BKV 10-K & 10-Q changes, risk factors and insider trading

The following risk factors should be considered in evaluating our business and future prospects, in addition to other information included in this Annual Report.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.

• 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 armed conflicts between Russia and Ukraine and Israel and Hamas, and associated economic sanctions on Russia and conditions in China, the Middle East, Africa,South America, Russia, Ukraine, and South AmericaChina;

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

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, 20222023 through December 31, 2024,2025, 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 average in 20222023, was2024 $6.45and 2025 were$2.57 per MMBtu, which trended higher due to production freeze-offs and high net withdrawals of natural gas from storage. In 2023 and 2024, natural gas spot prices averaged $2.57 per MMBtu and $2.21 per MMBtu, and $3.52 per MMBtu, respectively, aswith a2024 resultbeing 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 a warmer-than-normal winters, increased U.S.2025, natural gas supply,prices androse adue combinationto ofweather higherimpacts productionsuch andas higherthe storagepolar inventories given these mild winters.vortex.

A substantial percentage of our natural gas and NGL production is gathered, processedprocessed, 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%, 61%, and 69%,61%, for the years ended December 31, 2025, 2024, 2023, and 2022,2023, 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 EnLinkONEOK 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 credit worthinesscreditworthiness 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.

The present value of future net revenues from our proved natural gas, NGLNGL, 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 iswill 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:

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 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 as well as the pace of drilling and completion of new wells.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.

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 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 hurricaneshurricanes, floods, fires, tornadoes, droughts, hurricanes, tropical storms, and other severe weathercold conditions, or pandemics such as the COVID-19 pandemic or regulatory action related thereto.weather.

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.

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

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

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

We 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 mayincurred besignificant requiredcosts toin makeconnection additional capital contributions towith the BKV-BPP Power Joint Venture.Venture Transaction.

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, 2024,2025, BKV-BPP Power had unrealized losses of $13.2$19.6 million on its derivative instruments as a result of increased power prices; of the $13.2$19.6 million, $5.5$13.3 million of these losses pertain to twofour 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.

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

Our retail energy business is operated through BKV-BPP Retail, a wholly-owned subsidiary of the BKV-BPP Power Joint VentureVenture. inAs whichof December 31, 2025, we and BPPUS each have aowned 50% interest.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 whichthat werequires dothe notconsent control.of BPPUS for certain material actions.”

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 to imposeimposing additional regulations on the retail business and increaseincreasing 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.

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 EagleEast FordTexas 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 EnLink,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 the enhanced Section 45Q tax credits implemented by the Inflation Reduction Act of 2022.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 EagleEast FordTexas 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 EnLink,ONEOK, or successfully develop the Eagle Ford Project and the Cotton Cove Project with BPPUSBPPUS, and the EagleEast FordTexas Project, or any future potential CCUS projects, depends on a number of factors that we are not able to fully control, including the following:

• 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 theany EPAgreenhouse mandatorygas Greenhousereporting Gas Reporting Program.requirements.

• 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.

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 termnear-term and long termlong-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.

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 termnear-term and long termlong-term net zero goals on our anticipated time frame or at all, as well as on our liquidity, financial condition, and results of operations.

•Production of natural gas, NGLs, and oil was 288.4305.0 Bcfe.Bcfe, or 835.5 MMcfe/d.

•Net income (loss)attributable to BKV was $(142.9)$173.1 million.

___________________________________ (1)Impact of derivatives prices excludes $13.3 million and $46.7 million of gains on derivative contract terminations for the years ended December 31, 2024 and 2023, respectively, and $158.4 million of losses on derivative contract terminations for the year ended December 31, 2022.respectively.

Our operating revenues and other income from operations include the activityrevenues from the sale of natural gas, NGLs, and oil, midstream revenues, gains and losses on our derivative contracts and on the sales of our business and assets, marketing revenues, Section 45Q tax credits, related party revenues, and other income from operations. The following table provides information on our revenues and other operating income for the periods presented:

Our natural gas revenues decreasedincreased by approximately $124.4$289.6 million, or 24%,75%, to $675.1 million for the year ended December 31, 2025, from $385.5 million for the year ended December 31, 2024, from $509.8 million for the year ended December 31, 2023.2024. The impact of commodity price decreases,increases, excluding the effect of derivative settlements, provided a $81.4$265.6 million decreaseincrease in year-over-year revenues (calculated as the change in the year-over-year average price times current year's production volumes). The decreaseincrease was also due to lowerhigher production volumes during the year ended December 31, 2024, primarily from the assets from the Exxon Barnett Acquisition, and from the sale of Chaffee and certain non-operated assets held by Chelsea,2025, which collectively accounted for a $43.0$24.0 million decreaseincrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price).

Our NGL revenues decreasedincreased by approximately $22.4$7.6 million, or 12%,5%, to $173.1 million for the year ended December 31, 2025, from $165.5 million for the year ended December 31, 2024, from $187.9 million for the year ended December 31, 2023.2024. The decreaseincrease was due to lowerhigher production volumes during the year ended December 31, 2024,2025, which accounted for a $12.4$5.5 million decreaseincrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price). The decreaseincrease was also due to the impact of commodity price decreases,increases, excluding the effect of derivative settlements, which accounted for a $10.0$2.1 million decreaseincrease in year-over-year revenues (calculated as the change in the year-over-year average price times current year's production volumes).

Our oil revenues decreasedincreased by approximately $1.8$2.9 million, or 22%,43%, to $9.5 million for the year ended December 31, 2025, from $6.6 million for the year ended December 31, 2024, from $8.4 million for the year ended December 31, 2023.2024. The decreaseincrease was due to lowerhigher production volumes during the year ended December 31, 2024,2025, which accounted for a $1.6$4.4 million decreaseincrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price). The decreaseincrease was alsooffset due toby the impact of commodity price decreases, excluding the impacteffect of derivative settlements, which accountaccounted for a $0.2$1.5 million decrease in the year-over-year revenues (calculated as the change in the year-over-year average price times current year's production volumes).

Our midstream revenues decreased by approximately $3.6$2.1 million, or 22%,17%, to $10.5 million for the year ended December 31, 2025, from $12.6 million for the year ended December 31, 2024, from $16.2 million for the year ended December 31, 2023.2024. This decrease was primarily due to the divestiture of Chaffee of $2.6$2.0 million as we sold our Repsol Midstream Interest in connection with this sale. The remainder of the decrease was due to changes in deal structures that reduced midstream transportation revenue while increasing third party gas sales.

Our marketing revenues increased by approximately $2.0 million to $10.7 million for the year ended December 31, 2024 from $8.7 million for the year ended December 31, 2023. Our marketing revenues are derived under our marketing agreement with a third party pursuant to which we receive a fixed percentage of all net income realized in the resale of our and other producers’ hydrocarbons. Our marketing revenues increased by $1.6 million to $12.3 million for the year ended December 31, 2025 from $10.7 million for the year ended December 31, 2024. The increase in marketing revenues during the year ended December 31, 20242025 was primarily due to coldera thanhigher normalpricing weatherenvironment incompared NEPA forto the monthyear ofended JanuaryDecember 31, 2024.

For the year ended December 31, 2025, we did not sell any businesses or subsidiaries. For the year ended December 31, 2024, we sold our wholly-owned subsidiary, Chaffee, for $104.4 million, net of third partythird-party transaction costs. The assets sold had an approximate carrying value of $97.3 million, which resulted in a gain on the sale of Chaffee of $7.1 million.

Gains (Losses) on Sales of AssetsAssets, Net

WeOther generaterevenues, awhich portionprimarily of our revenues fromincludes the sale of third-partythird naturalparty gas. Other revenuesgas, was $11.7 million for the year ended December 31, 2025 compared to $6.6 million for the year ended December 31, 2024 compared to $4.0 million for the year ended December 31, 2023.2024. The year-over-year increase year-over-year was primarily due to an increase in third party gas salesprices ofand $2.7contracted million.rates.

Taxes other than income were $50.8 million, or $0.17 per Mcfe, for the year ended December 31, 2025, which was an increase of $15.8 million, or 45%, from $35.0 million, or $0.12 per Mcfe, for the year ended December 31, 2024, which was a decrease of approximately $37.3 million, or 52%, from $72.3 million, or $0.23 per Mcfe, for the year ended December 31, 2023.2024. The decreaseincrease in taxes other than income during the year ended December 31, 20242025, compared to 20232024, was due to increases in production taxes of $16.0 million in the Barnett, which includes increases of $1.6 million in production taxes from the BKV Barnett II from the Bedrock Acquisition, and increases of $0.6 million in severance taxes related to our NEPA natural gas properties. BKV Barnett II also incurred $0.5 million of ad valorem taxes during the year ended December 31, 2025. This was offset by decreases in ad valorem and property taxes, and natural gas and NGL production taxes, bothtaxes associated with our operations in the Barnett of $27.8$1.4 million and $9.2 million, respectively.million. Certain ad valorem and production taxes are not applicable to our NEPA properties.

Depreciation, depletion, amortization, and accretion was $157.5 million, or $0.52 per Mcfe, for the year ended December 31, 2025, which was a decrease of $60.1 million, or 28%, from $217.5 million, or $0.75 per Mcfe, for the year ended December 31, 2024, which was a decrease of approximately $5.8 million, or 3%, from $223.4 million, or $0.71 per Mcfe, for the year ended December 31, 2023.2024. The decrease in depreciation, depletion, amortization, and accretion during the year ended December 31, 20242025, compared to the year ended December 31, 20232024, was primarily due to lowera productiondepletion duringrate the year ended December 31, 2024 compared to the same periodadjustment in the2025, priorwhich year,was offsetdriven by lowerhigher estimated proved reserves resulting from lower natural gas prices used in the determination of proved reserves and from the divestiture of Chaffee and certain non-operated upstream assets in Chelsea in June 2024.reserves.

Gains on contingent consideration liabilities. WeFor the year ended December 31, 2024, we recognized a gain on contingent consideration liabilities accruing as an earnout obligation under the purchase agreements executed in connection with the Devon Barnett Acquisition and the Exxon Barnett Acquisition. The gain on contingent consideration liabilities was $9.7 million,million for the year ended December 31, 2024, whichconsisting wasof a decreasegain of approximately$7.5 $28.7million and a gain of $2.2 million from the $38.4 million gain for the year ended December 31, 2023. The $9.7 million gain compared to the $38.4 million gain was primarily attributable to the prior period’s gain on contingent consideration liabilities with the Devon Barnett Acquisition of $25.0 million compared to the current period's gain of $7.5 million, as well as the prior period's gain on contingent consideration liabilities withand the Exxon Barnett AcquisitionAcquisition, ofrespectively. $13.4The millioncontingent comparedconsideration toprovisions theunder currentthese period'spurchase gainagreements of $2.2 million. There were higher gainsexpired in the prior period due to a significant decrease in the forward curve commodity pricing for natural gas (NYMEX) and oil (WTI) assumptions used in the Monte Carlo simulations during the year ended December 31, 2023 compared to slight decreases during the year ended December 31, 2024.

Earnings (losses) from equity affiliate. Earnings from our equity affiliate was $14.9 million for the year ended December 31, 2025, which was an increase of $4.5 million, from $10.4 million for the year ended December 31, 2024, which was a decrease of $6.4 million, from $16.9 million compared to the year ended December 31, 2023.2024. Earnings from our equity affiliate is related to our investment in, and our proportionate share in the income or losses of the BKV-BPP Power Joint Venture.

Loss on early extinguishment of debt. Loss on early extinguishment of debt was $13.9 million for the year ended December 31, 20242024, in connection with the early termination of our Term Loan Credit FacilityAgreement and Revolving Credit Agreement that took place in June 2024.

Interest expense. Interest expense was $28.6 million for the year ended December 31, 2025, which was a decrease of $16.9 million, from $45.6 million for the year ended December 31, 2024, which was a decrease of $24.4 million, from $69.9 million for the year ended December 31, 2023.2024. The decrease in interest expense during the year ended December 31, 20242025, was primarily due to lower interest rates and a lower outstanding balance on our RBL Credit Facility,Agreement, which we entered into on June 11, 2024, and thesubsequently subsequent paypaid down on the outstanding balances on our SCB Credit Facility, the Revolving Credit Agreement, and the Term Loan Credit Agreement, which incurred higher interest rates.

Interest expense, related party. Interest expense from our related party borrowings with BNAC was $5.2 million for the year ended December 31, 2024, which was arepaid decreasein ofSeptember $1.92024. million,We fromdid $7.1not millionhave for the year ended December 31, 2023. The decrease was due to the pay down of $75.0 million ofany related party borrowings with BNAC during the year ended December 31, 2024, slightly offset by the increase in interest rates year-over-year.2025.

Income tax benefit (expense). For the year ended December 31, 2024,2025, we had an income tax benefitexpense of $43.6$35.4 million, which was a change of $71.8$79.0 million, from an income tax expensebenefit of $28.2$43.6 million for the year ended December 31, 2023.2024. The year-over-year change was primarily due to a pre-tax income for the year ended December 31, 2025 compared to a pre-tax loss for the year ended December 31, 2024 compared to a pre-tax income for the year ended December 31, 2023. During the year ended December 31, 2024, we also recognized additional income tax expense due to executive compensation disallowance, which was offset by a tax benefit from the monetization of Section 45Q tax credits associated with the injection of CO2 waste in the Barnett Zero Project, Code Section 45I Marginal Well Credits from marginal production, excess tax benefits relating to the vesting of restricted shares, and by state apportionment changes due to the sale of Chaffee.2024.

Our operating revenues and other income from operations include the activity from the sale of natural gas, NGLs, and oil, midstream revenues, gains and losses on our derivative contracts and on the salesales of our business and assets, marketing revenues, Section 45Q tax credits, related party revenues, and other income from operations. The following table provides information on our revenues and other operating income for the periods presented:

Our natural gas revenues decreased by approximately$124.4 $800.5million, or 24%, to $385.5 million tofor the year ended December 31, 2024, from $509.8 million for the year ended December 31, 2023, from $1.3 billion for the year ended December 31, 2022.2023. The impact of commodity price decreases, excluding the effect of derivative settlements, resulted inprovided a $994.3$81.4 million decrease in year-over-year revenues (calculated as the change in the year-over-year average price times current yearyear's production volumes). ThisThe decrease was offsetalso bydue higherto lower production volumes, primarily from the 2022 Barnett Assets,volumes during the year ended December 31, 2023,2024, primarily from the assets from the Exxon Barnett Acquisition, and from the sale of Chaffee and certain non-operated assets held by Chelsea, which collectively accounted for a $193.8$43.0 million increasedecrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior yearyear's average price).

Our NGL revenues decreased by approximately$22.4 $123.7million, or 12%, to $165.5 million tofor the year ended December 31, 2024, from $187.9 million for the year ended December 31, 2023,2023. fromThe $311.5decrease millionwas fordue to lower production volumes during the year ended December 31, 2022.2024, which accounted for a $12.4 million decrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price). The decrease was also due to the impact of commodity price decreases, excluding the effect of derivative settlements, providedwhich accounted for a $134.9$10.0 million decrease in year-over-year revenues (calculated as the change in the year-over-year average price times current periodyear's production volumes). This was offset by higher production volumes, primarily from the 2022 Barnett Assets, during the year ended December 31, 2023, which accounted for a $11.2 million increase in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year average price).

Our oil revenues decreased by approximately$1.8 $3.4million, or 22%, to $6.6 million tofor the year ended December 31, 2024, from $8.4 million for the year ended December 31, 2023 from $11.9 million for the year ended December 31, 2022.2023. The decrease was drivendue byto lower production volumes during the year ended December 31, 2023,2024, which accounted for a $1.8$1.6 million decrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior yearyear's average price). The decrease was also due to the impact of commodity price decreases, excluding the effectimpact of derivative settlements, which resultedaccounted infor a $1.6$0.2 million decrease in the year-over-year revenues (calculated as the change in the year-over-year average price times current periodyear's production volumes).

The Quarterly Report on Form 10-Q should be read in conjunction with the “Risk Factors” disclosed in our 2025 Annual Report on Form 10-K, which could materially affect our business, financial condition, or future results. There have been no material changes to the risk factors previously disclosed in the 2025 Annual Report on Form 10-K.10-K and subsequent Quarterly Reports on Form 10-Q.

Below are some highlights of our operating and financial results for the three and six months ended MarchJune 31,30, 2026:

•Production of natural gas, NGLs, and oil was 83.389.0 Bcfe, or 925.0978.3 MMcfe/d and 172.3 Bcfe, or 951.8 MMcfe/d, respectively.

•Average realized product prices, excluding the impact of settled derivatives, waswere $3.46$2.49 per Mcfe.Mcfe and $2.96 per Mcfe, respectively.

•Power generation of 1,9812,222 GWh and 4,203 GWh, respectively, from the Temple Plants and capacity factorfactors of 62.4%.69.6% and 66.0%, respectively.

•Upstream/Midstream production revenues were $287.7$221.9 million and $509.6 million, respectively, and Power revenues were $69.0$74.4 million.million and $143.4 million respectively.

•Net income attributable to BKV was $44.1$75.8 million.million and $119.9 million, respectively.

•Net cash provided by operating activities for the threesix months ended MarchJune 31,30, 2026 was $72.0$181.7 million.

•Accrued capital expenditures for the threesix months ended MarchJune 31,30, 2026 were $118.6$191.0 million.

Commodity Pricing. The natural gas, NGL, and power industries are each cyclical and seasonal, and commodity prices are highly volatile, and we expect these prices to continue to remain volatile in the near future. In order to manage our market exposure ofto price volatility, we utilize derivative contracts in connection with our operations to provide an economic hedge of our exposure to commodity price risks associated with anticipated future natural gas and NGL production and power generation. However, there are still market risks beyond our control that may impact our financial condition, results of operations, and cash flows.

In September 2025, we completed the Bedrock Acquisition, with an economic effective date of July 1, 2025. The acquisition significantly expanded our asset base in the Barnett with low-decline proved developed producing reserves, resulting in higher production volumes, revenues, operating expenses, depreciation, depletion and amortization, and asset retirement obligations beginning in the third quarter of 2025. Because the acquired assets were not owned for a full period of 2025, results for 2026 are not comparable to prior periods. In addition, the consideration paid, including cash, common stock, and repayment of indebtedness, affected our liquidity, leverage, and weighted-averageweighted average shares outstanding.

Comparison of the Three Months Ended MarchJune 31,30, 2026 and 2025:

Our natural gas revenues slightly increased by approximately $72.2$0.5 million, or 43%, to $240.2$156.1 million for the three months ended MarchJune 31,30, 2026, from $168.0$155.6 million for the three months ended MarchJune 31,30, 2025. The increase was due to higher production volumes during the three months ended MarchJune 31,30, 2026, which accounted for a $43.4$38.6 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price). The impactincrease was alsooffset due toby commodity price increases,decreases, excluding the effect of derivative settlements, which provided a $28.8$38.0 million increasedecrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes).

Our oil revenues decreasedincreased by approximately $0.7$2.3 million, or 20%,92%, to $2.8$4.9 million for the three months ended MarchJune 31,30, 2026, from $3.5$2.5 million for the three months ended MarchJune 31,30, 2025. The decreaseincrease was primarily due to lower production volumes during the three months ended March 31, 2026, which accounted for a $0.9 million decrease in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price). The decrease was offset by the impact of commodity price increases, excluding the effect of derivative settlements, which accounted for a $0.2$1.6 million increase in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes). The increase was also due to higher production volumes during the three months ended June 30, 2026, which accounted for a $0.7 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).

For the three months ended MarchJune 31,30, 2026, our Upstream/Midstream segment had net realized and unrealized lossesgains on derivative contracts of $42.5$95.3 million,million compared to net realized and unrealized losses of $152.2$112.2 million for the same period in 2025. The decrease in lossesgains for the three months ended MarchJune 31,30, 2026, was primarily attributable to our open derivative positions, which were in an unrealized lossgain position of $16.1$56.0 million, compared to an unrealized lossgain position of $134.0$102.9 million for the same period in 2025. The current period primarily reflects slight increasesdecreases in the forward curve of natural gas prices relative to Decemberthe 31,previous 2025,quarter, whereas the prior year period reflected highersignificant increasesdecreases in future natural gas prices compared to December 31, 2024. In addition, we purchased put options of $16.2 million in the first quarter of 2025, limiting our 2026/2027 pricing downside. Increasing the derivative losses for the three months ended March 31, 20262025. wereOffsetting the decrease in derivative gains, net was our realized lossesgains of $26.3$39.3 million, compared to realized losses of $18.2$9.3 million for the three months ended MarchJune 31,30, 2025, which were due to slightly higherlower natural gas prices settled in the current period compared to the same period in the prior year.

Our marketing revenues arewere derived under our marketing agreement with a third party pursuant to which we receivereceived a fixed percentage of all net income realized in the resale of our and other producers'producers’ hydrocarbons. OurDuring the three months ended June 30, 2026, we began marketing all of our own natural gas production, causing our marketing revenues increasedto increase by approximately $7.9$19.2 million to $17.6$26.2 million for the three months ended MarchJune 31,30, 2026, from $9.7$7.0 million for the three months ended MarchJune 31,30, 2025. The increase in marketing revenues during the three months ended March 31, 2026, was primarily due to a higher pricing environment and more volumes sold compared to the same period in 2025.

Other revenues includesinclude the gain (loss) on sale of assets, which werewas $0.1a gain of $0.3 million for the three months ended MarchJune 31,30, 2026, compared to $1.3$0.1 million for the same period in 2025. The period-over-period increase was primarily due to a gain on sale of assets of $0.1 million during the three months ended March 31, 2026, compared to a loss on sale of assets of $1.4 million during the three months ended March 31, 2025.

Lease operating and workover expenses were $45.1$44.5 million, or $0.54$0.50 per Mcfe, for the three months ended MarchJune 31,30, 2026, which was an increase of approximately $10.0$10.3 million, or 29%,30%, from $35.1$34.2 million, or $0.51$0.46 per Mcfe, for the three months ended MarchJune 31,30, 2025. The increase in lease operating and workover expenses during the three months ended MarchJune 31,30, 2026, compared to the same period in 2025, was primarily attributable to $10.2 million of lease operating and workover expenses associated with BKV Barnett II, which was acquired in connection with the Bedrock Acquisition in September 2025.

Taxes other than income were $16.0$11.6 million, or $0.19$0.13 per Mcfe, for the three months ended MarchJune 31,30, 2026, which was ana increasedecrease of approximately $5.7$1.8 million, or 56%,14%, from $10.2$13.4 million, or $0.15$0.18 per Mcfe, for the three months ended MarchJune 31,30, 2025. The increasedecrease was primarily driven by highera $2.9 million production tax refund and a $0.3 million reduction in production taxes. These decreases were offset by a $1.0 million increase in production taxes in the Barnett of $4.1 million, including $2.1 million attributable to BKV Barnett II. In addition, adAd valorem and property taxes in the Barnettalso increased by $1.7$0.5 million, reflectingprimarily higherdue gasto prices,a of which $0.4$0.9 million wasincrease attributable to BKV Barnett II.II, partially offset by lower assessed values reflecting lower natural gas prices.

Gathering and transportation expenses were $67.8$68.1 million, or $0.81$0.76 per Mcfe, for the three months ended MarchJune 31,30, 2026, which was an increase of approximately $12.0$5.1 million, or 22%,8%, from $55.8$63.0 million, or $0.81$0.85 per Mcfe, for the three months ended MarchJune 31,30, 2025. This increase was primarily driven by $11.6 million and $0.8 million of higher costs associated with natural gas and NGL production ofvolumes, $11.9respectively and $0.4 million andof $1.1 million, respectively, and natural gasNGL rate increases of $0.3 million.increases. These increases were offset by NGL$8.1 million of natural gas rate decreases of $0.9 million and decreases in gathering costs associated with our midstream business of $0.4 million.decreases.

Depreciation, depletion, amortization, and accretion was $40.7$42.8 million, or $0.49$0.48 per Mcfe, for the three months ended MarchJune 31,30, 2026, which was an increase of approximately $1.2$5.2 million, or 3%,14%, from $39.5$37.6 million, or $0.58$0.51 per Mcfe, for the three months ended MarchJune 31,30, 2025. The increase was primarily dueattributable to an additional $3.4 million of expense related to BKV Barnett II, which was acquired in connection with the Bedrock Acquisition in September 2025. The remainder of the increase was driven by higher production volumes, partially offset by a lower depletion rate resulting from an increase in our proved reserves in the current period compared to the same period in 2025.reserves.

General and administrative expenses were $21.9$22.7 million, or $0.26 per Mcfe, for the three months ended MarchJune 31,30, 2026, which was an increase of approximately $11.7$8.0 million, from $10.2$14.8 million, or $0.15$0.20 per Mcfe, for the three months ended MarchJune 31,30, 2025. The increase was primarily attributable to Company-wide growth initiatives, including higher headcountinformation technology costs, employee and employee expenses,office, and an increase in consulting and informationcontracting technology expenses,costs, which resulted in increased corporate allocations to the Upstream/Midstream segment.

Other operating expenses were $8.9$1.4 million, or $0.11$0.02 per Mcfe, for the three months ended MarchJune 31,30, 2026, which was ana increasedecrease of approximately $4.8$2.0 million, from $4.0$3.4 million, or $0.06$0.05 per Mcfe, for the three months ended MarchJune 31,30, 2025. The increasedecrease in other operating expenses during the three months ended MarchJune 31,30, 2026, compared to the same period in 2025, was dueattributable to a $2.9$2.1 million increasedeficiency payment incurred in integration and transaction costs primarily due to the Bedrockprior Acquisition, a $1.0 million reduction in emissions costs in 2025, and an increase of $0.9 million in gas purchases due to higher gas prices.year.

Comparison of the Three Months Ended MarchJune 31,30, 2026 and 2025:

During the three months ended MarchJune 31,30, 2026, our Power revenues were $69.0$74.4 million, which was an increase of $12.4 million, or 20%, from $61.9 million compared to $43.9 million duringfor the three months ended MarchJune 31,30, 2025, which include merchant energy sales and revenue from our retail business. The increase was primarily due to the increase in merchant energy sales, which was attributable to higher power prices, power generation,generation and capacity at the Temple Plants.

Fuel commodity costs were $57.1$42.8 million for the three months ended MarchJune 31,30, 2026, which was an increase of $10.8$3.0 million, or 23%,7%, from $46.4$39.9 million for the three months ended MarchJune 31,30, 2025. The increase was due to higher fuel consumption compared to the same period in 2025.

Purchased power costs for the retail business were $27.4$29.5 million for both the three months ended MarchJune 31,30, 2026,2026 which was an increase of $8.7 million, or 47%, from $18.7 million for the three months ended March 31,and 2025. ThePurchased increasepower wascosts primarily driven by our net realized and unrealized loss position on theinclude power derivatives, which waswere $13.0in milliona net gain position of $0.2 million, compared to a net realizedloss and unrealized lossposition of $4.4$3.3 million for the same period in 2025.million. As the retail power derivatives are in a long position, increasesdecreases in market prices reducedrelative the spread betweento fixed contract prices and settlement prices, which resultedresult in gains. This was offset by an increase in purchased power due to slightly higher realizedsales losses.from our retail business.

Taxes other than income were $4.2$4.3 million for the three months ended MarchJune 31,30, 2026, which was a decrease of approximately $0.3 million, or 7%, from $4.6 million for the three months ended MarchJune 31,30, 2025. The decrease was driven by BKV-BPP Power's property tax reassessment.

Power operating and maintenance expenses are costs incurred to run the Temple Plants and remained relatively consistent period-over-period.Plants. These expenses were $19.7$17.2 million for the three months ended MarchJune 31,30, 2026, which was a decrease of approximately $0.5$1.1 million, or 3%,6%, from $20.2$18.3 million for the three months ended MarchJune 31,30, 2025. The decrease was primarily due to a $1.3 million decrease in planned maintenance period-over-period.

General and administrative expenses were $6.7$7.6 million for the three months ended MarchJune 31,30, 2026, which was an increase of approximately $1.5$3.4 million, from $5.2$4.3 million for the three months ended MarchJune 31,30, 2025. The increase was primarily attributable to Company-widehigher growthallocations initiatives,of includingcorporate general and administrative costs and higher headcountadministrative andservice employeeexpenses expenses,charged andby BKV under the administrative services agreement due to an increase in consultingcontracted andrates. informationThese technologyincreases expenses,were which resulted in increased corporate allocations to the Power segment. This waspartially offset by a $2.6 million decrease in lower credit loss expense with BKV-BPP Retail customers as the prior year period included significant write-offs related to 2024 and 2025 customer balances.expense.

Other operating expenses were $4.2$4.9 million for the three months ended MarchJune 31,30, 2026, which was an increase of approximately $3.8$4.5 million, from $0.4 million for the three months ended MarchJune 31,30, 2025. The increase was due to $3.7$4.3 million in transaction costs related to the BKV-BPP Power Joint Venture Transaction.

Our Section 45Q tax credits decreasedincreased by approximately $0.2$0.5 million, or 7%,18%, to $3.1$3.0 million during the three months ended MarchJune 31,30, 2026, from $3.3$2.6 million during the three months ended MarchJune 31,30, 2025. Our Section 45Q tax credits related to CO2 waste sequestration activities under our Barnett ZeroZero, Project.Cotton Cove and Eagle Ford projects. The decreaseincrease period-over-period was due to lessmore CO2 waste sequestered in 2026,2026 reflectingdue routineto fluctuationsCotton Cove and Eagle Ford injections beginning in activitythe levelsfirst that occur as parthalf of our normal operations.2026.