BKV Corporation
03/06/2026 | Press release | Distributed by Public on 03/06/2026 15:45
Annual Report for Fiscal Year Ending December 31, 2025 (Form 10-K)
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included in Item 8 of Part II, Financial Statements and Supplementary Data in this Annual Report on Form 10-K. This Annual Report on Form 10-K contains certain statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Certain statements contained in the Management's Discussion and Analysis of Financial Condition and Results of Operations are forward-looking statements that involve risks and uncertainties. The forward-looking statements are not historical facts, but rather are based on current expectations, estimates, assumptions, and projections about our industry, business, and future financial results. Our actual results could differ materially from the results contemplated by these forward-looking statements due to a number of factors, including those discussed in other sections of this Annual Report on Form 10-K. See Item 1A of Part I, "Risk Factors" and under "Cautionary Note Regarding Forward-Looking Statements."
Overview
We are a forward-thinking, growth-driven energy company focused on creating long-term risk-adjusted stockholder value through the development of natural gas producing assets, the ownership and operation of natural gas-fired power generation assets, and selective accretive acquisitions. Our core businesses are the production of natural gas and the generation of natural gas-fired power from our owned and operated assets, supported by a closed-loop strategy enabled by our upstream, midstream, power, and CCUS businesses.
Our operations are supported by four business lines: natural gas production, natural gas midstream, power generation, and CCUS. Our operating approach is designed around a closed-loop model that aligns these business lines to support cost efficiency, commercial optimization, and operational reliability across the value chain. Through this approach, we retain operational control over the production, transportation, and processing of natural gas and provide multiple platforms for disciplined capital deployment, while meeting growing demand for low carbon natural gas and power.
For example, in the Barnett Shale, natural gas produced from our upstream assets is gathered and transported in part through our midstream systems. In November 2023, we commenced sequestration operations at our first CCUS project, and we currently expect our second and third CCUS projects to commence sequestration activities in the first and second quarter of 2026 with additional CCUS growth opportunities beyond 2026. Further, we are pursuing a power growth strategy that aligns with both our natural gas and CCUS businesses.
As part of our ongoing operations, we expect our owned and operated upstream and natural gas midstream businesses to achieve net-zero Scope 1 and Scope 2 greenhouse gas emissions during the early 2030s and net-zero Scope 1, Scope 2, and Scope 3 emissions by the late 2030s.
We believe our business model, experienced management team, and disciplined technology-enabled operations support our ability to create long-term, risk-adjusted stockholder value.
Recent Developments
•Equity Offering. On December 3, 2025, we completed an underwritten public offering of 6,900,000 shares of common stock for net proceeds of $170.1 million (the "2025 Equity Offering"). We used the net proceeds from the 2025 Equity Offering to fund the cash consideration for the BKV-BPP Power Joint Venture Transaction and related expenses. For additional information, see Note 1 - Business and Basis of Presentationand Note 13 - Stockholders' Equity and Mezzanine Equity.
•BKV-BPP Power Joint Venture Transaction. On January 30, 2026, we completed the previously announced BKV-BPP Power Joint Venture Transaction for aggregate consideration consisting of $115.1 million in cash and 5,315,390 shares of our common stock. We funded the cash consideration with a combination of cash on hand and the net proceeds from the 2025 Equity Offering. Following the closing of the transaction, the BKV-BPP Power Joint Venture is owned 75% by BKV and 25% by BPPUS, and the financial results of BKV-BPP Power will be consolidated into our financial statements. For additional information, see Note 14 - Investments and Note 19 - Subsequent Events.
Operational and Financial Highlights
Below are some highlights of our operating and financial results for the year ended December 31, 2025.
•Production of natural gas, NGLs, and oil was 305.0 Bcfe, or 835.5 MMcfe/d.
•Average realized product prices, excluding the impact of settled derivatives, were $2.81 per Mcfe.
•Production revenues were $857.6 million and midstream revenues were $10.5 million.
•Lease operating expense was $145.6 million, or $0.48 per Mcfe.
•Net income attributable to BKV was $173.1 million.
•Net cash provided by operating activities was $242.7 million.
•Accrued capital expenditures were $318.5 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, NGLs, 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:
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| Production Data | |||||||||||||||||
| Natural gas (MMcf) | 242,935 | 228,682 | 249,766 | ||||||||||||||
| NGLs (MBbls) | 10,181 | 9,858 | 10,554 | ||||||||||||||
| Oil (MBbls) | 159 | 96 | 119 | ||||||||||||||
| Total volumes (MMcfe) | 304,975 | 288,406 | 313,804 | ||||||||||||||
| Average daily total volumes (MMcfe/d) | 835.5 | 788.0 | 859.7 | ||||||||||||||
Impact of Acquisition and Joint Venture Transactions. Our financial condition and results of operations for the periods presented were impacted by acquisitions and joint venture transactions completed during 2025, which changed the scale, composition, and ownership structure of our operations.
In May 2025, as part of our CCUS business strategy, we partnered with the Class B Member to form the BKV-CIP Joint Venture, and beginning in the third quarter of 2025, we consolidated the BKV-BPP Cotton Cove Joint Venture. These transactions resulted in changes to the accounting treatment of certain assets and results, including the recognition of noncontrolling interests and fair value adjustments, further affecting comparability across periods.
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, results for 2025 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-average shares outstanding.
As a result of these transactions, our historical operating, financial, and reserve data may not be comparable between periods presented in this Annual Report on Form 10-K.
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, a minority equity interest in a midstream system, 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 7 - Derivative Instrumentsin Item 8 of Part II, "Financial Statements and Supplementary Data." The following is a comparison of average pricing excluding and including the effects of derivatives:
| Year Ended December 31, | ||||||||||||||||||||
| 2025 | 2024 | 2023 | ||||||||||||||||||
|
Average prices
|
||||||||||||||||||||
|
Natural gas ($/Mcf)
|
||||||||||||||||||||
| Average NYMEX Henry Hub price | $ | 3.43 | $ | 2.27 | $ | 2.74 | ||||||||||||||
| Average natural gas realized price (excluding derivatives) | $ | 2.78 | $ | 1.69 | $ | 2.04 | ||||||||||||||
|
Average natural gas realized price (including derivatives) (1)
|
$ | 2.75 | $ | 2.10 | $ | 2.23 | ||||||||||||||
|
Differential
|
$ | (0.65) | $ | (0.58) | $ | (0.70) | ||||||||||||||
|
NGLs ($/Bbl)
|
||||||||||||||||||||
| Average NGL realized price (excluding derivatives) | $ | 17.00 | $ | 16.79 | $ | 17.80 | ||||||||||||||
|
Average NGL realized price (including derivatives) (1)
|
$ | 16.84 | $ | 17.19 | $ | 17.55 | ||||||||||||||
|
Oil ($/Bbl)
|
||||||||||||||||||||
|
Average oil realized price
|
$ | 59.50 | $ | 68.81 | $ | 70.97 | ||||||||||||||
|
High and low daily spot prices
|
||||||||||||||||||||
|
Oil ($/Bbl)
|
||||||||||||||||||||
|
High NYMEX WTI
|
$ | 80.73 | $ | 87.69 | $ | 93.67 | ||||||||||||||
|
Low NYMEX WTI
|
$ | 55.44 | $ | 66.73 | $ | 66.61 | ||||||||||||||
|
Natural gas ($/Mcf)
|
||||||||||||||||||||
|
High NYMEX Henry Hub
|
$ | 9.86 | $ | 13.20 | $ | 3.78 | ||||||||||||||
|
Low NYMEX Henry Hub
|
$ | 2.65 | $ | 1.21 | $ | 1.74 | ||||||||||||||
___________________________________
(1)Impact of derivatives prices excludes $13.3 million and $46.7 million of gainson derivative contract terminations for the years ended December 31, 2024 and 2023, respectively.
Results of Operations
Comparison of the Year Ended December 31, 2025 and 2024
Operating Revenues and Operating Income
Our operating revenues and other income from operations include the revenues 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:
| Year Ended December 31, | |||||||||||||||||||||||
| (in thousands, other than percentages) | 2025 | 2024 | $ Change | % Change | |||||||||||||||||||
| Revenues | |||||||||||||||||||||||
| Natural gas revenues | $ | 675,078 | $ | 385,456 | $ | 289,622 | 75 | % | |||||||||||||||
| NGL revenues | 173,059 | 165,508 | 7,551 | 5 | % | ||||||||||||||||||
| Oil revenues | 9,460 | 6,606 | 2,854 | 43 | % | ||||||||||||||||||
| Midstream revenues | 10,456 | 12,560 | (2,104) | (17) | % | ||||||||||||||||||
| Derivative gains (losses), net | 105,081 | (34,152) | 139,233 | * | |||||||||||||||||||
| Marketing revenues | 12,304 | 10,668 | 1,636 | 15 | % | ||||||||||||||||||
|
Gain on sale of business
|
- | 7,080 | (7,080) | (100) | % | ||||||||||||||||||
| Gains (losses) on sales of assets, net | (1,805) | 3,523 | (5,328) | * | |||||||||||||||||||
| Section 45Q tax credits | 11,752 | 14,021 | (2,269) | (16) | % | ||||||||||||||||||
|
Related party revenues
|
1,760 | 3,080 | (1,320) | (43) | % | ||||||||||||||||||
|
Other
|
11,664 | 6,631 | 5,033 | 76 | % | ||||||||||||||||||
| Total revenues and other operating income | $ | 1,008,809 | $ | 580,981 | |||||||||||||||||||
| *Percentage not meaningful | |||||||||||||||||||||||
Natural Gas Revenues
Our natural gas revenues increased by $289.6 million, or 75%,to $675.1 million for the year ended December 31, 2025, from $385.5 million for the year ended December 31, 2024. The impact of commodity price increases, excluding the effect of derivative settlements, provided a $265.6 millionincrease in year-over-year revenues (calculated as the change in the year-over-year average price times current year's production volumes). The increase was also due to higherproduction volumes during the year ended December 31, 2025, which accounted for a $24.0 millionincrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price).
NGL Revenues
Our NGL revenues increased by $7.6 million, or 5%, to $173.1 millionfor the year ended December 31, 2025,from $165.5 millionfor the year ended December 31, 2024. The increase was due to higherproduction volumes during the year ended December 31, 2025, which accounted for a $5.5 millionincrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price). The increase was also due to the impact of commodity price increases, excluding the effect of derivative settlements, which accounted for a $2.1 millionincrease in year-over-yearrevenues (calculated as the change in the year-over-year average price times current year's production volumes).
Oil Revenues
Our oil revenues increased by $2.9 million, or 43%, to $9.5 millionfor the year ended December 31, 2025,from $6.6 millionfor the year ended December 31, 2024. The increase was due to higherproduction volumes during the year ended December 31, 2025, which accounted for a $4.4 million increasein year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price). The increase was offset by the impact of commodity price decreases, excluding the effect of derivative settlements, which accounted for a $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).
Midstream Revenues
Our midstream revenues decreasedby $2.1 million, or 17%, to $10.5 million for the year ended December 31, 2025, from $12.6 million for the year ended December 31, 2024. This decreasewas 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 (Losses), Net
For the year ended December 31, 2025, we had net realized and unrealized gains on derivative contracts of $105.1 millioncompared to net realized and unrealized losses on derivative contracts of $34.2 millionfor the year ended December 31, 2024. The increase in gainsfor the year ended December 31, 2025 was primarily attributable to our open derivative positions, which were in more of an unrealized gain position of $113.2 million, compared to an unrealized lossposition of $146.7 million for the year ended December 31, 2024, The increase in unrealized gainsfor the year ended December 31, 2025 reflected decreases in the forward curve of natural gas prices relative to December 31, 2024, whereas the prior year period reflected increases in the forward curve of natural gas prices compared to December 31, 2023. The increased gainson our derivative contracts were also offset by realized lossesof $8.1 million during the year ended December 31, 2025, compared to realized gainsof $112.5 million during the year ended December 31, 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 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, 2025 was primarily due to a higher pricing environment comparedto the year ended December 31, 2024.
Gain on Sale of Business
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-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 Assets, Net
For the year ended December 31, 2025, we recognized a loss of $1.8 million on sales of assets compared to a gain of $3.5 million on sales of assets during the year ended December 31, 2024. During the year ended December 31, 2025, we wrote-down our Bridgeport office building by $2.4 million to its sale price of $5.5 million. This was offset by other
property and equipment sold for $1.3 million in proceeds, which resulted in a gain on sale of these assets of $0.6 million. For the year ended December 31, 2024, we sold other properties for $5.0 million in proceeds, which resulted in a gain on the sale of these properties of $3.5 million.
Section 45Q Tax Credits
Our Section 45Q tax credits relate to CO2 waste sequestration activities associated with our Barnett Zero Project. Our Section 45Q tax credits decreased by $2.3 million, or 16%, to $11.8 million for the year ended December 31, 2025, from $14.0 million for the year ended December 31, 2024. This decrease was due to lower volumes of CO2waste sequestered during the year ended December 31, 2025, reflecting routine fluctuations in activity levels that occur as part of our normal operations.
Related Party Revenues
Our related party revenues were $1.8 million for the year ended December 31, 2025, compared to $3.1 million for the year ended December 31, 2024. The decrease of $1.3 million, or 43%, in related party revenues was due to a decrease in operating fee income with BKV-BPP Power, attributable to lower contracted rates.
Other Revenue
Other revenues, which primarily includes the sale of third party gas, was $11.7 million for the year ended December 31, 2025 compared to $6.6 million for the year ended December 31, 2024. The year-over-year increase was primarily due to an increase in gas prices and contracted rates.
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:
| Year Ended December 31, | |||||||||||||||||||||||
| (in thousands, other than percentages and average costs) | 2025 | 2024 | $ Change | % Change | |||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||
| Lease operating and workover | $ | 152,873 | $ | 136,991 | $ | 15,882 | 12 | % | |||||||||||||||
| Taxes other than income | 50,762 | 35,009 | 15,753 | 45 | % | ||||||||||||||||||
| Gathering and transportation costs | 250,849 | 222,391 | 28,458 | 13 | % | ||||||||||||||||||
| Depreciation, depletion, amortization, and accretion | 157,464 | 217,533 | (60,069) | (28) | % | ||||||||||||||||||
| General and administrative | 124,355 | 104,473 | 19,882 | 19 | % | ||||||||||||||||||
| Other | 54,893 | 19,385 | 35,508 | * | |||||||||||||||||||
|
Total operating expense
|
$ | 791,196 | $ | 735,782 | |||||||||||||||||||
| Average costs per Mcfe | |||||||||||||||||||||||
| Lease operating and workover | $ | 0.50 | $ | 0.47 | $ | 0.03 | 6 | % | |||||||||||||||
| Taxes other than income | 0.17 | 0.12 | 0.05 | 42 | % | ||||||||||||||||||
| Gathering and transportation costs | 0.82 | 0.77 | 0.05 | 6 | % | ||||||||||||||||||
| Depreciation, depletion, amortization, and accretion | 0.52 | 0.75 | (0.23) | (31) | % | ||||||||||||||||||
| General and administrative | 0.41 | 0.36 | 0.05 | 14 | % | ||||||||||||||||||
| Other | 0.18 | 0.07 | 0.11 | * | |||||||||||||||||||
|
Total
|
$ | 2.60 | $ | 2.54 | |||||||||||||||||||
| *Percentage not meaningful | |||||||||||||||||||||||
Lease Operating and Workover
The following table summarizes our components of lease operating expenses for the periods presented:
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||
| 2025 | 2024 | $ Change | % Change | ||||||||||||||||||||||||||||||||
| (in thousands, other than percentages and average costs) | Amount | Per Mcfe | Amount | Per Mcfe | |||||||||||||||||||||||||||||||
| Lease operating expenses | $ | 145,631 | $ | 0.48 | $ | 132,317 | $ | 0.46 | $ | 13,314 | 10 | % | |||||||||||||||||||||||
| Workover expenses | 7,242 | 0.02 | 4,674 | 0.01 | 2,568 | 55 | % | ||||||||||||||||||||||||||||
| Total lease operating and workover expense | $ | 152,873 | $ | 0.50 | $ | 136,991 | $ | 0.47 | $ | 15,882 | 12 | % | |||||||||||||||||||||||
Lease operating and workover expenses were $152.9 million, or $0.50 per Mcfe, for the year ended December 31, 2025, an increase of $15.9 million, or 12%,from $137.0 million, or $0.47 per Mcfe, for the year ended December 31, 2024. The increase was primarily attributable to $9.2 million of lease operating and workover expenses associated with BKV Barnett II, which was acquired in connection with the Bedrock Acquisition in September 2025. In addition, lease operating and workover expenses increased due to higher project activity related to our Pad of the Future program of $5.0 million and higher vehicle expenses of $1.0 million during 2025. In addition, during the year ended December 31, 2024, we received a credit of $1.5 million for a water sharing agreement that related to 2023. These increases were partially offset by lower compression and water expenses of $1.5 million and favorable timing of inspection fees of $0.6 million during the year ended December 31, 2025, compared to the year ended December 31, 2024.
Taxes Other Than Income
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. The increase in taxes other than income during the year ended December 31, 2025, compared to 2024, 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 associated with our operations in the Barnett of $1.4 million. Certain ad valorem and production taxes are not applicable to our NEPA properties.
Gathering and Transportation
Gathering and transportation expenses were $250.8 million, or $0.82per Mcfe, for the year ended December 31, 2025, which was an increase of $28.5 million, or 13%,from $222.4 million, or $0.77 per Mcfe, for the year ended December 31, 2024. This increasewas primarily attributable to higher natural gas and NGL production, which increased gathering and transportation expenses by $21.2 million, including an increase of $6.9 million related to production from BKV Barnett II. In addition, higher gathering and transportation rates for natural gas and NGLs of $8.5 million contributed to the increase in gathering and transportation expenses. This was offset by a $1.3 million decrease in gathering costs associated with our midstream business.
Depreciation, Depletion, Amortization, and Accretion
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. The decrease in depreciation, depletion, amortization, and accretion during the year ended December 31, 2025, compared to the year ended December 31, 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 $124.4 million, or $0.41 per Mcfe, for the year ended December 31, 2025, which was an increase of $19.9 million, or 19%, from $104.5 million, or $0.36per Mcfe, for the year ended December 31, 2024. The increase in general and administrative expenses during the year ended December 31, 2025, compared to the year ended December 31, 2024, was due to increases from Company-wide growth initiatives of $10.1 million in contract labor, employee-based compensation, and employee expenses, $7.2 million in consulting and information technology-related expenses, and $2.3 million in severance costs.
Other Operating Expenses
Other operating expenses were $54.9 million, or $0.18 per Mcfe, for the year ended December 31, 2025, which was an increase of$35.5 million, from $19.4 million, or $0.07 per Mcfe, for the year ended December 31, 2024. The increase wasprimarily driven by acquisition and transaction-related costs, including $15.8 million of integration costs associated with the Bedrock Acquisition, $5.5 million of costs and fees related to CCUS transactions, and $1.5 million in transaction costs incurred in connection with the BKV-BPP Power Joint Venture Transaction. In addition, other operating expenses increased due to a $6.0 million increase in gas purchases resulting from higher volumes and natural gas prices, a $5.6 million write-off related to an enterprise resource planning system, a $1.7 million increase in legal matters, and $1.5
million in project write-offs. These increases were partially offset by $2.0 million of waste emissions costs accrued in 2024 under the Inflation Reduction Act thatwere not accrued in 2025 due to changes in the regulatory environment.
Other Income (Expense)
Gains on contingent consideration liabilities. For 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 for the year ended December 31, 2024, consisting of again of $7.5 million and a gain of $2.2 million from the Devon Barnett Acquisition and the Exxon Barnett Acquisition, respectively. The contingent consideration provisions under these purchase agreements expired in 2024.
Earnings (losses) from equity affiliate. Earningsfrom 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. Earningsfrom 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, 2024, in connection with the early termination of our Term Loan Credit Agreement and Revolving Credit Agreement that took place in June 2024.
Interest expense. Interest expense was $28.6 millionfor the year ended December 31, 2025, which was a decrease of $16.9 million, from $45.6 millionfor the year ended December 31, 2024. The decrease in interest expense during the year ended December 31, 2025, was primarily due to lower interest rates and a lower outstanding balance on our RBL Credit Agreement, 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 year ended December 31, 2024, which was repaid in September 2024. We did not have any related party borrowings during the year ended December 31, 2025.
Interest income. Interest income was $1.6 million for the year ended December 31, 2025, which was a decrease of $2.3 million, from $3.9 million for the year ended December 31, 2024. The decrease was due to the cessation of interest earned on restricted cash following the repayment of the Term Loan Credit Agreement in June 2024, which had previously funded the debt service reserve account.
Income tax benefit (expense). For the year ended December 31, 2025, we had an income tax expense of $35.4 million, which was a change of $79.0 million, from an income tax benefit of $43.6 million for the year ended December 31, 2024. The year-over-year change was primarily due to a pre-tax income for the year ended December 31, 2025compared to a pre-tax loss for the year ended December 31, 2024.
Results of Operations
Comparison of the Year Ended December 31, 2024 and 2023
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 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:
| Year Ended December 31, | ||||||||||||||||||||||||||
| (in thousands, other than percentages) | 2024 | 2023 | $ Change | % Change | ||||||||||||||||||||||
| Revenues | ||||||||||||||||||||||||||
| Natural gas revenues | $ | 385,456 | $ | 509,846 | $ | (124,390) | (24) | % | ||||||||||||||||||
| NGL revenues | 165,508 | 187,860 | (22,352) | (12) | % | |||||||||||||||||||||
| Oil revenues | 6,606 | 8,445 | (1,839) | (22) | % | |||||||||||||||||||||
| Midstream revenues | 12,560 | 16,168 | (3,608) | (22) | % | |||||||||||||||||||||
| Derivative gains (losses), net | (34,152) | 238,743 | (272,895) | * | ||||||||||||||||||||||
| Marketing revenues | 10,668 | 8,710 | 1,958 | 22 | % | |||||||||||||||||||||
| Gain on sale of business | 7,080 | - | 7,080 | * | ||||||||||||||||||||||
| Gain on sales of assets, net | 3,523 | 2,207 | 1,316 | 60 | % | |||||||||||||||||||||
| Section 45Q tax credits | 14,021 | 701 | 13,320 | * | ||||||||||||||||||||||
|
Related party revenues
|
3,080 | 3,593 | (513) | (14) | % | |||||||||||||||||||||
|
Other
|
6,631 | 3,957 | 2,674 | 68 | % | |||||||||||||||||||||
| Total revenues and other operating income | $ | 580,981 | $ | 980,230 | ||||||||||||||||||||||
| *Percentage not meaningful | ||||||||||||||||||||||||||
Natural Gas Revenues
Our natural gas revenues decreasedby $124.4 million, or 24%,to $385.5 millionfor the year ended December 31, 2024, from $509.8 millionfor the year ended December 31, 2023. The impact of commodity price decreases, excluding the effect of derivative settlements, provided a $81.4 million decreasein year-over-year revenues (calculated as the change in the year-over-year average price times current year's production volumes). The decrease was also due to lowerproduction 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, which collectively accounted for a $43.0 milliondecrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price).
NGL Revenues
Our NGL revenues decreasedby $22.4 million, or 12%,to $165.5 millionfor the year ended December 31, 2024, from $187.9 millionfor the year ended December 31, 2023. The decrease was due to lowerproduction volumes during the year ended December 31, 2024, which accounted for a $12.4 million decreasein year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price). The decreasewas also due to the impact of commodity price decreases, excluding the effect of derivative settlements, which accounted for a $10.0 million decreasein year-over-year revenues (calculated as the change in the year-over-year average price times current year's production volumes).
Oil Revenues
Our oil revenues decreasedby $1.8 million, or 22%,to $6.6 millionfor the year ended December 31, 2024,from $8.4 millionfor the year ended December 31, 2023. The decreasewas due to lowerproduction volumes during the year ended December 31, 2024, which accounted for a $1.6 million decreasein year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price). The decreasewas also due to the impact of commodity price decreases, excluding the impact of derivative settlements, which accounted for a $0.2 million decreasein the year-over-year revenues (calculated as the change in the year-over-year average price times current year's production volumes).
Midstream Revenues
Our midstream revenues decreasedby $3.6 million, or 22%,to $12.6 millionfor the year ended December 31, 2024,from $16.2 millionfor the year ended December 31, 2023. This decreasewas primarily due to the divestiture of Chaffee of $2.6 million as we sold our Repsol Midstream Interest in connection with this sale. The remainder of the decrease was due to the changes in deal structures that reduced midstream transportation revenue while increasing third party gas sales.
Derivative Gains (Losses), Net
For the year ended December 31, 2024, we had net realized and unrealized losseson derivative contracts of $34.2 millioncompared to net realized and unrealized gainson derivative contracts of $238.7 millionfor the year ended December 31, 2023. The decreased lossesfor the year ended December 31, 2024,was primarily attributable to the significant asset positions as of December 31, 2023, reversing due to settlement during 2024, resulting in unrealized losses
of $146.7 million, which included the sale of call options in January 2024 limiting our 2026/2027 pricing upside, and is currently in a long term liability position. The year ended December 31, 2023, resulted in unrealized gains of $148.6 million, due to significant liability positions as of December 31, 2022 that reversed and settled during 2023. This was offset by higher realized gains during the year ended December 31, 2024, compared to the year ended December 31, 2023, of $22.3 million, due to slightly lower natural gas prices.
Marketing Revenues
Our marketing revenues increasedby $2.0 millionto $10.7 millionfor the year ended December 31, 2024from $8.7 millionfor 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. The increasein marketing revenues during the year ended December 31, 2024,compared to the year ended December 31, 2023, was primarily due to colder than normal weather in NEPA for the month of January 2024.
Gain on Sale of Business
For the year ended December 31, 2024, we sold our wholly-owned subsidiary, Chaffee, for $104.4 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 $7.1 million.
Gains (Losses) on Sales of Assets, Net
For the year ended December 31, 2024, we sold other properties for $5.0 million in proceeds, which resulted in a gain on the sale of these properties of $3.6 million. For the year ended December 31, 2023, we sold land and our solar assets for $6.7 millionin proceeds, which resulted in a gain on sale of assets of $2.2 million.
Section 45Q Tax Credits
Our Section 45Q tax credits increased by $13.3 million to $14.0 million for the year ended December 31, 2024 from $0.7 million for the year ended December 31, 2023. This increase was due to higher volumes of CO2waste sequestered in 2024, which started in the fourth quarter of 2023. Our Section 45Q tax credits relate to CO2 waste sequestration activities associated with our Barnett Zero Project.
Related Party Revenues
We generate a portion of our revenues from a management fee from BKV-BPP Power. Our related party revenues were $3.1 million for the year ended December 31, 2024, compared to $3.6 millionfor the year ended December 31, 2023. Related party revenues decreased during the year ended December 31, 2024, compared to the year ended December 31, 2023, from the decrease in operating fee income with BKV-BPP Power of $0.5 million due to contracted rate decreases.
Other Revenues
We generate a portion of our revenues from the sale of third-party natural gas. Other revenues was $6.6 million for the year ended December 31, 2024, compared to $4.0 millionfor the year ended December 31, 2023. The increase year-over-year was primarily due to an increase in third party gas sales of $2.6 million.
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:
| Year Ended December 31, | |||||||||||||||||||||||
| (in thousands, other than percentages and average costs) | 2024 | 2023 | $ Change | % Change | |||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||
| Lease operating and workover | $ | 136,991 | $ | 150,647 | $ | (13,656) | (9) | % | |||||||||||||||
| Taxes other than income | 35,009 | 72,290 | (37,281) | (52) | % | ||||||||||||||||||
| Gathering and transportation costs | 222,391 | 248,990 | (26,599) | (11) | % | ||||||||||||||||||
| Depreciation, depletion, amortization, and accretion | 217,533 | 223,370 | (5,837) | (3) | % | ||||||||||||||||||
| General and administrative | 104,473 | 114,688 | (10,215) | (9) | % | ||||||||||||||||||
| Other | 19,385 | 12,625 | 6,760 | 54 | % | ||||||||||||||||||
|
Total operating expense
|
$ | 735,782 | $ | 822,610 | |||||||||||||||||||
| Average costs per Mcfe | |||||||||||||||||||||||
| Lease operating and workover | $ | 0.47 | $ | 0.48 | $ | (0.01) | (2) | % | |||||||||||||||
| Taxes other than income | 0.12 | 0.23 | (0.11) | (48) | % | ||||||||||||||||||
| Gathering and transportation costs | 0.77 | 0.79 | (0.02) | (3) | % | ||||||||||||||||||
| Depreciation, depletion, amortization, and accretion | 0.75 | 0.71 | 0.04 | 6 | % | ||||||||||||||||||
| General and administrative | 0.36 | 0.37 | (0.01) | (3) | % | ||||||||||||||||||
| Other | 0.07 | 0.04 | 0.03 | 75 | % | ||||||||||||||||||
|
Total
|
$ | 2.54 | $ | 2.62 | |||||||||||||||||||
| *Percentage not meaningful | |||||||||||||||||||||||
Lease Operating and Workover
The following table summarizes our components of lease operating expenses for the periods presented:
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||
| 2024 | 2023 | $ Change | % Change | ||||||||||||||||||||||||||||||||
| (in thousands, other than percentages and average costs) | Amount | Per Mcfe | Amount | Per Mcfe | |||||||||||||||||||||||||||||||
| Lease operating expenses | $ | 132,317 | $ | 0.46 | $ | 142,911 | $ | 0.46 | $ | (10,594) | (7) | % | |||||||||||||||||||||||
| Workover expenses | 4,674 | 0.01 | 7,736 | 0.02 | (3,062) | (40) | % | ||||||||||||||||||||||||||||
| Total lease operating and workover expense | $ | 136,991 | $ | 0.47 | $ | 150,647 | $ | 0.48 | $ | (13,656) | (9) | % | |||||||||||||||||||||||
Lease operating and workover expenses were $137.0 million,or $0.47per Mcfe, for the year ended December 31, 2024, which was a decreaseof $13.7 million, or 9%, from $150.6 million, or $0.48per Mcfe, for the year ended December 31, 2023. The decreasein lease operating and workover expenses during the year ended December 31, 2024,compared to the same period in 2023,was due to decreases in compression and water expenses of $5.6 million, materials and labor of $3.6 million, and repairs and maintenance of $2.7 million, all of which were due to cost savings initiatives that began during the second half of 2023 and the divestiture of Chaffee and certain non-operating upstream assets in Chelsea. In addition, during the year ended December 31, 2024, we received a credit of $1.5 million for a water sharing agreement that related to 2023.
Taxes Other Than Income
Taxes other than income were $35.0 million, or $0.12per Mcfe, for the year ended December 31, 2024, which was a decreaseof $37.3 million, or 52%, from $72.3 million, or $0.23per Mcfe, for the year ended December 31, 2023. The decreasein taxes other than income during the year ended December 31, 2024,compared to 2023was due to decreases in ad valorem and property taxes, and natural gas and NGL production taxes, both associated with our operations in the Barnett of $27.8 million and $9.2 million, respectively. Certain ad valorem and production taxes are not applicable to our NEPA properties.
Gathering and Transportation
Gathering and transportation expenses were $222.4 million, or $0.77per Mcfe, for the year ended December 31, 2024, which was a decreaseof $26.6 million, or 11%, from $249.0 million, or $0.79per Mcfe, for the year ended December 31, 2023. This decreasewas driven by decreased production in the Barnett and natural gas rate decreases of $15.7 million and $12.2 million, respectively. This was offset by new contracts we entered into during 2024 where we started outsourcing gathering costs with our midstream business of $1.3 million.
Depreciation, Depletion, Amortization, and Accretion
Depreciation, depletion, amortization, and accretion was $217.5 million, or $0.75per Mcfe, for the year ended December 31, 2024, which was a decreaseof $5.8 million, or 3%, from $223.4 million, or $0.71per Mcfe, for the year ended December 31, 2023. The decreasein depreciation, depletion, amortization, and accretion during the year ended December 31, 2024,compared to the year ended December 31, 2023,was due to lower production during the year ended December 31, 2024, compared to the same period in the prior year, offset by lower 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.
General and Administrative
General and administrative expenses were $104.5 million, or $0.36per Mcfe, for the year ended December 31, 2024, which was a decreaseof $10.2 million, or 9%, from $114.7 million, or $0.37per Mcfe, for the year ended December 31, 2023. The decreasewas driven by a $22.2 million reduction in equity-based compensation related to the expiration of performance-based restricted stock units ("PRSU") on December 31, 2023, and an $8.0 million decrease in management fees following the termination of the Verde CO2 contract in November 2023. These cost savings were partially offset by a $12.6 million acceleration of time-based restricted stock units ("TRSU") recognized upon the IPO (including $2.5 million in payroll taxes), $3.5 million in stock compensation expense under the 2024 Equity and Incentive Compensation Plan (the "2024 Plan"), and $3.7 million in higher payroll costs due to increased headcount in 2024.
Other Operating Expenses
Other operating expenses were $19.4 million, or $0.07per Mcfe, for the year ended December 31, 2024, which was an increaseof $6.8 million, or 54%,from $12.6 million, or $0.04per Mcfe, for the year ended December 31, 2023. The increasein other operating expenses during the year ended December 31, 2024 was primarily driven by the following factors: $5.3 million in CCUS operating expenses for CO2purchases and fuel and increased legal contingencies, $3.4 million in higher emissions monitoring costs, $2.1 million in well clean up costs and expenses related to a potential CCUS equity raise and investments, and $1.0 million in costs from the newly enacted EPA fees under the Inflation Reduction Act. These increases were offset by $3.6 million of inventory restocking and rig termination fees, $2.0 million of prior year inventory restocking fees and write-offs, and $0.7 million of lower midstream operating expenses and gas purchases.
Other Income (Expense)
Gains on contingent consideration liabilities.We recognized a gainon 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 in 2024, compared to $38.4 millionin 2023, which was a decreaseof $28.7 million. The decrease was primarily attributable to lower gains on contingent consideration liabilities with the Devon Barnett Acquisition and the Exxon Barnett Acquisition. Gains related to the Devon Barnett Acquisition were $7.5 million in 2024 compared to $25.0 million in 2023, and gains related to the Exxon Barnett Acquisition were $2.2 million in 2024 compared to $13.4 million in 2023. The higher gains in 2023 were 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 that year compared to slight decreases in 2024.
Earnings from equity affiliate. Earnings from our equity affiliate was $10.4 millionfor 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. 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, 2024, in connection with the early termination of our Term Loan Credit Agreement and Revolving Credit Agreement that took place in June 2024.
Interest expense. Interest expense was $45.6 millionfor the year ended December 31, 2024, which was a decreaseof $24.4 millionfrom $69.9 millionfor the year ended December 31, 2023. The decreasein interest expense during the year ended December 31, 2024,was primarily due to lower interest rates on our RBL Credit Agreement, which we entered into
on June 11, 2024, and the subsequent paydown 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 was $5.2 millionfor the year ended December 31, 2024, which was a decreaseof $1.9 million from $7.1 millionfor the year ended December 31, 2023. The decrease was primarily due to the payment in full of the loan with BNAC in 2023, which provided nine months of interest compared to none in 2024. This was slightly offset by an increase in the interest on the loan under the related party loan with BNAC, which provided for seven months of interest in 2023compared to a full year in 2024.
Income tax benefit (expense).For the year ended December 31, 2024, we had anincome tax benefitof $43.6 million,which was a change of $71.8 million,from an income tax expense of $28.2 millionfor the year ended December 31, 2023. The year-over-year change was primarily due 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 CO2waste 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.
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 uses of cash during the year ended December 31, 2025wereto fund the Bedrock Acquisition and the development of our natural gas properties. Our primary uses of cash during the years ended December 31, 2024 and 2023 were to pay down debt and fund the development of our natural gas properties.
During the years ended December 31, 2025, 2024, and 2023, cash paid for capital expenditures was $300.2 million, $100.9 million, and $187.7 million, respectively. Our current estimated budget for total accrued capital expenditures in 2026 is approximately $410 million to $560 million on a Company-wide basis. To help fund these capital expenditures, we expect to receive approximately $50 million to $70 million of capital contributions from our joint venture partners in our CCUS and power businesses. Expected contributions from our joint venture partners would bring our net 2026 capital expenditure range to $360 million to $490 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.
On January 14, 2026, we entered into a manufacturing reservation agreement related to a planned power generation project. Under the agreement, we are committed to pay up to an aggregate of $80.0 million in reservation fees, scheduled in phases during 2026, to secure future manufacturing capacity through 2028 for turbines with up to approximately 1,230 megawatts in total generation capacity. Amounts paid are generally non-refundable and will be credited against the purchase price if a definitive supply agreement is executed.
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 the 2030 Senior Notes, the 2025 Equity Offering, and our commodity hedges in place will provide sufficient liquidity to fund our operations and our capital expenditures into 2026, 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 years ended December 31, 2025, 2024, and 2023 (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| Net cash provided by operating activities | $ | 242,707 | $ | 118,538 | $ | 123,076 | |||||||||||
| Net cash provided by (used in) investing activities | (564,903) | 36,066 | (177,848) | ||||||||||||||
| Net cash provided by (used in) financing activities | 506,740 | (304,805) | 66,713 | ||||||||||||||
| Net increase (decrease) in cash, cash equivalents, and restricted cash | $ | 184,544 | $ | (150,201) | $ | 11,941 | |||||||||||
Cash flows provided by operating activities. Net cash provided by operating activities was $242.7 million for the year ended December 31, 2025, compared to $118.5 million for the year ended December 31, 2024. The increase of $124.2 million was due to a $69.1 million increase in income from operations (excluding non-cash items), resulting from higher natural gas volumes and prices compared to 2024, a favorable $45.3 million change in working capital, and a $44.1 million decrease in cash paid for interest. These increases were offset by $23.5 million of cash received in January 2024 for the sale of call options and $16.2 million of cash paid in February 2025 for the purchase of put options.
Net cash provided by operating activities was $118.5 million for the year ended December 31, 2024, compared to $123.1 million for the year ended December 31, 2023. The decrease of $4.5 million was due to a $41.5 million decrease in income from operations (excluding non-cash items), resulting from lower natural gas prices compared to 2023, an unfavorable $17.3 million change in working capital, $10.0 million in distributions from the BKV-BPP Power Joint Venture made in 2023, and $3.9 million of transaction costs associated with the sale of Chaffee and certain non-operated upstream assets in Chelsea. These decreases were offset by reduced settlements of contingent liabilities of $45.0 million and cash received from the sale of call options of $23.5 million.
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 $564.9 million for the year ended December 31, 2025, compared to net cash provided by investing activities of $36.1 million for the year ended December 31, 2024. The increase in cash outflows of $601.0 million was due to the $272.1 million of cash paid for the Bedrock Acquisition, a $172.1 million increase in capital expenditures (excluding CCUS activities), and a $27.1 million increase in CCUS expenditures for the year ended December 31, 2025 compared to the prior year. These outflows were offset by $2.1 million of cash acquired in consolidation of BKV-BPP Cotton Cove and a $1.8 million increase in proceeds from sales of assets for the year ended December 31, 2025 compared to the prior year.
Net cash provided by investing activities was $36.1 million for the year ended December 31, 2024, compared to net cash used in investing activities of $177.8 million for the year ended December 31, 2023. The increase in cash inflows of $213.9 million was due to the $132.6 million of total proceeds from the sale of Chaffee and certain non-operated upstream assets held by Chelsea during the year ended December 31, 2024. The change was also due to a decrease of $49.0 million in capital expenditures (excluding CCUS activities), a $37.8 million reduction of CCUS-related expenditures, and a $4.9 million decrease in cash used for acquisition of natural gas properties for the year ended December 31, 2024 compared to the prior year. These inflows were offset by a reduction of $10.4 million of cash proceeds from other investing activities for the year ended December 31, 2024 compared to the prior year.
The following table presents our capital expenditures (excluding leasehold costs and acquisitions) on an accrual basis for the years ended December 31, 2025, 2024, and 2023 and reconciles to cash flows used for capital expenditures in the consolidated statements of cash flows.
| Year Ended December 31, | |||||||||||||||||
| 2025 | 2024 | 2023 | |||||||||||||||
| (in thousands) | |||||||||||||||||
| Total use of cash and cash equivalents for capital expenditures | $ | (300,165) | $ | (100,916) | $ | (187,716) | |||||||||||
| (Increase) decrease in accrued capital expenditures | (18,344) | (16,710) | 23,863 | ||||||||||||||
| Capital expenditures (accrued) | $ | (318,509) | $ | (117,626) | $ | (163,853) | |||||||||||
Cash flows provided by (used in) financing activities. Net cash provided byfinancing activities was $506.7 millionfor the year ended December 31, 2025, primarily driven by $500.0 million of proceeds from the issuance of the 2030 Senior Notes and $170.6 million of net proceeds from the 2025 Equity Offering (after deducting underwriting discounts and commissions). Financing inflows also included $19.8 million of cash contributions from noncontrolling interest. These inflows were partially offset by $165.0 million of net debt repayments, $15.9 million in payments of debt issuance costs, $1.6 million of net shares withheld for income taxes upon vesting of restricted stock units, and $1.2 million of cash distributions to noncontrolling interest.
Net cash used in financing activities was $304.8 million for the year ended December 31, 2024, which consisted of $493.0 million of net payments on debt, $53.2 million of payments for taxes related to net share settlement of restricted stock units, and $18.3 million for payments of debt issuance costs and debt extinguishment costs. These outflows were partially offset by $265.7 million of net proceeds from the issuance of common stock from our IPO (after deducting underwriting discounts and commissions).
Net cash provided by financing activities was $66.7 million for the year ended December 31, 2023, which consisted of $258.5 million and $117.0 million of advances received from the Revolving Credit Facilities and Revolving Credit Agreement, respectively. In addition, we received $150.0 million of capital contributions from BNAC in exchange for 7,500,000 shares of our common stock. These inflows were offset by $114.0 million, $272.5 million and $66.0 million of repayments made on our Term Loan Credit Agreement, Revolving Credit Facilities and Revolving Credit Agreement, respectively.
Working Capital
As of December 31, 2025, we had cash and cash equivalents of $199.4 million, compared to $14.9 million of cash and cash equivalents as of December 31, 2024. Our net working capital surpluswas $170.0 million as of December 31, 2025, compared to a working capital deficitof $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, BKV Upstream Midstream issued in a private placement $500.0 million of 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 outstanding borrowings under the RBL Credit Agreement and fund a portion of the cash consideration for the Bedrock Acquisition, with the remainder of the purchase price being funded with shares of our common stock. In connection with the issuance of the 2030 Senior Notes, we recorded debt issuance costs of $13.6 million, which are amortized to interest expense on the 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 BKV Upstream Midstream and its restricted subsidiaries.
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. 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, 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 as described in the indenture governing the 2030 Senior Notes, plus accrued and unpaid interest.
Loan Agreements and Credit Facilities
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 the RBL Credit Agreement's 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 December 31, 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 senior 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 March 6, 2026, $110.0 million of revolving borrowings and $15.0 million of letters of credit were outstanding under the RBL Credit Agreement, leaving $675.0 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.
Revolving Credit Agreements and Term Loan Credit Agreement
On June 11, 2024, using the funds from the RBL Credit Agreement, we repaid the outstanding debt balances under (i) the Term Loan Credit Agreement, (ii) the Revolving Credit Agreement, and (iii) our loan agreement previously entered into in March 2022 with Standard Charter Bank (the "SCB Credit Facility"), in each case with proceeds from the loans under the RBL Credit Agreement and cash on hand. The Term Loan Credit Agreement, the Revolving Credit Agreement, and the SCB Credit Facility were terminated concurrently with the repayment of the remaining amounts owed thereunder.
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, as applicable, we do not have the ability to unilaterally cause BKV-BPP Power or BKV-BPP Cotton Cove to make distributions. During the years ended December 31, 2025 and 2024, no distributions were made by BKV-BPP Power or BKV-BPP Cotton Cove. During the year ended December 31, 2023, BKV-BPP Power made a distribution of $10.0 million to BKV Corporation. 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, following the closing of the BKV-BPP Power Joint Venture Transaction on January 30, 2026, any additional capital contributions to BKV-BPP Power must be approved by a majority of BKV-BPP Power's twelve member boardof managers, nine of whom are appointed by us and three of whom are appointed by BPPUS. Similarly, any additional capital contributions to BKV-BPP Cotton Cove must receive the unanimous approval of the BKV-BPP Cotton Cove Joint Venture'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. Subsequent to these transactions, BKV dCarbon Ventures contributed an additional $5.8 million, for a total of $9.0 million, and BPPUS contributed an additional $5.5 million, for a total of $8.8 million, for the year ended December 31, 2025.
On October 29, 2025, we entered into a Membership Interest Purchase Agreement with BPPUS to acquire one-half of the limited liability company interests of the BKV-BPP Power Joint Venture then held by BPPUS upon the terms and subject to the conditions of the purchase agreement. On January 30, 2026, we completed the BKV-BPP Power Joint Venture Transaction for aggregate consideration consisting of $115.1 million in cash and 5,315,390 shares of our common stock.
We funded the cash consideration with a combination of cash on hand and the net proceeds from the 2025 Equity Offering. For additional information, see Note 14 - Investmentsand Note 19 - Subsequent Events.
For more information about our joint ventures with BPPUS, see "-Risk Factors -Risks Related to Our Power Generation Business -We operate our power generation business through a joint venture that requires the consent of BPPUS for certain material actions." and "Risk Factors -Risks Related to Our CCUS Business -We operate the Cotton Cove Project through a joint venture that requires the consent of BPPUS for certain material actions."
Internal Controls and Procedures
As an accelerated filer, we are required to comply with the SEC's rules implementing Section 404(a) of the Sarbanes-Oxley Act of 2022. Accordingly, management is required to assess, and report on the effectiveness of our internal control over financial reporting as of the end of each fiscal year, beginning with this Annual Report on Form 10-K. In addition, we are required to disclose any change in our internal control over financial reporting that occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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 December 31, 2025, our material off-balance sheet arrangements and transactions included natural gas transportation commitments of $259.4 million and letters of credit of $15.0 million against the RBL Credit Agreement. For further information regarding these arrangements, see Note 16 - Commitments and Contingenciesto our consolidated financial statements and under "-Liquidity and Capital Resources - Loan Agreements and Credit Facilities."
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. For more information, see Item 8 of Part II, Financial Statements and Supplementary Data, Note 2 - Summary of Significant Accounting Policies.
Accounting for Natural Gas and NGL Reserves Quantities and Standardized Measure of Future Cash Flows
We use the successful efforts method of accounting for natural gas producing activities. Under this method, the costs to acquire mineral interests in natural gas properties, to drill and equip exploratory leases that find proved reserves, and to drill and equip development leases and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized, or suspended, pending determination of whether the wells have proved reserves. If we determine the wells do not have proved reserves, the costs are charged to expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if sufficient reserves have been found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. We reassess the operational viability of our exploratory wells on at least a quarterly basis, which may involve use of significant judgment. If we determine that future appraisal drilling or development activities are unlikely to occur, the associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year.
The processes we use to estimate quantities of proved and unproved developed natural gas, NGL, and oil reserves and their values, future production rates, and future development costs are highly complex and requires significant subjectivity and estimation in the evaluation of available geological, engineering, and economic data. The accuracy of any reserves estimate is a function of the quality of data available and of engineering and geological interpretation. The data used in developing reserves estimates may change significantly over time as a result of numerous factors, including, but not limited to, evolving production history, additional development activity, and continual reassessment of the viability of production under varying economic conditions. Although we take every reasonable effort to ensure our reserves estimates are representative of our actual reserves - for example, by involving independent reserves engineers in the assessment of the estimates - the subjective decisions and variances in the data available could give rise to revisions that could materially impact the accompanying historical consolidated financial statements.
Impairment of Natural Gas Properties
The evaluation of impairment of proved and unproved natural gas properties is considered a critical accounting policy due to the significant judgment and estimation involved in ascertaining the probability of future events, such as future market values of natural gas, NGLs, and oil, future production costs, and future production volumes, as well as fair valuation of the properties in question. Changes in the judgments and estimates used in our evaluation of impairment, including, but not limited to, the expected future cash flows from natural gas reserves on our properties, could result in the cost of our proved and unproved properties not being recoverable and give rise to the need to record an impairment loss. Similarly, in the instance we determine the property is not recoverable, changes in the estimates and assumptions underlying the model used to derive the fair value of the properties in question may impact the output of the model, which could give rise to significant changes in the amount of impairment loss to record.
Litigation and Environmental Contingencies
In the ordinary course of business, we may at times be subject to claims and legal actions. Management does not believe the impact of such matters will have a material adverse effect on our financial position or results of operations.
We are subject to extensive federal, state, and local environmental laws and regulations, which may materially affect our operations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.
In our acquisition of existing assets, we may not be aware of what environmental safeguards were taken during the time such assets were operated, and it is possible we may acquire certain environmental liabilities along with such assets.
We maintain comprehensive insurance coverage that we believe is adequate to mitigate the risk of any adverse financial effects associated with these risks. However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still fall upon us. No claim has been made, nor are we aware of any liability which we may have, as it relates to any material environmental cleanup, restoration, or the violation of any rules or regulations relating thereto.
Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed as incurred. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the cost can be reasonably estimated.
Accounting for Variable Interest Entities
As described in Note 14 - Investmentsin our 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 1,791,155 Class B Units (the "Class B Units") at $10.00 per unit as of December 31, 2025. We determined that the Class B Units should be classified as noncontrolling interest within mezzanine equity on the Company's 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 consolidated balance sheets. The Class B Units also have a multiple on invested 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 two-year period (using the effective interest method) with the accretion accounted for as a dividend paid to the Class B Member.
Recent Accounting Pronouncements
See Note 2 - Summary of Significant Accounting Policiesto our consolidated financial statements included in this Annual Report on Form 10-K for more information about recent accounting pronouncements, the timing of their adoption, and our assessment, to the extent we have made one, of their potential impact on our financial condition and our results of operations.
Emerging Growth Company Status
We are an "emerging growth company" as defined in Section 2(a)(19) of the Securities Act, 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 Annual Report on Form 10-K 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 (i) we become a "large accelerated filer," which requires that the market value of our common equity held by non-affiliates be at least $700 million as of the end of the most recently completed second fiscal quarter, (ii) our gross revenues for any fiscal year equal or exceed $1.235 billion, or (iii) we issue more than $1.0 billion of non-convertible debt in any three-year period, then we will cease to be an emerging growth company prior to the end of such five-year period. We expect to lose our emerging growth company status as of December 31, 2026.
BKV Corporation published this content on March 06, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on March 06, 2026 at 21:45 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]