BKV Corp: Form 10-Q for the period ended Sep 30, 2025

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included in Item 1 of Part I, Financial Statements in this report on Form 10-Q and our audited consolidated financial statements and related notes, including “Management's Discussion and Analysis of Financial Condition and Results of Operations” for the year ended December 31, 2024 included in our 2024 Annual Report on Form 10-K filed on March 31, 2025. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expectations. We disclaim any duty to publicly update any forward-looking statements except as otherwise required by applicable law.

In this section, references to “BKV,” the “Company,” “we,” “us,” and “our” refer to BKV Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires. For more information on our organizational structure, see Note 1 - Business and Basis of Presentation to our condensed consolidated financial statements included in Item 1 of Part I of this report.

Overview

We are a forward thinking, growth driven energy company focused on creating value for our stockholders through the organic development of our properties as well as accretive acquisitions. Our core business is to produce natural gas from our owned and operated upstream businesses, which are supported by our four business lines: natural gas production; our natural gas midstream business; power generation; and CCUS. We expect our owned and operated upstream and natural gas midstream businesses to achieve net zero Scope 1 and Scope 2 emissions by the early 2030s, and net zero Scope 1, 2, and 3 emissions by the late 2030s. We maintain a “closed-loop” approach to our net zero emissions goal through the operation of our four business lines. We are committed to vertically integrating portions of our business to reduce costs and improve overall commercial optimization of the full value chain. For instance, in the Barnett, our natural gas production is gathered and transported in part through our midstream systems and we commenced sequestration operations at our first CCUS project in November 2023. We expect our second and third CCUS projects to commence sequestration activities in the first half of 2026 and are evaluating a robust backlog of actionable CCUS opportunities. We believe that our differentiated business model, net zero emissions focus, highly experienced management team and technology-driven approach to operating our business will enable us to create stockholder value.

Recent Developments

• BKV-BPP Power Joint Venture Transaction. On October 29, 2025, BKV entered into a membership interest purchase agreement with BPPUS to acquire one-half of the limited liability company interests of BPP-BPP Power currently held by BPPUS for aggregate consideration of (x) $376.0 million less (y) 25% of the net indebtedness of BKV-BPP Power at the closing, which consideration will be paid 50% in cash and 50% in BKV common stock. As of September 30, 2025, the net indebtedness of BKV-BPP Power was approximately $581.8 million. The number of shares of common stock to be issued at the closing will be determined by dividing the amount equal to 50% of the purchase price by $21.6609, which is the volume-weighted average price BKV common stock during the 20 consecutive trading-day period ended October 28, 2025. BPPUS has agreed not to dispose of the stock consideration for a period of 180 days following the date on which the stock consideration is delivered to BPPUS. We plan to fund the cash consideration for the acquisition with a combination of cash on hand and borrowings under our RBL Credit Agreement. Upon the closing of the BKV-BPP Power Joint Venture Transaction, BKV-BPP Power will be owned 75% by BKV and 25% by BPPUS, and BKV will consolidate the financial results of BKV-BPP Power into BKV’s consolidated financial results. The BKV-BPP Power Joint Venture Transaction is expected to close in the first quarter of 2026, subject to certain closing conditions, including approval by at least 75% of the disinterested shareholders of Banpu Power, the sole shareholder of BPPUS, represented at the meeting to be called for such purpose.
• Bedrock Acquisition. On September 29, 2025, BKV Upstream Midstream completed the previously announced Bedrock Acquisition. Upon the closing of the Bedrock Acquisition, we acquired approximately 99,000 net acres, or 108 MMcfe/d of production (approximately 63% natural gas), 1,121 producing locations, nearly 1 Tcfe of 1P reserves (using NYMEX strip pricing), and 50 new drill locations with an assumed 10,000 lateral length with accretive natural gas price break-evens compared to our existing inventory, and 80 low cost refrac locations. For additional information see Note 2 - Acquisition.
• 2030 Senior Notes. On September 26, 2025, BKV Upstream Midstream issued in a private placement $500.0 million of its 2030 Senior Notes due October 15, 2030. The 2030 Senior Notes were issued at par and resulted in proceeds of $490.0 million, after deducting underwriters’ discounts and commissions. The proceeds were used to repay a

portion of the outstanding borrowings under the RBL Credit Agreement and fund a portion of the cash consideration for the Bedrock Acquisition. For additional information regarding the 2030 Senior Notes and the covenants contained therein, see Note 3 - Debt and under “Liquidity and Capital Resources —2030 Senior Notes.”

• Write-Off of Enterprise Resource Planning (“ERP”) System. On July 31, 2025, management made the strategic decision to pause its ERP system implementation, which began development in the fourth quarter of 2024. The decision was driven by Company growth and a strategic reassessment of our evolving operational and financial needs. As of September 30, 2025, we wrote off the majority of our capitalized software costs and other related costs of approximately $5.6 million related to the ERP implementation. As of November 10, 2025, we are in the process of evaluating ERP systems that better align with our company-needs.

Operational and Financial Highlights

Below are some highlights of our operating and financial results for the three and nine months ended September 30, 2025:

• Production of natural gas, NGLs, and oil was 76.2 Bcfe, or 828.5 MMcfe/d and 218.5 Bcfe, or 800.4 MMcfe/d, respectively.
• Average realized product prices, excluding the impact of settled derivatives, were $2.52 per Mcfe and $2.78 per Mcfe, respectively.
• Production revenues were $192.4 million and $608.3 million, respectively, and midstream revenues were $2.6 million and $8.1 million, respectively.
• Lease operating expense was $34.8 million, or $0.46 per Mcfe and $101.1 million, or $0.46 per Mcfe, respectively.
• Net income attributable to BKV was $76.9 million and $102.8 million, respectively.
• Net cash provided by operating activities for the nine months ended September 30, 2025 was $173.3 million.
• Accrued capital expenditures for the nine months ended September 30, 2025 were $216.4 million.

Factors That Affect Comparability of Our Financial Condition and Results of Operations

Our business depends on many factors, primarily commodity prices, market supply and demand for natural gas, NGLs, and oil, upstream capital costs, and production costs. We continually monitor domestic and global factors which may cause our actual results of operations to differ from historical results or expected outlook.

Commodity Pricing. The natural gas and NGL industry is cyclical 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 of price volatility, we utilize derivative contracts in connection with our natural gas operations to provide an economic hedge of our exposure to commodity price risks associated with anticipated future natural gas and NGL production. However, there are still market risks beyond our control that may impact our financial condition, results of operations, and cash flows.

Supply, Demand, Market Risk, and the Impact on Natural Gas, NGL, and Oil Prices. Natural gas and oil prices are subject to large fluctuations in response to relatively minor changes in the demand for natural gas, NGLs, and oil. Prices are affected by current and expected supply and demand dynamics, including the level of drilling, completion, and production activities by other natural gas production companies, global industry-wide supply chain disruptions, widespread shortages of labor, material, and services, the ability to agree and maintain production levels by members of OPEC and other oil producing countries, and political instability of other energy producing countries, resulting in increased supply in the global market. Other factors impacting supply and demand include weather conditions (including severe weather events), pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, supply chain quality and availability, strength of the U.S. dollar as well as other factors, the majority of which are outside of our control.

Upstream Capital Costs. Businesses engaged in the exploration and production of natural gas and NGLs, such as ours, face the challenge of natural production declines. As initial reservoir pressures are depleted, natural gas and NGL production from a given well naturally decreases. Thus, as does any natural gas exploration and production company, we deplete part of our asset base with each unit of natural gas and NGLs we produce. We attempt to overcome this natural decline by drilling and refracturing to unlock additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production in a cost-effective manner, through development of existing assets and acquisitions. Our ability to make capital expenditures to increase production from our existing reserves and to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost-effective manner and to timely obtain drilling permits and regulatory approvals.

Other factors significantly affecting our financial condition and results of operations include, among others:

• success in drilling new wells;
• the availability of attractive acquisition opportunities and our ability to execute them;
• the amount of capital we invest in the leasing and development of our properties;
• facility or equipment availability and unexpected downtime; and
• delays imposed by or resulting from compliance with regulatory requirements.

Production Volumes

The following table presents our historical production volumes for the periods presented:

Sources of Revenues

Currently, substantially all of our revenues are derived from the sale of our natural gas production and the NGLs that are extracted from processing our natural gas, though we also generate a portion of our revenues from the sale of crude oil, midstream and surface operations, and certain marketing revenue and other income. Our midstream and surface operations primarily support our own exploration and production operations, with revenues generated primarily from fees charged for midstream and surface services, including transportation, freshwater sourcing and disposal, and other services to us and our affiliates and, to a lesser extent, third parties.

Realized Commodity Prices

NYMEX Henry Hub, for gas prices, and NYMEX WTI, for oil prices, are widely used benchmarks for the pricing of natural gas and oil in the United States. The price we receive for our natural gas and oil production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. As such, our revenues are sensitive to the price of the underlying commodity to which they relate. For further discussion on our derivative contracts, see Note 6 - Derivative Instruments to the unaudited condensed consolidated financial statements. The following is a comparison of average pricing excluding and including the effects of derivatives:

(1) Impact of derivatives prices excludes $13.3 million of gains on derivative contract terminations for the nine months ended September 30, 2024.

Results of Operations

Comparison of the Three Months Ended September 30, 2025 and 2024

Operating Revenues and Operating Income

Our operating revenues and other income from operations include the activity from the sale of natural gas, NGLs, and oil, midstream revenues, gains and losses on our derivative contracts, 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:

(in thousands, other than percentages)

Natural Gas Revenues

Our natural gas revenues increased by approximately $63.1 million, or 72%, to $150.9 million for the three months ended September 30, 2025, from $87.9 million for the three months ended September 30, 2024. The impact of commodity price increases, excluding the effect of derivative settlements, provided a $55.4 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 September 30, 2025, which accounted for a $7.7 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).

NGL Revenues

Our NGL revenues increased by approximately $2.3 million, or 6%, to $39.8 million for the three months ended September 30, 2025, from $37.5 million for the three months ended September 30, 2024. The increase was due to slightly higher production volumes during the three months ended September 30, 2025, which accounted for a $3.0 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price). The increase was slightly offset by commodity price decreases, excluding the effect of derivative settlements, which accounted for a $0.7 million decrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes).

Oil Revenues

Our oil revenues increased by approximately $0.1 million, or 9%, to $1.7 million for the three months ended September 30, 2025, from $1.6 million for the three months ended September 30, 2024. The increase was primarily due to higher production volumes during the three months ended September 30, 2025, which accounted for a $0.4 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price). The increase was offset by the impact of commodity price decreases, excluding the effect of derivative settlements, which accounted for a $0.3 million decrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes).

Midstream Revenues

Our midstream revenues decreased by approximately $0.1 million, or 3%, to $2.6 million for the three months ended September 30, 2025, from $2.7 million for the three months ended September 30, 2024, which is consistent period-over-period.

Derivative Gains, Net

For the three months ended September 30, 2025, we had net realized and unrealized gains on derivative contracts of $74.9 million compared to $35.3 million for the same period in 2024. The increase in gains for the three months ended September 30, 2025, was primarily attributable to our open derivative positions, which were in more of an unrealized gain position of $55.2 million compared to an unrealized loss position of $3.0 million for the same period in 2024. The increase in unrealized gains for the current period primarily reflects decreases in the forward curve of natural gas prices between quarters, whereas unrealized losses the prior year period reflected minimal increases in forward natural gas prices between quarters. The increased gains on our derivative contracts were offset by a decrease in realized gains of $18.7 million to $19.7 million for the three months ended September 30, 2025 compared to realized gains of $38.3 million in the same period in 2024, which were due to higher natural gas prices settled in the current period compared to the same period in the prior year.

Marketing Revenues

Our marketing revenues were $1.7 million for both the three months ended September 30, 2025 and 2024. 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.

Section 45Q Tax Credits

Our Section 45Q tax credits decreased by approximately $0.5 million, or 13%, to $3.7 million during the three months ended September 30, 2025, from $4.3 million during the three months ended September 30, 2024. Our Section 45Q tax credits relate to CO2 waste sequestration activities under our Barnett Zero Project. The period-over-period decrease was due to lower volumes of CO2 waste sequestered in 2025, reflecting routine fluctuations in activity levels that occur as part of our normal operations.

Related Party Revenues

Our related party revenues were $0.4 million for both the three months ended September 30, 2025 and 2024, which was consistent period-over-period. Related party revenues represent fees earned for services provided to BKV-BPP Power under the Administrative Services Agreement.

Other Revenues

Other revenues includes the sale of third-party natural gas, offset by a loss on the sale of assets, which was $2.6 million and $0.5 million, respectively for the three months ended September 30, 2025. This is compared to $1.7 million of third-party gas sold during the three months ended September 30, 2024, which increased from 2024 due to an increase in natural gas prices.

Operating Expenses

Our operating expenses reflect costs incurred in the development, production, and sale of natural gas, NGLs, and oil. The following table provides information on our operating expenses:

(in thousands, other than percentages and average costs)

Lease Operating and Workover

The following table summarizes our components of lease operating expenses for the periods presented:

(in thousands, other than percentages and average costs)

Lease operating and workover expenses were $36.9 million, or $0.49 per Mcfe, for the three months ended September 30, 2025, which was an increase of approximately $3.3 million, or 10%, from the three months ended September 30, 2024, of $33.6 million, or $0.48 per Mcfe. Lease operating expenses during the three months ended September 30, 2025, compared to the same period in 2024, were due to increased project activity with our Pad of the Future program, disposal costs, compressor movement, and fracking offsets.

Taxes Other Than Income

Taxes other than income were $11.6 million, or $0.15 per Mcfe, for the three months ended September 30, 2025, which was an increase of approximately $1.0 million, or 9%, from $10.7 million, or $0.15 per Mcfe, for the three months ended September 30, 2024. The increase in taxes other than income during the three months ended September 30, 2025, compared to 2024, was due to increases in production taxes of $2.9 million in the Barnett. This was offset by decreases in ad valorem and property taxes associated with our operations in the Barnett and NEPA of $2.2 million and $0.3 million, respectively. Certain ad valorem and production taxes are not applicable to our NEPA properties.

Gathering and Transportation

Gathering and transportation expenses in the Barnett were $61.8 million, or $0.81 per Mcfe, for the three months ended September 30, 2025, which was an increase of approximately $7.1 million, or 13%, from $54.7 million, or $0.78 per Mcfe, for the three months ended September 30, 2024. This increase was primarily driven by natural gas and NGL production increases of $5.3 million, and $1.3 million, respectively, and increased natural gas and NGL rate of $0.8 million and $0.1 million, respectively. This was offset by a decrease in the gathering costs on our outsourced contracts with our midstream business of $0.4 million.

Depreciation, Depletion, Amortization, and Accretion

Depreciation, depletion, amortization, and accretion was $37.9 million, or $0.50 per Mcfe, for the three months ended September 30, 2025, which was a decrease of approximately $19.5 million, or 34%, from $57.4 million, or $0.82 per Mcfe, for the three months ended September 30, 2024. The decrease in depreciation, depletion, amortization, and accretion during the three months ended September 30, 2025, compared to the three months ended September 30, 2024, was primarily due to a depletion rate adjustment in 2025, which was driven by higher reserves.

General and Administrative

General and administrative expenses were $30.7 million, or $0.40 per Mcfe, for the three months ended September 30, 2025, which was a decrease of approximately $2.9 million, or 9%, from $33.6 million, or $0.48 per Mcfe, for the three months ended September 30, 2024. The decrease was primarily driven by the reduction of employee-based compensation of $7.7 million. The three months ended September 30, 2024, included $10.6 million of TRSU stock compensation expense under the 2021 Plan post-IPO, partially offset by $2.9 million of stock compensation expense incurred during the three months ended September 30, 2025, under the 2024 Plan. Slightly offsetting the overall decrease were period-over-period increases in labor and contracting expenses and consulting fees of $2.6 million and $2.2 million, respectively.

Other Operating Expenses

Other operating expenses were $16.6 million, or $0.22 per Mcfe, for the three months ended September 30, 2025, which was an increase of approximately $12.4 million, from $4.1 million, or $0.06 per Mcfe, for the three months ended September 30, 2024. The increase in other operating expenses during the three months ended September 30, 2025, compared to the same period in 2024, was primarily due to $5.6 million in an enterprise resource planning system write-off, $3.8 million in integration costs from the Bedrock Acquisition, a $1.3 million increase in third-party natural gas purchases due to increased volumes and natural gas prices, and $1.1 million in transaction costs related to the BKV-BPP Power Joint Venture Transaction.

Other Income (Expense)

Gains on contingent consideration liabilities. For the three months ended September 30, 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 $3.9 million for the three months ended September 30, 2024, and consisted of a gain of $3.9 million and a negligible gain from the Devon Barnett Acquisition and the Exxon Barnett Acquisition, respectively. The contingent considerations under these purchase agreements expired in 2024.

Earnings from equity affiliate. Earnings from our equity affiliate were $21.1 million for the three months ended September 30, 2025, which was a decrease of $29.5 million, from $50.6 million of earnings from our equity affiliate during the three months ended September 30, 2024. Earnings from our equity affiliate are related to our investment in, and our proportionate share in the income or losses of the BKV-BPP Power Joint Venture.

Interest expense. Interest expense was $6.5 million for the three months ended September 30, 2025, which was a decrease of $2.7 million, from $9.2 million for the three months ended September 30, 2024. The decrease in interest expense during the three months ended September 30, 2025, was primarily due to lower principal outstanding on our RBL Credit Facility during the three months ended September 30, 2025, compared to the three months ended September 30, 2024.

Interest expense, related party. Interest expense from our related party borrowings with BNAC was $1.3 million for the three months ended September 30, 2024, which was repaid in September 2024.

Interest income. Interest income was $0.3 million for the three months ended September 30, 2025, which was an increase of $0.1 million, from $0.2 million for the three months ended September 30, 2024.

Income tax benefit (expense). For the three months ended September 30, 2025, we had an income tax expense of $20.0 million, which was a change of $8.7 million from a $11.3 million income tax expense for the three months ended September 30,

2024. The period-over period change was primarily due to a higher pre-tax income for the three months ended September 30, 2025, compared to the three months ended September 30, 2024.

Results of Operations

Comparison of the Nine Months Ended September 30, 2025 and 2024

Operating Revenues and Operating Income

Our operating revenues and other income from operations include revenues from the sale of natural gas, NGLs, and oil, midstream revenues, gains and losses on our derivative contracts and on the sale of our business, 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:

(in thousands, other than percentages)

Natural Gas Revenues

Our natural gas revenues increased by approximately $207.4 million, or 78% to $474.5 million for the nine months ended September 30, 2025, from $267.1 million for the nine months ended September 30, 2024. The impact of commodity price increases, excluding the effect of derivative settlements, provided a $206.6 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 slightly higher production volumes during the nine months ended September 30, 2025, which accounted for a $0.8 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).

NGL Revenues

Our NGL revenues increased by approximately $4.0 million, or 3% to $126.1 million for the nine months ended September 30, 2025, from $122.1 million for the nine months ended September 30, 2024. The increase was due to the impact of commodity price increases, excluding the effect of derivative settlements, which accounted for a $2.6 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 nine months ended September 30, 2025, which accounted for a $1.4 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).

Oil Revenues

Our oil revenues increased by approximately $2.4 million, or 45%, to $7.7 million for the nine months ended September 30, 2025, from $5.3 million for the nine months ended September 30, 2024. The increase was due to higher production volumes during the nine months ended September 30, 2025, which accounted for a $3.6 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price). The increase was offset by the impact of commodity price decreases, excluding the effect of derivative settlements, which accounted for a $1.2 million decrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes).

Midstream Revenues

Our midstream revenues decreased by approximately $2.1 million, or 20%, to $8.1 million for the nine months ended September 30, 2025, from $10.2 million for the nine months ended September 30, 2024. This decrease was primarily due to the divestiture of Chaffee of $2.0 million as we sold our Repsol Midstream Interest in connection with this sale.

Derivative Gains, Net

For the nine months ended September 30, 2025, we had net realized and unrealized gains on derivative contracts of $34.9 million, compared to $24.1 million for the same period in 2024. The increase in gains for the nine months ended September 30, 2025, was primarily attributable to our open derivative positions, which were in more of an unrealized gain position of $24.1 million, compared to an unrealized loss position of $82.1 million for the same period in 2024. The increase in unrealized gains for the current period primarily reflects decreases in the forward curve of natural gas prices relative to December 31, 2024, whereas the prior year period reflected increases in future natural gas prices compared to December 31, 2023. Offsetting the unrealized gains for the nine months ended September 30, 2025, were the purchase of put options in the first quarter of 2025, limiting our 2026/2027 pricing downside. Included in the unrealized losses for the nine months ended September 30, 2024, were the sale of call options in January 2024, which limited our 2026/2027 pricing upside. The increased gains on our derivative contracts were offset by a decrease in realized gains of $95.5 million to $10.8 million for the nine months ended September 30, 2025, compared to realized gains of $106.3 million in the same period in 2024, which were due to higher natural gas prices settled in the current period compared to the same period in the prior year.

Marketing Revenues

Our marketing revenues increased by approximately $0.8 million, or 9%, to $9.5 million for the nine months ended September 30, 2025, from $8.7 million for the nine months ended September 30, 2024. Our marketing revenues are derived under our marketing agreement with a third party pursuant to which we receive a fixed percentage of all net income realized in the resale of our and other producers’ hydrocarbons. The increase in marketing revenues during the nine months ended September 30, 2025, was primarily due to a higher pricing environment compared to the same period in 2024.

Gain on Sale of Business

During the nine months ended September 30, 2024, we sold our wholly-owned subsidiary, Chaffee for $103.2 million, net of third-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 $6.0 million.

Section 45Q Tax Credits

Our Section 45Q tax credits decreased by approximately $0.6 million, or 6%, to $9.6 million during the nine months ended September 30, 2025, from $10.3 million during the nine months ended September 30, 2024. Our Section 45Q tax credits related to CO2 waste sequestration activities under our Barnett Zero Project. The decrease period-over-period was due to less CO2 waste sequestered in 2025, compared to the prior period from operational maintenance in April and May 2025, and routine fluctuations in activity levels that occur as part of our normal operations.

Related Party Revenues

Our related party revenues were $1.3 million for the nine months ended September 30, 2025, compared to $2.6 million for the nine months ended September 30, 2024. The decrease of $1.3 million, or 51%, in related party revenues was due to a decrease in operating fee income with BKV-BPP Power, attributable to lower contracted rates.

Other Revenues

Other revenues includes the gain (loss) on sale assets and the sale of third-party natural gas. Other revenues were $7.0 million for the nine months ended September 30, 2025, compared to $4.8 million for the nine months ended September 30, 2024. The period-over-period increase was due to an increase in third-party gas of $4.8 million, offset by the loss on sale of assets of 1.7 million in during the nine months ended September 30, 2025, compared to a gain on sale of assets of $0.8 million during the nine months ended September 30, 2024.

Operating Expenses

Our operating expenses reflect costs incurred in the development, production and sale of natural gas, NGLs, and oil. The following table provides information on our operating expenses:

(in thousands, other than percentages and average costs)

Lease Operating and Workover

The following table summarizes our components of lease operating expenses for the periods presented:

(in thousands, other than percentages and average costs)

Lease operating and workover expenses were $106.2 million, or $0.49 per Mcfe, for the nine months ended September 30, 2025, which was an increase of approximately $3.9 million, or 4%, from $102.2 million, or $0.47 per Mcfe, for the nine months ended September 30, 2024. The increase in lease operating and workover expenses during the nine months ended September 30, 2025, compared to the same period in 2024 was due to our Pad of the Future program and increased project activity in 2025 of $3.3 million and vehicle expenses of $0.8 million. In addition, during the nine months ended September 30, 2024, we received a credit of $1.5 million for a water sharing agreement that related to 2023. This was offset by decreases in compression and water expenses of $1.5 million and timing of inspection fees of $0.3 million during the nine months ended September 30, 2025 compared to 2024.

Taxes Other Than Income

Taxes other than income were $35.3 million, or $0.16 per Mcfe, for the nine months ended September 30, 2025, which was an increase of approximately $3.4 million, or 11%, from $31.9 million, or $0.15 per Mcfe, for the nine months ended September 30, 2024. The increase in taxes other than income during the nine months ended September 30, 2025, compared to 2024, was due to increases in production taxes of $11.1 million in the Barnett. This was offset by decreases in ad valorem and property taxes associated with our operations in the Barnett and NEPA of $7.0 million and $0.7 million, respectively. Certain ad valorem and production taxes are not applicable to our NEPA properties.

Gathering and Transportation

Gathering and transportation expenses were $180.6 million, or $0.83 per Mcfe, for the nine months ended September 30, 2025, which was an increase of approximately $12.8 million, or 8%, from $167.8 million, or $0.77 per Mcfe, for the nine months ended September 30, 2024. This increase was primarily driven by natural gas and NGL rate increases of $6.0 million and $1.4 million, respectively, and increased natural gas and NGL production of $5.7 million and $0.6 million, respectively. This was offset by a decrease in gathering costs associated with our midstream business of $0.9 million.

Depreciation, Depletion, Amortization, and Accretion

Depreciation, depletion, amortization, and accretion was $115.9 million, or $0.53 per Mcfe, for the nine months ended September 30, 2025, which was a decrease of approximately $52.9 million, or 31%, from $168.8 million, or $0.78 per Mcfe, for the nine months ended September 30, 2024. The decrease in depreciation, depletion, amortization, and accretion during the nine months ended September 30, 2025, compared to the nine months ended September 30, 2024, was primarily due to a depletion rate adjustment in 2025, which was driven by higher reserves.

General and Administrative

General and administrative expenses were $86.5 million, or $0.40 per Mcfe, for the nine months ended September 30, 2025, which was an increase of approximately $13.0 million, or 18%, from $73.5 million, or $0.34 per Mcfe, for the nine months ended September 30, 2024. The increase in general and administrative expenses during the nine months ended September 30, 2025, compared to the nine months ended September 30, 2024, was due to increases from Company-wide growth initiatives of $7.0 million in consulting and information technology-related expenses, $3.7 million in contract labor, employee-based compensation, and employee expenses, and $2.3 million in severance costs.

Other Operating Expenses

Other operating expenses were $37.3 million, or $0.17 per Mcfe, for the nine months ended September 30, 2025, which was an increase of approximately $21.9 million, from $15.4 million, or $0.07 per Mcfe, for the nine months ended September 30, 2024. The increase in other operating expenses during the nine months ended September 30, 2025, compared to the same period in 2024 was due to $5.6 million in an enterprise resource planning system write-off, an increase of $5.0 million in gas purchases due to increased volumes and natural gas prices, $3.8 million in integration costs from the Bedrock Acquisition, $3.1 million of costs related to the CCUS equity raise, $2.4 million in CCUS transaction fees, $2.2 million of a deficiency payment incurred under our minimum volume commitments on our midstream pipeline, $1.5 million in project write-offs, $1.4 million in legal settlements and $1.1 million in transaction costs related to the BKV-BPP Power Joint Venture Transaction. This was offset by $5.0 million of accrued waste emissions costs established by the Inflation Reduction Act recognized during the nine months ended September 30, 2024, which were not accrued in 2025 due to the impacts of the new Trump Administration.

Other Income (Expense)

Gains on contingent consideration liabilities. For the nine months ended September 30, 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 $10.0 million for the nine months ended September 30, 2024, and consisted of a gain of $7.8 million and a gain of $2.2 million from the Devon Barnett Acquisition and the Exxon Barnett Acquisition, respectively. The contingent considerations under these purchase agreements expired in 2024.

Earnings from equity affiliate. Earnings from our equity affiliate was $20.6 million for the nine months ended September 30, 2025, which was a decrease in earnings of $7.0 million, from $27.6 million for the nine months ended September 30, 2024. Earnings from our equity affiliate is related to our investment in, and our proportionate share in the income or losses of the Power Joint Venture.

Interest expense. Interest expense was $17.0 million for the nine months ended September 30, 2025, which was a decrease of $23.5 million, from $40.4 million for the nine months ended September 30, 2024. The decrease in interest expense during the nine months ended September 30, 2025 was primarily due to lower interest rates and a lower outstanding balance on our RBL Credit Facility, which we entered into on June 11, 2024, and subsequently paid down the outstanding balances on our SCB Credit Facility, the Revolving Credit Agreement, and the Term Loan Credit Agreement, which incurred higher interest rates.

Interest expense, related party. Interest expense from our related party borrowings with BNAC was $5.2 million for the nine months ended September 30, 2024, which was repaid in September 2024.

Interest income. Interest income was $0.6 million for the nine months ended September 30, 2025, which was a decrease of $3.0 million, from $3.6 million for the nine months ended September 30, 2024. The decrease was due to the cessation of interest earned on restricted cash following the repayment of the Term Loan Agreement in June 2024, which had previously funded the debt service reserve account.

Income tax benefit (expense). For the nine months ended September 30, 2025, we had an income tax expense of $18.7 million, which was a change of $48.8 million, from $30.1 million income tax benefit for the nine months ended September 30, 2024. The period-over-period change was primarily due to a pre-tax income for the nine months ended September 30, 2025, compared to a pre-tax loss for the nine months ended September 30, 2024.

Liquidity and Capital Resources

Capital Commitments

Our primary needs for cash are to fund our upstream development, midstream, power, and CCUS activities, fund operations and capital expenditures, acquisitions, and asset retirement obligations, cover any debt interest or minimum volume commitment obligations, pay down debt, and return capital to stockholders. Our primary use of cash during the nine months ended September 30, 2025, was to fund the Bedrock Acquisition and the development of our natural gas properties. Our primary use of cash during the nine months ended September 30, 2024, was to fund the development of our natural gas properties.

During the nine months ended September 30, 2025 and 2024, cash paid for capital expenditures was $209.0 million and $52.8 million, respectively. Our 2025 full year estimated accrued capital expenditures remain consistent at approximately $290 million to $350 million. Capital expenditures for our operated properties are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for natural gas and NGLs, the availability of equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs, and the level of participation by other interest owners. We will continue to monitor commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.

Capital Resources

Historically, our primary sources of capital and liquidity have consisted of internally generated cash flows from operations, together with loans and capital contributions from our majority stockholder, BNAC. We also enter into financial instruments to reduce the impact of commodity price volatility and provide a level of certainty and stability around cash flows. We currently believe that our cash flows from operations, cash on hand, borrowings under our RBL Credit Agreement and 2030 Senior Notes, and our commodity hedges in place will provide sufficient liquidity to fund our operations and our capital expenditures for the remainder of 2025, excluding our CCUS business. We expect to fund the majority of our CCUS business from a variety of external sources, including contributions from our joint ventures with the Class B Member and BPPUS, project-based equity partnerships, debt financing, and federal grants, with the remaining capital needs being funded with cash flows from operations.

The following table summarizes our cash flows for the nine months ended September 30, 2025 and 2024 (in thousands):

Cash flows provided by operating activities. Net cash provided by operating activities was $173.3 million for the nine months ended September 30, 2025, compared to $74.8 million for the nine months ended September 30, 2024. Net cash provided by operating activities increased during the nine months ended September 30, 2025, compared to the nine months ended September 30, 2024 due to a $68.0 million increase in income from operations (excluding net unrealized gains (losses), depreciation, depletion, amortization, and accretion, and equity-based compensation), resulting from higher natural gas prices in

2025 compared to 2024, a $40.7 million decrease in cash paid for interest, a $28.4 million increase in working capital, and a $3.5 million decrease in transaction costs from the sale of business assets paid over the same period. These increases were offset by $23.5 million of cash received in January 2024 for the sale of call options, $16.2 million of cash paid in February 2025 for the purchase of put options, and $3.0 million of lower interest income.

Operating cash flow fluctuations are substantially driven by realized commodity prices, production volumes, and operating expenses. Prices for natural gas and NGLs have historically been volatile, primarily as a result of supply and demand, pipeline infrastructure constraints, basis differentials, inventory storage levels, and seasonal influences. We are unable to predict future commodity prices and therefore cannot provide assurance about future levels of cash provided by operating activities.

Cash flows provided by (used in) investing activities. Net cash used in investing activities was $435.0 million for the nine months ended September 30, 2025, compared to net cash provided by investing activities of $80.6 million for the nine months ended September 30, 2024. The change was due to $220.3 million of cash paid in the Bedrock Acquisition, $140.5 million increase in capital expenditures (excluding CCUS activities), $15.7 million increase in CCUS expenditures, and $15.0 million deposit paid to secure a fixed asset purchase during the nine months ended September 30, 2025, compared to the nine months ended September 30, 2024. This was offset by a $5.2 million increase in proceeds from the sales of assets and $2.1 million of cash acquired in consolidation of BKV-BPP Cotton Cove over the same period. Contributing to the cash inflow during the nine months ended September 30, 2024, were total proceeds of $131.7 million from the sale of Chaffee and Chelsea.

The following table presents our capital expenditures (excluding leasehold costs and acquisitions) on an accrual basis for the nine months ended September 30, 2025 and 2024 and reconciles to cash flows used for capital expenditures in the condensed consolidated statements of cash flows.

Cash flows provided by (used in) financing activities. Net cash provided by financing activities was $330.0 million for the nine months ended September 30, 2025, which consisted of $490.0 million in net proceeds from the issuance of the 2030 Senior Notes, $11.0 million of cash contributions from noncontrolling interest, offset by $165.0 million in net payments on the RBL Credit Agreement, $4.4 million in payments of debt issuance costs, and $1.6 million in payments for taxes related to net share settlement of restricted stock units. For the nine months ended September 30, 2024, net cash used in financing activities was $289.2 million, which primarily consisted of $468.0 million of net payments on debt, $53.2 million for taxes paid related to net share settlement of restricted stock units, and payments of $18.3 million for debt issuance costs and debt extinguishment costs. This was offset by net proceeds from the issuance of common stock from our IPO of $253.8 million, after deducting underwriting discounts and commissions.

Working Capital

As of September 30, 2025, we had cash and cash equivalents of $83.1 million, compared to $14.9 million of cash and cash equivalents as of December 31, 2024. Our net working capital deficit was $34.6 million as of September 30, 2025, compared to a deficit of $71.6 million as of December 31, 2024.

Our working capital fluctuates based on the timing of cash collections on accounts receivable and payments on accounts payable. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Furthermore, we expect that our pace of development, production volumes, commodity prices, and differentials to NYMEX pricing for our natural gas and oil production will be the largest variables impacting our working capital.

2030 Senior Notes

On September 26, 2025, we issued in a private placement $500.0 million of 7.50% senior unsecured notes due October 15, 2030 (the "2030 Senior Notes"). The 2030 Senior Notes were issued at par and resulted in proceeds of $490.0 million, after deducting underwriters’ discounts, and commissions. The proceeds were used to repay a portion of the RBL Credit Agreement and fund a portion of the purchase price of the Bedrock Acquisition. In connection with the issuance of the 2030 Senior Notes, we recorded debt issuance costs of $13.4 million, which are amortized to interest expense on the condensed consolidated statements of operations over the term of the 2030 Senior Notes.

Interest on the 2030 Senior Notes is payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2026. The 2030 Senior Notes are guaranteed on a senior unsecured basis by us and all of BKV Upstream Midstream's existing restricted subsidiaries and certain future subsidiaries (collectively, the “BKV Guarantors,” and such guarantees, the “Guarantees”). These Guarantees are full, unconditional, joint, and several among the BKV Guarantors, subject to certain customary release provisions. The indenture governing the 2030 Senior Notes contains customary events of default, as well as cross-default provisions with other indebtedness of the Company and its restricted subsidiaries.

The 2030 Senior Notes and the Guarantees will rank effectively subordinate in right of payment to any secured indebtedness of BKV Upstream Midstream and the BKV Guarantors, including under the RBL Credit Agreement, and other secured obligations BKV Upstream Midstream or the BKV Guarantors incur in the future, to the extent of the value of the assets constituting collateral securing such indebtedness and obligations. The 2030 Senior Notes and the Guarantees will rank senior in right of payment to any of BKV Upstream Midstream and the BKV Guarantors’ subordinated indebtedness. In addition, the 2030 Senior Notes will be structurally subordinated in right of payment to any indebtedness and other liabilities (other than indebtedness and liabilities owed to BKV Upstream Midstream) of BKV Upstream Midstream’s subsidiaries that do not guarantee the 2030 Senior Notes. On or after October 15, 2027, BKV Upstream Midstream may, on any one or more occasions, redeem some or all of its 2030 Senior Notes prior to their maturity at redemption prices plus accrued and unpaid interest as described in the indenture governing the 2030 Senior Notes. Subject to certain conditions, BKV Upstream Midstream may redeem up to 40% of the aggregate principal amount of the 2030 Senior Notes before October 15, 2027, with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price described in the indenture governing the 2030 Senior Notes plus accrued and unpaid interest to, but excluding, the redemption date. In addition, prior to October 15, 2027, the BKV Upstream Midstream may redeem some or all of the 2030 Senior Notes at a price equal to 100% of the principal amount thereof, plus a make-whole premium set forth in this offering memorandum, plus accrued and unpaid interest as described in the indenture governing the 2030 Senior Notes.

RBL Credit Agreement

On June 11, 2024, BKV Corporation, as a guarantor, and BKV Upstream Midstream, as borrower, entered into the RBL Credit Agreement with Citibank, N.A., as the administrative agent, and the financial institutions party thereto. The RBL Credit Agreement includes a maximum credit commitment of $1.5 billion. On September 22, 2025, with the unanimous consent of our credit facility lenders, we amended the RBL Credit Agreement to, among other things, increase the borrowing base by $150.0 million and the elected commitment by $135.0 million upon closing of the Bedrock Acquisition (among other conditions). This amendment constituted a semiannual borrowing base redetermination. As of September 30, 2025, the RBL Credit Agreement had a borrowing base of $1.0 billion, an elected commitment of $800.0 million, and the ability to issue up to $40.0 million in letters of credit. The loans under the RBL Credit Agreement may be borrowed, repaid, and reborrowed during the term of the RBL Credit Agreement. The RBL Credit Agreement will mature on June 12, 2028. The obligations under the RBL Credit Agreement are secured and guaranteed on a secured basis by BKV Upstream Midstream and all of BKV Upstream Midstream’s current and future material restricted subsidiaries. Loans under the RBL Credit Agreement bear interest at one, three, or six-month term SOFR or ABR, as applicable, plus a credit spread adjustment of 0.10% for SOFR borrowings, plus an applicable margin per annum. Interest is payable on the last day of each interest period and at maturity. We are obligated to pay certain fees to the lenders and administrative agent under the RBL Credit Agreement, including commitment fees on the average daily amount of the undrawn portion of the commitments. As of November 10, 2025, zero revolving borrowings and $15.0 million of letters of credit were outstanding under the RBL Credit Agreement, leaving $785.0 million of available capacity thereunder for future borrowings and letters of credit.

The RBL Credit Agreement contains various restrictive covenants that, among other things, limit BKV Upstream Midstream’s ability and the ability of its restricted subsidiaries to, subject to certain exceptions: (i) incur indebtedness; (ii) incur liens; (iii) acquire or merge with any other company; (iv) sell assets or equity interests of their subsidiaries; (v) make investments; (vi) pay dividends or make other restricted payments; (vii) change their lines of business; (viii) enter into certain hedge agreements; (ix) enter into transactions with affiliates; (x) own any subsidiary that is not organized in the United States; (xi) prepay any unsecured senior or subordinated indebtedness; (xii) engage in certain marketing activities; and (xiii) allow, on a net basis, gas imbalances, take-or-pay or other prepayments with respect to their proved oil and gas properties.

The RBL Credit Agreement requires BKV Upstream Midstream and its restricted subsidiaries to always hedge not less than 50% of reasonably anticipated projected production from their proved developed producing reserves for the subsequent 24 calendar month period immediately following the date financial statements are required to be delivered under the RBL Credit Agreement for each fiscal quarter.

The RBL Credit Agreement also includes financial covenants that require BKV Upstream Midstream to maintain:

• on a quarterly basis, a minimum Current Ratio (as defined in the RBL Credit Agreement) of no less than 1.00 to 1.00; and
• on a quarterly basis, a Net Leverage Ratio (as defined in the RBL Credit Agreement) of no greater than 3.25 to 1.00.

The RBL Credit Agreement includes customary equity cure rights that will enable us to cure certain breaches of the minimum current ratio covenant or the maximum net leverage ratio covenant (subject to certain limitations in the RBL Credit Agreement).

The RBL Credit Agreement generally includes customary events of default for a reserve-based credit facility, some of which allow for an opportunity to cure. If an event of default relating to bankruptcy or other insolvency events occurs, the revolving loans will immediately become due and payable; if any other event of default exists, the administrative agent or the requisite lenders will be permitted to accelerate the maturity of the revolving loans. The RBL Credit Agreement is secured by substantially all of BKV Upstream Midstream's assets and those of the guarantors, and upon an event of default the agent under the RBL Credit Agreement could commence foreclosure proceedings.

BKV-BPP Power and BKV-BPP Cotton Cove Joint Ventures

Under the terms of the BKV-BPP Power LLC Agreement and BKV-BPP Cotton Cove LLC Agreement, we do not have the ability to unilaterally cause BKV-BPP Power or BKV-BPP Cotton Cove to make distributions. During the nine months ended September 30, 2025 and 2024, no distributions were made by BKV-BPP Power or BKV-BPP Cotton Cove. In addition, we may be required to make additional capital contributions to one or both joint ventures to fund items approved in their respective annual budgets or other matters approved by their respective boards. Such additional capital contributions, which are not subject to any limit on the potential amount required, would reduce the amount of cash otherwise available to us. However, any additional capital contributions to BKV-BPP Power must be approved by a majority of BKV-BPP Power's ten member board of managers, five of whom are appointed by us and five of whom are appointed by BPPUS. Similarly, any additional capital contributions to BKV-BPP Cotton Cove must receive the unanimous approval of BKV-BPP Cotton Cove, LLC's six member board of managers, four of whom are appointed by us and two of whom are appointed by BPPUS. On June 26, 2025, BKV dCarbon Ventures and BPPUS amended and restated the BKV-BPP Cotton Cove, LLC Agreement whereby on July 9, 2025, BKV dCarbon Ventures contributed $3.3 million to BKV-BPP Cotton Cove, net of $0.1 million of expenditures paid by BKV dCarbon Ventures on behalf of BKV-BPP Cotton Cove, and on July 10, 2025, BPPUS received $5.4 million of its initial capital contribution of $8.6 million from BKV-BPP Cotton Cove. On July 31, 2025, BKV dCarbon Ventures and BPPUS contributed an additional $3.8 million and $3.6 million, respectively.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that could give rise to material off-balance sheet arrangements. As of September 30, 2025, our material off-balance sheet arrangements and transactions included transportation commitments of $278.6 million and letters of credit of $15.0 million against the RBL Credit Agreement. For further information regarding these arrangements, see Note 11 - Commitments and Contingencies to our condensed consolidated financial statements and under “—Liquidity and Capital Resources — RBL Credit Agreement.”

Critical Accounting Policies and Estimates

Management’s discussion and analysis of our financial condition and results of operations are based upon our historical consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets, liabilities, and related disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

Accounting for Variable Interest Entities

As described in Note 10 - Investments in our condensed consolidated financial statements, on May 8, 2025, BKV dCarbon Ventures, together with C Squared Solutions, Inc., a subsidiary of the Energy Transition Fund managed by Copenhagen Infrastructure Partners (CIP), and for the limited purposes specified therein, BKV Corporation, entered into the BKV-CIP JV

Agreement forming the BKV-CIP Joint Venture. On June 26, 2025, BKV dCarbon Ventures and BPPUS amended and restated the BKV-BPP Cotton Cove, LLC Agreement whereby on July 9, 2025, BKV dCarbon Ventures contributed $3.3 million to BKV-BPP Cotton Cove, net of $0.1 million of expenditures paid by BKV dCarbon Ventures on behalf of BKV-BPP Cotton Cove, and on July 10, 2025, BPPUS received $5.4 million of its initial capital contribution of $8.6 million from BKV-BPP Cotton Cove. On July 31, 2025, BKV dCarbon Ventures and BPPUS contributed an additional $3.8 million and $3.6 million, respectively. BKV dCarbon Ventures owns a 51% interest and BPPUS owns a 49% interest in BKV-BPP Cotton Cove.

We consider the BKV-CIP Joint Venture and BKV-BPP Cotton Cove Joint Venture to each be a variable interest entity (“VIE”) of BKV in accordance with ASC 810, Consolidation, as BKV is deemed to be the primary beneficiary of these joint ventures. Generally, a VIE is an entity with at least one of the following conditions: (i) the total equity investment at risk is insufficient to allow the entity to finance its activities without additional subordinated financial support, or (ii) the holders of the equity investment at risk, as a group, lack the characteristics of having a controlling financial interest. The primary beneficiary of a VIE is an entity that has a variable interest or a combination of variable interests that provide such entity with a controlling financial interest in the VIE. An entity is deemed to have a controlling financial interest in a VIE if it has both of the following characteristics: (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, and (ii) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

In exchange for cash contributions received from the Class B Member to the BKV-CIP Joint Venture, the BKV-CIP Joint Venture has issued 1,103,773 Class B Units (the “Class B Units”) at $10.00 per unit as of September 30, 2025. We determined that the Class B Units should be classified as noncontrolling interest within mezzanine equity on the Company's condensed consolidated balance sheets. The Class B Units are not mandatorily redeemable or currently redeemable, but become exercisable with the passage of time, which is on the second anniversary of the BKV-CIP JV Agreement, or May 8, 2027. Prior to the second anniversary, we determined that there is an embedded put option in the Class B Units, which does not meet the derivative accounting criteria, and is not within the control of the Company. Therefore, the shares of the Class B Units have been classified as noncontrolling interest within mezzanine equity on our condensed consolidated balance sheets. The Class B Units also have a multiple investment on capital equal to 1.65, which may be redeemed on the second anniversary date. The contributions from the Class B Member are accreted to the redemption value over a 2-year period (using the effective interest method) with the accretion accounted for as a dividend paid to the Class B Member.

Tariffs and Trading Relationships

In April 2025, the U.S. government announced a baseline tariff of 10% on products imported from all countries and an additional individualized reciprocal tariff on the countries with which the United States has the largest trade deficits, including China. Increased tariffs by the United States have led and may continue to lead to the imposition of retaliatory tariffs by foreign jurisdictions. Additionally, the U.S. government has announced and rescinded multiple tariffs on several foreign jurisdictions, which has increased uncertainty regarding the ultimate effect of the tariffs on economic conditions. Current uncertainties about tariffs and their effects on trading relationships may impact the demand for, and price of natural gas, NGLs, and oil, increase the costs of goods and services or the availability of raw materials that we rely on to operate our business or impact interest rates. Although we are continuing to monitor the economic effects of such announcements, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs remain uncertain and could adversely impact our financial position, results of operations, and liquidity.

Emerging Growth Company Status

We are an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act of 1933, as amended, including as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As a result, for so long as we qualify as an emerging growth company, we are eligible to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies. We have elected to take advantage of certain of the reduced disclosure obligations in this Quarterly Report on Form 10-Q and may elect to take advantage of other reduced reporting requirements in our future filings with the SEC. As a result, the information that we provide to our stockholders may be different from other public reporting companies.

Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards issued subsequent to the enactment of the JOBS Act, until such time as those standards apply to private companies. However, we have irrevocably elected not to avail ourselves of this exemption. Rather, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.

We may take advantage of these provisions until the last day of our fiscal year following the fifth anniversary of the date of our IPO. Such fifth anniversary will occur in 2029. However, if certain events occur prior to the end of such five-year period, including if we become a “large accelerated filer,” our gross revenues for any fiscal year equal or exceed $1.235 billion or we issue more than $1.0 billion of non-convertible debt in any three-year period, we will cease to be an emerging growth company prior to the end of such five-year period.

There has been no material change in our market risks since December 31, 2024, as set forth in our 2024 Annual Report on Form 10-K.

Commodity Price Risk and Hedging Activities

Our primary market risk exposure is in the price we receive for our natural gas and NGL production. Pricing is primarily driven by spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas and NGLs has historically been volatile and unpredictable, and we expect this volatility to continue in the future. The prices we receive for our production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate some of the potential negative impact on our cash flows caused by changes in commodity prices, we enter into financial derivative instruments for a portion of our natural gas and NGL production when management believes that favorable future prices can be secured.

Our financial hedging activities are intended to support natural gas and NGL prices at targeted levels and to manage our exposure to natural gas and NGL price fluctuations. These contracts may include commodity price swaps, whereby we will receive a fixed price and pay a variable market price to the contract counterparty, producer collars that set a floor and ceiling price for the hedged production, or basis differential swaps. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity. The derivative contracts outstanding as of September 30, 2025 consisted of commodity price swaps, basis differential swaps, put and call options, and producer collar agreements, subject to master netting agreements with each individual counterparty.

These derivative contracts cover portions of our projected positions through 2028. Our commodity hedge position as of September 30, 2025 is summarized in Note 6 - Derivative Instruments to our condensed consolidated financial statements.

We may enter into single hedge transactions with settlements up to 48 months. The aggregation of these executed hedge instruments may not exceed certain limits without board of director approval of our forecasted production volumes. During the three months ended September 30, 2025 and 2024, a hypothetical increase of $0.10 per Mcf in NYMEX would have resulted in a $3.6 million and $2.7 million decrease in natural gas hedge revenues, respectively, and a hypothetical decrease of $0.10 per Mcf would have resulted in a $3.5 million and $2.7 million increase in natural gas hedge revenues, respectively, over the same time period. During the three months ended September 30, 2025 and 2024, a hypothetical increase or decrease of $1.00 per Bbl of NGL purity product price would have resulted in a $1.3 million and $2.0 million decrease or increase in NGL hedge revenues, respectively. During the nine months ended September 30, 2025 and 2024, a hypothetical increase or decrease of $0.10 per Mcf in NYMEX would have resulted in a $10.5 million and $7.0 million decrease or increase in natural gas hedge revenues, respectively, and a hypothetical increase or decrease of $1.00 per Bbl of NGL purity product price would have resulted in a $3.9 million and $5.0 million decrease or increase in NGL hedge revenues, respectively.

Additionally, to reduce its exposure to fluctuations in the market price of electricity and natural gas, BKV-BPP Power enters 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 are sometimes not 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 BKV-BPP Power, 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 the power prices, which could have an adverse effect on our financial condition. Moreover, in the event BKV-BPP Power is not able to satisfy its obligations under the HRCO, it must purchase power at prevailing market prices 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 BKV-BPP Power, and thus on our business, financial condition, results of operations, and cash flows.

All derivative instruments, other than those that meet the normal purchase and normal sale scope exception, are recorded at fair market value in accordance with GAAP and are included in our condensed consolidated balance sheets as assets or liabilities. The fair values of our derivative instruments are adjusted for non-performance risk. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment; therefore, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our condensed consolidated statements of operations. We present total gains or losses on commodity derivatives (for both settled derivatives and derivative positions which remain open) within operating revenues as derivative gains, net.

Mark-to-market adjustments of derivative instruments cause earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled or monetized prior to settlement. We expect continued volatility in the fair value of our derivative instruments. Our cash flows are only impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty. As of September 30, 2025, the estimated fair value of our commodity derivative instruments was a net liability of $6.6 million, comprised of current and noncurrent assets and current and noncurrent liabilities. As of December 31, 2024, the estimated fair value of our commodity derivative instruments was a net liability of $67.6 million, comprised of current and noncurrent liabilities.

By removing price volatility from a portion of our expected production through December 2028, we have mitigated, but not eliminated, the potential negative effects of changing prices on our operating cash flows for those periods. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

Counterparty Credit Risk

We routinely monitor and manage our exposure to counterparty risk related to derivative contracts by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties’ public credit ratings, and avoiding concentration of credit exposure by transacting with multiple counterparties. Our commodity derivative contract counterparties are typically financial institutions with investment-grade credit ratings.

We enter into International Swap Dealers Association (“ISDA”) Master Agreements with each of our derivative counterparties prior to executing derivative contracts. The terms of the ISDA Master Agreements provide, among other things, the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either us or counterparty to a derivative contract.

In addition, 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 worthiness of such third party marketer, who collects directly from the purchasers and remits to us the total of all amounts collected on our behalf, less their fee for making such sales.

Interest Rate Risks

As of September 30, 2025, we did not have primary exposure to interest rate risk due to the zero balance on our RBL Credit Agreement. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate 2030 Senior Notes, but can affect their fair values. For more information on our 2030 Senior Notes, see Note 3 - Debt and Note 5 - Fair Value Measurements to our condensed consolidated financial statements included in Item 1 of Part I of this report. As of September 30, 2024, our primary exposure to interest rate risk resulted from our outstanding borrowings on our RBL Credit Agreement, which has a floating interest rate. As of September 30, 2024, we had $190.0 million of outstanding borrowings under the RBL Credit Agreement. The average annualized interest rate incurred on our outstanding variable rate borrowings during the nine months ended September 30, 2025 and 2024, was approximately 7.4% and 9.4%, respectively. We estimate that a 1.0% increase in the applicable average interest rates during the three months ended September 30, 2025 and 2024, would have resulted in increases of $0.7 million and $0.9 million in interest expense, respectively, and that a 1.0% increase in the applicable average interest rates during the nine months ended September 30, 2025 and 2024, would have resulted in increases of $1.8 million and $4.4 million in interest expense, respectively.

Evaluation of Disclosure Controls and Procedures

As required by Rules 13a-15(b) and 15d-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the Commission's rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that due to the presence of our material weakness described below, as of September 30, 2025, our disclosure controls and procedures were not effective.

Material Weakness in Internal Control over Financial Reporting

As of September 30, 2025, a material weakness continued to exist 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 (i) 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, (ii) an immaterial audit adjustment to the supplemental cash flow information for cash payments for income taxes and a reclassification between oil and gas production and other taxes payable and other accrued liabilities within Note 11 - Accounts Payable and Accrued Liabilities to our consolidated financial statements as of and for the year ended December 31, 2023, (iii) audit adjustments to deferred tax liabilities and additional paid-in capital as of December 31, 2024, and (iv), the revision of our previously issued financial statements for the interim and annual periods included in the years ended December 31, 2021, 2022, and 2023, and interim periods included in the year ended December 31, 2024. This material weakness could result 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.

Notwithstanding this material weakness, we believe our condensed consolidated financial statements fairly present, in all material respects, our financial condition, results of operations, and cash flows for the periods presented, in accordance with GAAP.

Remediation Efforts to Address the Material Weakness

We have taken steps towards remediating this material weakness 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 are addressing the internal control deficiencies that led to this material weakness, the measures we have taken, and plan to take, may not be effective.

Inherent Limitations on Effectiveness of Controls and Procedures

In designing and evaluating the disclosure controls and procedures and internal control over financial reporting, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures and internal control over financial reporting must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Changes in Internal Control over Financial Reporting

There were no changes in the Company's internal control over financial reporting during the quarter ended September 30, 2025 that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting.

The Quarterly Report on Form 10-Q should be read in conjunction with the “Risk Factors” disclosed in our 2024 Annual Report on Form 10-K and subsequent Quarterly Reports on Form 10-Q, which could materially affect our business, financial condition, or future results. Except as set forth below, there have been no material changes to the risk factors previously disclosed in the 2024 Annual Report on Form 10-K and subsequent Quarterly Reports on Form 10-Q.

The consummation of the BKV-BPP Power Joint Venture Transaction is subject to a number of conditions that may not be satisfied or completed on a timely basis or at all, including the affirmative vote of at least 75% of the disinterested stockholders of Banpu Power represented at the meeting called for such purpose, and there can be no assurance as to when or if the BKV-BPP Power Joint Venture Transaction will be completed.

Although we expect to complete the BKV-BPP Power Joint Venture Transaction in the first quarter of 2026, there can be no assurances as to the timing of the closing or that the BKV-BPP Power Joint Venture Transaction will be completed at all. The consummation of the BKV-BPP Power Joint Venture Transaction is subject to the satisfaction or waiver of a number of conditions contained in the purchase agreement, including the affirmative vote of at least 75% of the disinterested stockholders of Banpu Power, the sole stockholder of BPPUS, represented at the meeting to be called for such purpose (the "BPP Stockholder Approval"). Some conditions, including the BPP Stockholder Approval, are beyond our control. The potential that any condition fails to be satisfied or waived in a timely manner, or at all makes the completion and timing of the BKV-BPP Power Joint Venture Transaction uncertain. In addition, the purchase agreement contains certain termination rights for both parties, which if exercised will also result in the BKV-BPP Power Joint Venture Transaction not being consummated. Any such termination or any failure to otherwise complete the BKV-BPP Power Joint Venture Transaction could result in various consequences, including, among others: our business being adversely impacted by the failure to pursue other beneficial opportunities due to the time and resources committed by our management to the BKV-BPP Power Joint Venture Transaction, without realizing any of the benefits of completing the BKV-BPP Power Joint Venture Transaction; being required to pay our legal, accounting and other expenses relating to the BKV-BPP Power Joint Venture Transaction; the market price of our common stock being adversely impacted to the extent that the current market price reflects a market assumption that the BKV-BPP Power Joint Venture Transaction will be completed; and negative reactions from the financial markets and customers that may occur if the anticipated benefits of the BKV-BPP Power Joint Venture Transaction are not realized. Such consequences could materially and adversely affect our business, financial condition, results of operations and cash flows.