adverse impacts to our business. We continue to monitor and assess the impact of these laws, such as the California Consumer Privacy Act and the Cyber Incident Reporting for Critical Infrastructure Act, and other similar legislation. If we are not able to adjust to changing laws, regulations, and standards relating to privacy or cybersecurity, our business may be materially harmed. As noted above, we are also subject to the possibility of cyber events, which themselves may result in a violation of these privacy and data security laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable privacy and cybersecurity laws, we may incur significant liabilities and penalties as a result.

Changes in U.S. foreign trade policies, including the imposition of additional tariffs and other trade barriers, and efforts to withdraw from or materially modify international trade agreements, may materially and adversely affect our business, operations and financial condition.

U.S. foreign trade policy continues to evolve, and recent actions have resulted in the imposition of new and increased tariffs, as well as other trade barriers on the foreign import of certain materials and products. For example, in April 2025, the U.S. government announced a new tariff regime that included a 10% baseline tariff on most products imported from other countries and an additional individualized reciprocal tariff on the countries with which the U.S. has the largest trade deficits, including China. Since that time, the U.S. has expanded tariffs on key industrial inputs, including tariffs on steel and aluminum imports, and has at times announced, rescinded, modified and temporarily suspended multiple tariffs on several foreign jurisdictions, which has increased uncertainty regarding the ultimate effect of the tariffs on economic conditions. Additionally, in August 2025, the U.S. Court of Appeals for the Federal Circuit ruled that many of the tariffs imposed under the Trump Administration exceed presidential authority and therefore are invalid, and in February 2026, the U.S. Supreme Court affirmed such decision. Following the ruling, the Trump Administration signed an executive order imposing a 10% “global tariff” and later indicated an intention to increase such “global tariff” to 15%, effective immediately, using presidential powers under certain U.S. trade laws. If implemented, such tariffs can remain in effect for up to 150 days, which may be extended by the U.S. Congress. The Trump Administration may continue to impose additional tariffs under other U.S. trade laws. Moreover, from time to time, certain leaders in the U.S. government, including in the Trump administration, have indicated a willingness to revise, renegotiate or terminate various existing bilateral and multilateral trade agreements. The uncertainty over such policies has caused volatility in commodity, capital and financial markets, increased concerns over domestic and global inflation and adversely impacted consumer confidence in the U.S. and worldwide. Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, declining consumer confidence, significant inflation and diminished expectations for the economy, and ultimately reduced demand for oil and natural gas.

Changes in tariffs and trade restrictions can be announced with little or no advance notice. We cannot predict what additional changes to trade policy or tariffs will be made by the Trump administration or Congress, including whether

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existing tariff policies will be maintained or modified, what materials or products may be subject to such policies or whether the entry into new bilateral or multilateral trade agreements, or the amendment or termination of existing trade agreements, will occur, nor can we predict the effects that any such changes would have on our business. However, such steps, if adopted, could increase our costs, disrupt supply chains, delay project timelines or otherwise adversely impact our business and operations.

In addition, changes in U.S. trade policy and tariffs have resulted, and could again result, in reactions from U.S. trading partners, including adopting responsive trade policies. For example, in response to the U.S. government’s additional tariff on imports from China, on February 4, 2025, the Chinese government announced that it would implement tariffs on certain goods being imported into China from the U.S. Similar responsive measures have been announced or implemented by other countries affected by U.S. trade actions. There can be no assurance that such changes in U.S. or foreign trade policy or tariffs or in laws and policies governing foreign trade, and any resulting negative sentiments or retaliatory trade practices towards the United States as a result of such changes, would not materially and adversely affect our business, financial condition and results of operations.

Risks Related to Our Relationship with Banpu and its Affiliates

Banpu is our controlling stockholder and exercises a significant influence over us, and investors' ability to influence matters requiring stockholder approval may be limited.

As of February 27, 2026, Banpu indirectly owns approximately 67.6% of our outstanding common stock. Our outstanding common stock is entitled to one vote per share. As a result of this ownership, Banpu has a significant influence on our affairs and its voting power constitutes a significant majority percentage of any quorum of our stockholders voting on any matter requiring the approval of our stockholders. Such matters include the election of directors, the adoption of amendments to our certificate of incorporation and bylaws, and the approval of mergers or the sale of all or substantially all of our assets. Banpu’s control or significant influence over us also may delay, defer, or prevent an acquisition by a third party or other change of control of our Company and may make some transactions more difficult or impossible without the support of Banpu, even if such events are in the best interests of our other stockholders.

In addition, under our Stockholders’ Agreement, as long as BNAC beneficially owns 10% or more of our voting stock, BNAC will be entitled to designate for nomination to our board of directors a number of individuals approximately proportionate to such beneficial ownership, provided that (i) from September 27, 2025 until the first date on which BNAC beneficially owns 50% or less of our voting stock, at least four board seats will not be BNAC designees, and (ii) from and after the first date on which BNAC beneficially owns 50% or less of our voting stock, a number of board seats equal to the minimum number of directors that would constitute a majority of the total number of directors comprising our board of directors will not be BNAC designees.

Further, 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), such event will be an event of default under the RBL Credit Agreement, which may result in the amounts owed by us thereunder to become immediately due and payable. Further, if, any person or group (other than Banpu and its controlled affiliates) acquires more than 50% of our equity interests, unless Banpu and its controlled retain the right to appoint a majority of the directors of BKV Upstream Midstream, and Moody’s or S&P decreases their rating of the 2030 Senior Notes as a result thereof within 60 days, holders of the 2030 Senior Notes will be entitled to a require BKV Upstream Midstream to repurchase all or any part of that holder’s 2030 Senior Notes pursuant to an offer on the terms set forth in the indenture governing the 2030 Senior Notes.

Banpu also exercises significant influence over the BKV-BPP Cotton Cove Joint Venture and the BKV-BPP Power Joint Venture, each of which requires the consent of BPPUS for certain material actions. The BKV-BPP Cotton Cove Joint Venture is controlled by its six-member board of managers, four of whom are appointed by BKV dCarbon Ventures (our wholly-owned subsidiary) and two of whom are appointed by BPPUS. Of the three members appointed by us, none are employees of Banpu who also serve on our board of directors. For additional information, see “— Risks Related to Our CCUS Business — We operate the Cotton Cove Project through a joint venture that requires the consent of BPPUS for certain material actions.”

The BKV-BPP Power Joint Venture is controlled by its twelve-member board of managers (the “Power JV Board”), nine of whom are appointed by us and three of whom are appointed by BPPUS. For as long as BPPUS maintains an ownership interest in the BKV-BPP Power Joint Venture of at least 10%, consent from at least one member of the Power JV Board appointed by BPPUS will be required for certain specified actions as detailed in the BKV-BPP Power LLC Agreement. For additional information, see “— Risks Related to Our Power Generation Business — We operate our power generation business through a joint venture that requires the consent of BPPUS for certain material actions.”

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The interests of Banpu may differ from our interests or those of our other stockholders and the concentration of control in Banpu will limit other stockholders’ ability to influence corporate matters. Banpu may take actions that our other stockholders do not view as beneficial or decline to take actions that our other stockholders view as beneficial, which may adversely affect our business, financial condition, and results of operations. In addition, Banpu’s control or significant influence over us may have an adverse effect on the price of our common stock.

Historically, we relied on Banpu and its affiliates for capital investments sufficient to fund our business operations. Banpu has no obligation to make any further capital investments or to provide additional loan proceeds.

Prior to our IPO on September 27, 2024, we relied on Banpu and its affiliates for the capital investments necessary to fund our business through loan proceeds and other contributions. Following this date, Banpu and its affiliates have no obligation to provide any additional funding, and instead, we expect to fund our capital expenditures for our upstream, midstream, and power businesses through cash flows from operations and from borrowings under our RBL Credit Agreement. 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. Our future operating performance and ability to meet our debt service obligations will be affected by economic and capital market conditions, commodity prices, our results of operations, and other factors, many of which are beyond our control.

Restrictive covenants in the agreements governing the indebtedness of Banpu may limit our ability to incur additional debt.

The agreements governing the indebtedness of Banpu require it to maintain certain financial ratios and tests based on consolidated financial statements. Banpu continues to have a substantial influence on our affairs and its voting power will constitute a substantial percentage of any quorum of our stockholders voting on any matter requiring the approval of our stockholders. As a result, Banpu may prevent us from taking corporate actions that could cause Banpu to fail to comply with the applicable provisions of its debt agreements, even when such actions are in our best interests and the interests of our other stockholders. This limitation may materially adversely affect our ability to obtain future financing or fund needed capital expenditures.

We are currently a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for and rely on exemptions from certain corporate governance requirements.

Banpu beneficially controls a significant majority of the voting power of our outstanding voting stock. Pursuant to our Stockholders’ Agreement, BNAC, through ownership interests in us held by BNAC, has certain rights to designate individuals for nomination to our board of directors. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

• a majority of the board of directors consist of independent directors;

• the corporate governance and nominating committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities;

• the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

• there be an annual performance evaluation of the nominating and governance and compensation committees.

These requirements will not apply to us as long as we remain a controlled company. Accordingly, the same protections afforded to stockholders of companies that are subject to all of the NYSE corporate governance requirements are not afforded to our stockholders.

Banpu’s interests, including interests in certain corporate opportunities, may conflict with our interests and the interests of our other stockholders. Conflicts of interest between us and Banpu could be resolved in a manner unfavorable to us and our other stockholders.

Banpu could have interests that differ from, or conflict with, the interests of our other stockholders and could cause us to take certain actions even if the actions are not favorable to us or our other stockholders or are opposed by our other stockholders. Potential conflicts of interest or disputes may arise between Banpu and us in a number of areas relating to our past or ongoing relationships, including:

• tax, employee benefits, indemnification, and other matters arising from our status as a publicly traded company;

• employee retention and recruiting;

• corporate opportunities that may be attractive to both Banpu and us;

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• the arrangements governing the BKV-BPP Power Joint Venture, BKV-BPP Cotton Cove Joint Venture, and any other new commercial arrangements between the Company and affiliates of Banpu in the future; and

• sales or other disposals by Banpu of all or a portion of its interest in us.

We may not be able to resolve potential conflicts and disputes with Banpu and even if we do, the resolution may be less favorable to us than if we were dealing with an unaffiliated third party. Because we are controlled and significantly influenced by Banpu, we may not have the leverage to negotiate amendments to the arrangements governing the BKV-BPP Power Joint Venture or BKV-BPP Cotton Cove Joint Venture (if any are required) on terms as favorable to us as those we would negotiate with an unaffiliated third party. As a result of Banpu’s relationship with us, Banpu will have significant influence over our affairs and potentially those of the BKV-BPP Power Joint Venture and could exercise such influence in a manner that is not in the best interests of our stockholders.

Additionally, there can be no assurance that Banpu will not engage in competition with us in the future. Our certificate of incorporation provides that, to the fullest extent permitted by law, neither Banpu nor its affiliates or any director who is not employed by us (including any non-employee director who serves as one of our officers in both his or her director and officer capacities) or his or her affiliates will have any duty to refrain from (i) engaging in the same or similar business activities or lines of business in which we or our affiliates now engage or propose to engage or (ii) otherwise competing with us or our affiliates. In addition, to the fullest extent permitted by law, in the event that Banpu or its affiliates, or any non-employee director, acquires knowledge of a potential transaction or other business opportunity that may be a corporate opportunity for itself, himself or herself, or its, or his or her affiliates, or for us or any of our affiliates, such person will have no duty to communicate or offer such transaction or business opportunity to us or any of our affiliates. They may take any such opportunity for themselves or offer it to another person or entity.

Our certificate of incorporation also renounces, to the fullest extent permitted by law, any interest or expectancy that we have in, or right to be offered an opportunity to participate in, specified business opportunities that are, from time to time, presented to our officers, directors, or stockholders or their respective affiliates, other than those officers, directors, stockholders, or affiliates who are our, or our subsidiaries’ employees.

Generally, neither Banpu nor our non-employee directors, who also are directors, officers, employees, agents, or affiliates of Banpu or its affiliates (other than us), will be liable to us or our stockholders for breach of any fiduciary duty solely due to the fact that any such person pursues or acquires any corporate opportunity for, or recommends or transfers any corporate opportunity to, Banpu or its affiliates (other than us), rather than to us. This renunciation will not extend to corporate opportunities expressly offered to one of our non-employee directors solely in his or her capacity as our director or officer.

These provisions create the possibility that a corporate opportunity of our Company may be used for the benefit of Banpu and may significantly impair our ability to grow. In addition, Christopher Kalnin serves as a member of Banpu’s Executive Committee with responsibilities to Banpu to, among other things, manage all aspects of Banpu’s business in North America. Although our corporate opportunity policy requires Mr. Kalnin to present applicable business opportunities sourced by him to our Company before such opportunities may be presented to Banpu, Banpu or its affiliates may compete with us for acquisition or other business opportunities.

Certain of our officers and directors may have actual or potential conflicts of interest because of their positions with Banpu or its affiliates and/or their ownership of common stock or equity awards in Banpu or its affiliates.

Christopher Kalnin currently serves as a member of Banpu’s Executive Committee with responsibilities to Banpu to, among other things, manage all aspects of Banpu’s business in North America. Seven of our directors are employees of Banpu or its affiliates. In addition, most of our directors now own, or our officers and other directors may own in the future, capital stock or equity awards in Banpu or its affiliates. For certain of these individuals, their holdings of common stock or equity awards in Banpu or its affiliates may be significant compared to their total assets. Their position at Banpu or its affiliates and the ownership of capital stock or equity awards in Banpu or its affiliates creates, or may create the appearance of, conflicts of interest when these directors and officers are faced with decisions that could have different implications for Banpu than for us. These decisions could include:

• corporate opportunities;

• the impact that operating or capital decisions (including the incurrence of indebtedness) relating to our business may have on Banpu’s consolidated financial statements or current or future indebtedness (including related covenants);

• business combinations involving us;

• our dividend and stock repurchase policies;

• compensation and benefit programs and other human resources policy decisions;

• management of stock ownership;

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• the payment of dividends on our common stock; and

• determinations with respect to our tax returns.

As a result of these actual or apparent conflicts of interest, we may be precluded from pursuing certain growth initiatives or transactions that may be favorable to us or we may take certain actions even if the actions are not favorable to us or are opposed by our stockholders.

The BKV-BPP Joint Venture Transaction is a related party transaction, which may create actual or perceived conflicts of interest.

The BKV-BPP Joint Venture Transaction is considered a “Related Party” transaction pursuant to Rule 312.03 of the NYSE Listed Company Manual. BPPUS is a wholly-owned subsidiary of Banpu Power, which is a subsidiary of Banpu, and Banpu is the ultimate parent company of both BKV and BKV’s majority stockholder, BNAC. Although our board of directors implemented procedural safeguards, including the formation of a special committee consisting solely of independent and disinterested directors, these overlapping relationships may create the perception that the BKV-BPP Joint Venture Transaction was not negotiated at arm’s length. Such perceptions could lead to negative stockholder sentiment, potential claims, or increased regulatory scrutiny.

Risks Related to Our Common Stock

Our actual operating results and activities could differ materially from the guidance we have disclosed herein.

We have presented herein certain forecasted operating results, costs and activities, including, without limitation, our future expected drilling activity and production. Any such forward-looking guidance represents our management’s estimates as of the date hereof, is based upon a number of assumptions that are inherently uncertain and is subject to numerous business, political, economic, competitive, financial, and regulatory risks, including the risks described in Item 1A, “Risk Factors,” and under “Cautionary Note Regarding Forward-Looking Statements” included elsewhere herein. Many of these risks and uncertainties are beyond our control, such as declines in commodity prices, the speculative nature of estimating natural gas and NGL reserves, and projecting future rates of production. If any of these risks and uncertainties actually occur or the assumptions underlying our guidance are incorrect, our actual operating results, costs, and activities may be materially and adversely different from our guidance. In addition, investors should also recognize that the reliability of any guidance diminishes the farther in the future that the data is forecast. In light of the foregoing, investors are urged to put our guidance in context and not to place undue reliance upon it.

We do not currently plan to, and may not in the future have sufficient available cash to, pay dividends on our common stock.

We do not currently plan to declare dividends on our shares of common stock, and any future determination to pay dividends will be made at the sole discretion of our board of directors after considering our general economic and business conditions, including, among other things, our financial condition and anticipated cash needs. Furthermore, under Delaware law, cash dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from the corporation’s net profits for the then-current or the preceding fiscal year. Unless we operate profitably, our ability to pay dividends on our common stock would require the availability of adequate “surplus,” which is defined as the excess, if any, of net assets (total assets less total liabilities) over capital. Events may occur, including a reduction in anticipated production volumes or realized prices or other events, which could materially impact the amount of surplus we may have and/or may result in insufficient available cash to enable us to pay dividends to our stockholders.

The payment of dividends on our common stock is subject to the discretion of our board of directors and the lack of dividend payments on our common stock could adversely affect the market price of our common stock.

Our stockholders will have no contractual or other legal right to dividends. The payment of any future dividends on our common stock will be at the discretion of our board of directors and any determination to pay dividends and the amount of any such dividends will depend on general economic and business conditions, our financial condition, capital requirements, results of operations, contractual limitations, legal, tax, regulatory and contractual restrictions, and implications on the payment of dividends by us to our stockholders or by our subsidiaries to us, including the restrictions under our current and any future debt agreements, potential acquisition opportunities, and the availability and desirability of financing alternatives, the need to service our indebtedness or other current and anticipated cash needs, and any other factors our board of directors deem relevant. Our board of directors will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of or increase in those reserves could result in insufficient cash available for payment of dividends on our common stock. The lack of dividend payments on our common stock could adversely affect the market price of our common stock.

The repurchase of shares of our common stock will be at the discretion of management and subject to numerous factors.

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In December 2025, our board of directors authorized a two-year share repurchase program pursuant to which the Company may repurchase from time to time shares of its common stock, for an aggregate purchase price of up to $100.0 million through open market purchases, block trades, 10b5-1 plans, or by means of privately negotiated purchases. However, the timing and total amount of any share repurchases will be determined at the discretion of management based on a variety of factors, including economic and market conditions, the stock price, the Company’s liquidity requirements and priorities, regulatory requirements, applicable legal requirements and other factors. The repurchase program does not obligate us to repurchase any specific number of shares and may be suspended, modified, or discontinued at any time at the discretion of our board of directors.

The agreements governing our indebtedness impose restrictions on dividend payments.

The RBL Credit Agreement and the indenture governing the 2030 Senior Notes contain, and any future debt agreement may contain, covenants that prohibit us from paying dividends on our common stock under certain circumstances. The RBL Credit Agreement permits BKV Upstream Midstream and its restricted subsidiaries to pay (a) dividends to their stockholders (including to BKV Corporation) in an amount not to exceed 100% of Distributable Free Cash Flow (as defined in the RBL Credit Agreement) if (1) the net leverage ratio on a pro forma basis is less than or equal to 2.00 to 1.00 and (2) the pro forma available commitments are greater than or equal to 20% of the Loan Limit, and (b) additional unlimited dividends to their stockholders (including to BKV Corporation) if (1) the net leverage ratio (as defined in the RBL Credit Agreement) on a pro forma basis is less than or equal to 1.75 to 1.00 and (2) the pro forma available commitments are greater than or equal to 25% of the Loan Limit (as defined in the RBL Credit Agreement), in each case, subject to no default, event of default or borrowing base deficiency under the RBL Credit Agreement. The indenture governing the 2030 Senior Notes permits BKV Upstream Midstream and its restricted subsidiaries to pay (a) unlimited dividends to their stockholders (including to BKV Corporation) if (1) the consolidated net leverage ratio (as defined in the indenture governing the 2030 Senior Notes) on a pro forma basis is less than or equal to 1.00 to 1.00 and (2) other dividends to their stockholders (including to BKV Corporation) in an amount not to exceed 25.0% of BKV Upstream Midstream’s Consolidated EBITDAX (as defined in the indenture governing the 2030 Senior Notes) for the most recently ended four full fiscal quarters, so long as, after giving pro forma effect to the payment of any such dividend, the consolidated net leverage ratio is no greater than 1.25 to 1.00, in each case, subject to no default or event of default under the indenture governing the 2030 Senior Notes. There can be no assurance that we will generate sufficient cash flow to permit us to reduce leverage and pay dividends in compliance with the RBL Credit Agreement, the indenture governing the 2030 Senior Notes, or any other debt agreement.

Restrictions on distributions to us by our subsidiaries and affiliates under agreements governing their future indebtedness could limit our ability to pay dividends to holders of our common stock. These agreements contain financial tests and covenants that our subsidiaries and affiliates must satisfy prior to making distributions. If any of our subsidiaries or affiliates is unable to satisfy these restrictions or is otherwise in default under such agreements, it would be prohibited from making distributions to us that could, in turn, limit our ability to pay dividends to holders of our common stock.

We have identified a material weakness in our internal control over financial reporting and may identify additional material weaknesses in the future, or otherwise fail to maintain effective internal control over financial reporting, which could result in a restatement of our financial statements or cause us to fail to meet our reporting obligations.

As of December 31, 2024, a material weakness existed in our internal control over financial reporting. A “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

We did not design and maintain effective controls related to the accounting for income taxes, which were not designed at a sufficient level of precision or rigor to prepare and review the tax rate reconciliation, return to provision, income tax provision, related income tax assets and liabilities, and disclosures in the consolidated financial statements. This material weakness resulted in audit adjustments to income tax benefit, income taxes payable to related party, and deferred tax assets and liabilities in the consolidated financial statements as of December 31, 2021 and for the year then ended.

During the year ended December 31, 2025, we remediated this material weakness related to the accounting for our income taxes primarily by designing and implementing additional internal controls, including those related to the preparation and review of the income tax rate reconciliation, return to provision, income tax provision, related income tax assets and liabilities, and income tax disclosures. Although we believe we addressed the internal control deficiencies that led to this material weakness, the measures we have taken may not be effective.

The material weaknesses described above could have resulted in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.

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Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate control over financial reporting in the future, or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act.

We cannot guarantee that we have identified all, or that we will not in the future have additional material weaknesses. Material weaknesses may still exist when we report on the effectiveness of our internal control over financial reporting as required by reporting requirements under Section 404 of the Sarbanes-Oxley Act as a public entity. If material weaknesses emerge related to financial reporting, we encounter difficulties in implementing or improving our internal controls or we otherwise fail to develop and maintain effective internal control over financial reporting, our reputation and operating results could be harmed, we could fail to meet our reporting obligations, or we may have a restatement of our financial statements. Ineffective internal control over financial reporting could also cause current and potential investors to lose confidence in our reported financial information, which would harm our business and likely have a negative effect on the trading price of our common stock.

Our governing documents, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock. The existence of significant stockholders, such as Banpu, may have similar effects.

Some provisions of our governing documents could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

• providing for a classified board of directors;

• limitations on the removal of directors;

• limitations on the ability of our stockholders to call special meetings;

• establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;

• the requirement that the affirmative vote of the holders of at least 66 2∕3% in voting power of all the then-outstanding shares of our stock be obtained to amend and restate our existing bylaws or to remove directors;

• the requirement that the affirmative vote of the holders of at least 66 2∕3% in voting power of all the then-outstanding shares of our stock (or, if approved by at least 60% of our board of directors, a majority in voting power of all the then-outstanding shares of our stock) be obtained to amend our certificate of incorporation; and

• providing that the board of directors is expressly authorized to make, repeal, alter, amend, and rescind our bylaws.

In addition, the existence of significant stockholders, such as our sponsor, Banpu, and its affiliates, may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of the Company. Banpu is the ultimate parent company of BPPUS and BNAC and, as a result, Banpu's concentration of stock ownership increased upon the issuance of 5,315,390 shares of common stock issued to BPPUS in connection with the closing of the BKV-BPP Power Joint Venture Transaction. Moreover, Banpu’s concentration of stock ownership in us may adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.

Future sales of our common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

As of February 27, 2026, Banpu, the ultimate parent of BPPUS and BNAC, is the indirect beneficial owner of 69,193,004 shares of common stock, representing approximately 67.6% of our total outstanding common stock, and management, directors, and other employee and non-employee stockholders, collectively, own 33,095,073 shares of common stock, representing approximately 32.4% of our total outstanding common stock.

In addition, our Stockholders’ Agreement provides BNAC and its affiliates with the right, in certain circumstances, to require us to register their shares of our common stock constituting registrable securities under the Securities Act for sale into the public markets. In accordance with the registration rights granted to BNAC, on October 1, 2025, we filed a resale registration statement on Form S-3 to register the offer and sale of 63,877,614 shares of common stock owned by BNAC, and subsequently amended the resale registration statement on November 25, 2025. As of the date of this Annual Report on Form 10-K, no shares of our common stock have been sold by BNAC pursuant to that resale registration statement.

In connection with the closing of the Bedrock Acquisition, we entered into a Registration Rights Agreement with Bedrock Energy Partners, LLC ("Bedrock Energy Partners"), pursuant to which we agreed to, among other things, provide

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Bedrock Energy Partners with certain demand and piggyback registration rights for the 5,233,957 shares of common stock received in the Bedrock Acquisition, subject to customary cutbacks, blackout periods, and other limitations.

In accordance with the registration rights granted to Bedrock Energy Partners, on December 23, 2025, we filed an automatic shelf registration statement on Form S-3 to register the offer and sale of 5,233,957 shares of our common stock owned by Bedrock Energy Partners. As of the date of this Annual Report on Form 10-K, no shares of our common stock have been sold by Bedrock Energy Partners pursuant to that resale registration statement.

In connection with the closing of the BKV-BPP Power Joint Venture Transaction, we also entered into a Registration Rights Agreement with BPPUS, pursuant to which BPPUS received certain demand and piggyback registration rights for the 5,315,390 shares of common stock issued to BPPUS in the BKV-BPP Power Joint Venture Transaction, subject to a 180-day lock-up and customary cutbacks, blackout periods and other limitations.

We also may, in the future, issue additional shares of common stock as some or all of the consideration for future transactions. Furthermore, we may issue additional shares of common stock or convertible securities in subsequent public offerings. We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances of our common stock will have on the market price of our common stock. Issuances of substantial amounts of our common stock or sales of shares owned by Banpu and other stockholders, or the perception that such issuances or sales could occur, may adversely affect prevailing market prices of our common stock.

Our common stock does not entitle the holders thereof to preemptive rights to buy shares from us. As a result, stockholders will not have the automatic ability to avoid dilution in their percentage ownership of us.

Terms of subsequent financings or the issuance of preferred stock may adversely impact stockholder equity.

If we raise more equity capital from the sale of common stock, institutional or other investors may negotiate terms more favorable than the current prices of our common stock. If we issue debt securities, the holders of the debt would have a claim to our assets that would be prior to the rights of stockholders until the debt is paid. Interest on these debt securities would increase costs and could negatively impact our operating results.

In accordance with Delaware law and the provisions of our certificate of incorporation, we may issue one or more classes or series of preferred stock that ranks senior in right of dividends, liquidation or voting to our common stock. Preferred stock may have such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine, and the issuance of preferred stock would dilute the ownership of our existing stockholders. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock. The terms of any series of preferred stock may also reduce or eliminate the amount of cash available for payment of dividends to our holders of common stock or subordinate the claims of our holders of common stock to our assets in the event of our liquidation. Our common stock is not subject to conversion, redemption or sinking fund provisions.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of the Company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover the Company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by law, be the sole and exclusive forum for any (i) derivative action or proceeding brought on behalf of the Company, (ii) action asserting a claim of breach of a fiduciary duty owed by any director, officer or employee of the Company to the Company or our stockholders, (iii) action asserting a claim against the Company or any director or officer of the Company arising pursuant to any provision of the Delaware General Corporation Law or our governing documents, or (iv) action asserting a claim against the Company or

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any director, officer or employee of the Company, which claim is governed by the internal affairs doctrine. Notwithstanding the foregoing sentence, the federal district courts of the United States of America shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under U.S. federal securities laws, including the Securities Act and the Exchange Act. This choice of forum may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our governing documents inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our financial condition, results of operations, and cash flows.

The price of our common stock has fluctuated substantially and may fluctuate substantially in the future.

The market price of our common stock has experienced volatility and may fluctuate significantly in response to a number of factors, many of which we cannot predict or control, including supply of and demand for natural gas and NGLs and the prices of natural gas and NGLs, the level of global drilling, exploration and production activities, general market and economic conditions, disruptions, downgrades, credit events and perceived problems in the credit markets; actual or anticipated variations in our operating results; changes in our investments or asset composition; write-downs or perceived credit or liquidity issues affecting our assets; market perception of our business and our assets; reports by industry analysts; changes in our financial guidance or negative announcements by our customers, competitors or suppliers regarding their own performance; our level of indebtedness or adverse market reaction to any indebtedness that we may incur in the future; our ability to raise capital on favorable terms or at all; loss of any major funding source; additions or departures of our executive officers or key personnel; changes in market valuations of similar companies; and speculation in the press or investment community.

Securities markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. Any broad market fluctuations may adversely affect the trading price of our common stock.

Our ability to utilize U.S. net operating loss and Section 163(j) carryforwards to reduce future U.S. taxable income could be limited.

We and our subsidiaries have U.S. NOL and Section 163(j) interest expense carryforwards for U.S. federal income tax purposes. Our ability to utilize such NOL and Section 163(j) interest expense carryforwards would be limited under Section 382 of the Code (“Section 382”), if we experience an “ownership change,” which generally will occur if the direct or indirect ownership of our stock by one or more stockholders or groups of stockholders that are deemed to own at least 5% of our stock cumulatively increases by more than 50 percentage points at any time during a rolling three-year period. As of December 31, 2025, we do not believe that our NOL and Section 163(j) interest expense carryforwards are currently subject to the limits of Section 382. However, future issuances of our stock or the capital stock of Banpu and other sales or exchanges of our stock or the capital stock of Banpu could trigger an ownership change and, thus, a limitation on our ability to utilize NOL carryforwards under Section 382. Such limitation could result in an increase in our U.S. federal income tax liability.