BKV Corporation

08/06/2026 | Press release | Distributed by Public on 08/06/2026 12:26

Quarterly Report for Quarter Ending June 30, 2026 (Form 10-Q)

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 unaudited condensed consolidated financial statements and related notes included in Item 1 of Part I, Financial Statements in this Quarterly 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, 2025 included in our 2025 Annual Report on Form 10-K filed on March 6, 2026. 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 Quarterly Report on Form 10-Q.
Recent Developments
•Initial injection at Cotton Cove and Eagle Ford CCUS Projects. The Cotton Cove project owned by our BKV-BPP Cotton Cove Joint Venture commenced commercial CO2 sequestration operations on April 2, 2026, and the Eagle Ford project owned by our BKV-CIP Joint Venture commenced commercial CO2 sequestration operations on June 10, 2026. The Cotton Cove facility receives CO2 waste from BKV's co-located, owned and operated gas processing plant, while the Eagle Ford facility receives CO2 waste from a nearby gas processing plant owned and operated by a diversified midstream energy company. We estimate that the Cotton Cove project will geologically sequester up to approximately 32,000 metric tons of CO2 per year and that the Eagle Ford project will geologically sequester up to approximately 90,000 metric tons of CO2 per year.
Operational and Financial Highlights
Below are some highlights of our operating and financial results for the three and six months ended June 30, 2026:
•Production of natural gas, NGLs, and oil was 89.0 Bcfe, or 978.3 MMcfe/d and 172.3 Bcfe, or 951.8 MMcfe/d, respectively.
•Average realized product prices, excluding the impact of settled derivatives, were $2.49 per Mcfe and $2.96 per Mcfe, respectively.
•Power generation of 2,222 GWh and 4,203 GWh, respectively, from the Temple Plants and capacity factors of 69.6% and 66.0%, respectively.
•Upstream/Midstream production revenues were $221.9 million and $509.6 million, respectively, and Power revenues were $74.4 million and $143.4 million respectively.
•Net income attributable to BKV was $75.8 million and $119.9 million, respectively.
•Net cash provided by operating activities for the six months ended June 30, 2026 was $181.7 million.
•Accrued capital expenditures for the six months ended June 30, 2026 were $191.0 million.
Factors That Affect Comparability of Our Financial Condition and Results of Operations
Our business depends on many factors, including, but not limited to: (i) commodity prices, (ii) market supply and demand for natural gas, NGLs, and power, and (iii) upstream and power capital and operating 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, NGL, and power industries are each cyclical and seasonal, and commodity prices are highly volatile, and we expect these prices to continue to remain volatile in the near future. In order to manage our market exposure to price volatility, we utilize derivative contracts in connection with our operations to provide an economic hedge of our exposure to commodity price risks associated with anticipated future natural gas and NGL production and power generation. However, there are still market risks beyond our control that may impact our financial condition, results of operations, and cash flows.
Supply, Demand, Market Risk, and the Impact on Natural Gas, NGLs, and Power Prices. Natural gas, NGL, and power prices are subject to large fluctuations in response to relatively minor changes in the demand for natural gas, NGLs, and power. Natural gas and NGL 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, industry-wide supply chain disruptions, widespread shortages of labor, material, and services. Other factors impacting supply and demand include weather conditions (including severe weather events), pipeline capacity constraints, basis differentials, export capacity, supply chain quality and availability. Power prices in the ERCOT market are subject to large fluctuations in response to relatively minor changes in the weather, time of day and generation mix, along with current and expected supply and demand dynamics in the ERCOT market. The majority of the factors noted above are outside of our control.
Power Business. The consolidated financial statements include the results of our power business for all periods presented, reflecting the retrospective recast of prior periods, as the BKV-BPP Power Joint Venture Transaction was accounted for as a transfer between entities under common control. However, the power business has historically operated separately from our other operations and has a different operating profile. Businesses engaged in power generation are subject to seasonal, daily, and hourly fluctuations in demand, periods of peak load, and changes in supply and demand dynamics, which can result in variability in revenues and operating costs. In addition, the power business is more capital intensive, requiring ongoing investments in land, modular generation equipment, and turbine generators, and its growth is dependent on access to capital and the ability to obtain necessary commercial agreements. As a result, our consolidated results may not be fully comparable across periods and may not be indicative of the results that would have been achieved if the power business had been operated as part of our company during those periods or of our future performance.
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 and Power Data
The following table presents our historical production volumes for the periods presented:
Three Months Ended June 30, Six Months Ended June 30,
2026 2025 2026 2025
Production Data
Natural gas (MMcf) 72,785 58,328 140,863 112,451
NGLs (MBbls) 2,650 2,535 5,139 4,877
Oil (MBbls) 56 44 96 97
Total volumes (MMcfe) 89,021 73,802 172,273 142,295
Average daily total volumes (MMcfe/d) 978.3 811.0 951.8 786.2
Power Data
Power generation (GWh) 2,222 1,913 4,203 3,500
Fuel consumption (MMBtu) 15,973 13,595 29,989 24,827
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 of 2025, results for 2026 are not comparable to prior periods. In addition, the consideration paid, including cash, common stock, and repayment of indebtedness, affected our liquidity, leverage, and weighted 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 Quarterly Report on Form 10-Q.
Sources of Revenues
Our core businesses are the production of natural gas and the generation of natural gas-fired power from our owned and operated assets. Currently, a significant portion of our revenues are derived from the sale of our natural gas production and the NGLs that are extracted from processing our natural gas, as well as from the sale of our power generated out of the Temple Plants and sold to a third party at either market or negotiated contract terms. A smaller portion of our revenues are generated 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. In addition, we are exposed to fluctuations in wholesale electricity prices, primarily in the ERCOT market, related to our power generation and marketing activities. Power prices are influenced by several factors, including natural gas prices, weather, and market supply and demand. 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:
Three Months Ended June 30, Six Months Ended June 30,
2026 2025 2026 2025
Average prices:
Natural gas ($/Mcf)
Average NYMEX Henry Hub price $ 2.90 $ 3.44 $ 3.97 $ 3.55
Average natural gas realized price (excluding derivatives) $ 2.14 $ 2.67 $ 2.81 $ 2.88
Average natural gas realized price (including derivatives) $ 2.60 $ 2.83 $ 2.85 $ 2.84
Differential $ (0.76) $ (0.77) $ (1.16) $ (0.67)
NGLs ($/Bbl)
Average NGL realized price (excluding derivatives) $ 23.00 $ 16.42 $ 20.57 $ 17.70
Average NGL realized price (including derivatives) $ 25.21 $ 16.41 $ 22.17 $ 16.64
Oil ($/Bbl)
Average oil realized price $ 86.91 $ 57.66 $ 79.49 $ 61.82
High and low daily spot prices
Natural gas ($/Mcf)
High NYMEX Henry Hub $ 3.34 $ 4.21 $ 30.72 $ 9.86
Low NYMEX Henry Hub $ 2.54 $ 2.65 $ 2.54 $ 2.65
Oil ($/Bbl)
High NYMEX WTI $ 114.58 $ 75.89 $ 114.58 $ 80.73
Low NYMEX WTI $ 70.30 $ 58.50 $ 56.01 $ 58.50
Power
Average power price ($/MWh) (excluding derivatives) $ 31.88 $ 29.13 $ 39.41 $ 32.92
Average power price ($/MWh) (including derivatives) $ 41.59 $ 45.10 $ 46.04 $ 48.63
Average natural gas cost ($/Mcf) $ 2.68 $ 2.93 $ 3.33 $ 3.47
Business Segment Results of Operations
The following sections present our results of operations for our two reportable segments, which include Upstream/Midstream and Power. Management believes this information is useful to investors in understanding the Company's financial condition, results of operations, and trends and uncertainties. See Note 14 - Reportable Segments to our condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q.
Upstream/Midstream Segment
Comparison of the Three Months Ended June 30, 2026 and 2025:
Three Months Ended June 30,
(in thousands, other than percentages) 2026 2025 Change % Change
Production volume
Total production volumes (MMcfe) 89,021 73,802 15,219 21 %
Average daily production (MMcfe/d)
978.3 811.0 167.3 21 %
Average realized price (excluding derivatives) $ 2.49 $ 2.71 $ (0.22) (8) %
Average realized price (including derivatives) $ 2.93 $ 2.83 $ 0.10 4 %
Revenues and other operating income
Natural gas revenues $ 156,101 $ 155,562 $ 539 - %
NGL revenues 60,960 41,630 19,330 46 %
Oil revenues 4,867 2,537 2,330 92 %
Derivative gains, net 95,284 112,208 (16,924) (15) %
Marketing revenues 26,162 6,968 19,194 *
Other 328 140 188 *
Total revenues and other operating income 343,702 319,045 24,657
Operating expenses
Lease operating and workover 44,482 34,176 10,306 30 %
Marketing expense 22,516 4,321 18,195 *
Taxes other than income 11,583 13,404 (1,821) (14) %
Gathering and transportation 68,095 63,026 5,069 8 %
Depreciation, depletion, amortization, and accretion 42,821 37,644 5,177 14 %
General and administrative 22,747 14,782 7,965 54 %
Other operating expenses
1,420 3,403 (1,983) (58) %
Total operating expenses 213,664 170,756 42,908
Income from operations $ 130,038 $ 148,289 $ (18,251)
Per unit costs
Lease operating and workover $ 0.50 $ 0.46 $ 0.04 9 %
Marketing expense $ 0.25 $ 0.06 $ 0.19 *
Taxes other than income $ 0.13 $ 0.18 $ (0.05) (28) %
Gathering and transportation $ 0.76 $ 0.85 $ (0.09) (11) %
Depreciation, depletion, amortization, and accretion $ 0.48 $ 0.51 $ (0.03) (6) %
General and administrative $ 0.26 $ 0.20 $ 0.06 30 %
Other operating expenses
$ 0.02 $ 0.05 $ (0.03) (60) %
Total $ 2.40 $ 2.31 $ 0.09
*Percentage not meaningful
Natural Gas Revenues
Our natural gas revenues slightly increased by $0.5 million, to $156.1 million for the three months ended June 30, 2026, from $155.6 million for the three months ended June 30, 2025. The increase was due to higher production volumes during the three months ended June 30, 2026, which accounted for a $38.6 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price). The increase was offset by commodity price decreases, excluding the effect of derivative settlements, which provided a $38.0 million decrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes).
NGL Revenues
Our NGL revenues increased by approximately $19.3 million, or 46%, to $61.0 million for the three months ended June 30, 2026, from $41.6 million for the three months ended June 30, 2025. The increase was due to commodity price increases, excluding the effect of derivative settlements, which accounted for a $17.4 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 slightly higher production volumes during the three months ended June 30, 2026, which accounted for a $1.9 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 $2.3 million, or 92%, to $4.9 million for the three months ended June 30, 2026, from $2.5 million for the three months ended June 30, 2025. The increase was primarily due to the impact of commodity price increases, excluding the effect of derivative settlements, which accounted for a $1.6 million increase in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes). The increase was also due to higher production volumes during the three months ended June 30, 2026, which accounted for a $0.7 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).
Derivative Gains, Net
For the three months ended June 30, 2026, our Upstream/Midstream segment had net realized and unrealized gains on derivative contracts of $95.3 million compared to $112.2 million for the same period in 2025. The decrease in gains for the three months ended June 30, 2026, was primarily attributable to our open derivative positions, which were in an unrealized gain position of $56.0 million, compared to an unrealized gain position of $102.9 million for the same period in 2025. The current period primarily reflects slight decreases in the forward curve of natural gas prices relative to the previous quarter, whereas the prior year period reflected significant decreases in future natural gas prices compared to March 31, 2025. Offsetting the decrease in derivative gains, net was our realized gains of $39.3 million, compared to $9.3 million for the three months ended June 30, 2025, which were due to lower natural gas prices settled in the current period compared to the same period in the prior year.
Marketing Revenues
Our marketing revenues were derived under our marketing agreement with a third party pursuant to which we received a fixed percentage of all net income realized in the resale of our and other producers' hydrocarbons. During the three months ended June 30, 2026, we began marketing all of our own natural gas production, causing our marketing revenues to increase by approximately $19.2 million to $26.2 million for the three months ended June 30, 2026, from $7.0 million for the three months ended June 30, 2025.
Other Revenues
Other revenues include the gain (loss) on sale of assets, which was a gain of $0.3 million for the three months ended June 30, 2026, compared to $0.1 million for the same period in 2025.
Lease Operating and Workover
The following table summarizes our components of lease operating expenses for the periods presented:
Three Months Ended June 30,
2026 2025 $ Change % Change
(in thousands, other than percentages and average costs) Amount Per Mcfe Amount Per Mcfe
Lease operating expenses $ 41,076 $ 0.46 $ 32,677 $ 0.44 $ 8,399 26 %
Workover expenses 3,406 0.04 1,499 0.02 1,907 *
Total lease operating and workover expense $ 44,482 $ 0.50 $ 34,176 $ 0.46 $ 10,306 30 %
Lease operating and workover expenses were $44.5 million, or $0.50 per Mcfe, for the three months ended June 30, 2026, which was an increase of approximately $10.3 million, or 30%, from $34.2 million, or $0.46 per Mcfe, for the three months ended June 30, 2025. The increase in lease operating and workover expenses during the three months ended June 30, 2026, compared to the same period in 2025, was primarily attributable to $10.2 million of lease operating and workover expenses associated with BKV Barnett II, which was acquired in connection with the Bedrock Acquisition in September 2025.
Marketing Expense
During the three months ended June 30, 2026, we began marketing all of our own natural gas production, causing our marketing expense to increase by approximately $18.2 million to $22.5 million, or $0.25 per Mcfe for the three months ended June 30, 2026, from $4.3 million, or $0.06 per Mcfe for the three months ended June 30, 2025.
Taxes Other Than Income
Taxes other than income were $11.6 million, or $0.13 per Mcfe, for the three months ended June 30, 2026, which was a decrease of approximately $1.8 million, or 14%, from $13.4 million, or $0.18 per Mcfe, for the three months ended June 30, 2025. The decrease was primarily driven by a $2.9 million production tax refund and a $0.3 million reduction in production taxes. These decreases were offset by a $1.0 million increase in production taxes attributable to BKV Barnett II. Ad valorem and property taxes also increased by $0.5 million, primarily due to a $0.9 million increase attributable to BKV Barnett II, partially offset by lower assessed values reflecting lower natural gas prices.
Gathering and Transportation
Gathering and transportation expenses were $68.1 million, or $0.76 per Mcfe, for the three months ended June 30, 2026, which was an increase of approximately $5.1 million, or 8%, from $63.0 million, or $0.85 per Mcfe, for the three months ended June 30, 2025. This increase was primarily driven by $11.6 million and $0.8 million of higher costs associated with natural gas and NGL production volumes, respectively and $0.4 million of NGL rate increases. These increases were offset by $8.1 million of natural gas rate decreases.
Depreciation, Depletion, Amortization, and Accretion
Depreciation, depletion, amortization, and accretion was $42.8 million, or $0.48 per Mcfe, for the three months ended June 30, 2026, which was an increase of approximately $5.2 million, or 14%, from $37.6 million, or $0.51 per Mcfe, for the three months ended June 30, 2025. The increase was primarily attributable to an additional $3.4 million of expense related to BKV Barnett II, which was acquired in connection with the Bedrock Acquisition in September 2025. The remainder of the increase was driven by higher production volumes, partially offset by a lower depletion rate resulting from an increase in our proved reserves.
General and Administrative
General and administrative expenses were $22.7 million, or $0.26 per Mcfe, for the three months ended June 30, 2026, which was an increase of approximately $8.0 million, from $14.8 million, or $0.20 per Mcfe, for the three months ended June 30, 2025. The increase was primarily attributable to higher information technology costs, employee and office, and consulting and contracting costs, which resulted in increased corporate allocations to the Upstream/Midstream segment.
Other Operating Expenses
Other operating expenses were $1.4 million, or $0.02 per Mcfe, for the three months ended June 30, 2026, which was a decrease of approximately $2.0 million, from $3.4 million, or $0.05 per Mcfe, for the three months ended June 30, 2025. The
decrease in other operating expenses during the three months ended June 30, 2026, compared to the same period in 2025, was attributable to a $2.1 million deficiency payment incurred in the prior year.
Power Segment
Comparison of the Three Months Ended June 30, 2026 and 2025:
Three Months Ended June 30,
(in thousands, other than percentages) 2026 2025 Change % Change
Temple I capacity factor 69.2 % 64.0 % 5.2 % 8 %
Temple II capacity factor 69.9 % 54.8 % 15.1 % 28 %
Total power generation (GWh)
2,222 1,913 309 16 %
Fuel consumption (MMBtu)
15,973 13,595 2,378 17 %
Average generation price (excluding derivatives)
$ 31.88 $ 29.13 $ 2.75 9 %
Average generation price (including derivatives)
$ 41.59 $ 45.10 $ (3.51) (8) %
Average natural gas cost $ 2.68 $ 2.93 $ (0.25) (9) %
Average spark spread $ 22.31 $ 24.27 $ (1.96) (8) %
Revenues and other operating income
Power revenues
$ 74,362 $ 61,924 $ 12,438 20 %
Derivative gains, net 47,971 74,818 (26,847) (36) %
Total revenues and other operating income 122,333 136,742 (14,409)
Operating expenses
Fuel commodity costs 42,832 39,852 2,980 7 %
Purchased power 29,502 29,494 8 - %
Marketing expense 685 547 138 25 %
Taxes other than income 4,303 4,638 (335) (7) %
Depreciation, depletion, amortization, and accretion 9,552 9,536 16 - %
Power operating and maintenance
17,185 18,252 (1,067) (6) %
General and administrative 7,625 4,267 3,358 79 %
Other operating expenses
4,891 434 4,457 *
Total operating expenses 116,575 107,020 9,555
Income from operations $ 5,758 $ 29,722 $ (23,964)
*Percentage not meaningful
Power Revenues
During the three months ended June 30, 2026, our Power revenues were $74.4 million, which was an increase of $12.4 million, or 20%, from $61.9 million for the three months ended June 30, 2025, which include merchant energy sales and revenue from our retail business. The increase was primarily due to the increase in merchant energy sales, which was attributable to higher power generation and capacity at the Temple Plants.
Derivative Gains, Net
For the three months ended June 30, 2026, our Power segment had net realized and unrealized gains on derivative contracts of $48.0 million, compared to net realized and unrealized gains of $74.8 million for the same period in 2025, representing a decrease of $26.8 million. The decrease was primarily attributable to a $39.5 million unfavorable change in net realized gains on our power derivatives driven by higher realized market power prices relative to contracted prices between periods, and a $41.8 million unfavorable change in unrealized results on our power derivatives and HRCOs, primarily due to changes in forward power prices and related valuation assumptions. These unfavorable changes were partially offset by a $34.1 million favorable change in
realized gains on HRCO settlements, a $19.5 million favorable change in unrealized results on our natural gas hedges, primarily due to decreases in the forward natural gas price curve during the current period compared with increases during the prior-year period and a $0.8 million favorable change in realized results on our natural gas hedges.
Fuel Commodity Costs
Fuel commodity costs were $42.8 million for the three months ended June 30, 2026, which was an increase of $3.0 million, or 7%, from $39.9 million for the three months ended June 30, 2025. The increase was due to higher fuel consumption compared to the same period in 2025.
Purchased Power
Purchased power costs for the retail business were $29.5 million for both the three months ended June 30, 2026 and 2025. Purchased power costs include power derivatives, which were in a net gain position of $0.2 million, compared to a net loss position of $3.3 million. As the retail power derivatives are in a long position, decreases in market prices relative to fixed contract prices result in gains. This was offset by an increase in purchased power due to slightly higher sales from our retail business.
Marketing Expense
During the three months ended June 30, 2026, we began marketing all of our own natural gas production, causing our marketing expense to increase by approximately $0.1 million to $0.7 million for the three months ended June 30, 2026, from $0.5 million for the three months ended June 30, 2025.
Taxes Other Than Income
Taxes other than income were $4.3 million for the three months ended June 30, 2026, which was a decrease of approximately $0.3 million, or 7%, from $4.6 million for the three months ended June 30, 2025. The decrease was driven by BKV-BPP Power's property tax reassessment.
Depreciation, Depletion, Amortization, and Accretion
Depreciation, depletion, amortization, and accretion was $9.6 million and $9.5 million for the three months ended June 30, 2026 and 2025, respectively, which was consistent between periods.
Power Operating and Maintenance
Power operating and maintenance expenses are costs incurred to run the Temple Plants. These expenses were $17.2 million for the three months ended June 30, 2026, which was a decrease of approximately $1.1 million, or 6%, from $18.3 million for the three months ended June 30, 2025. The decrease was primarily due to a $1.3 million decrease in planned maintenance period-over-period.
General and Administrative
General and administrative expenses were $7.6 million for the three months ended June 30, 2026, which was an increase of approximately $3.4 million, from $4.3 million for the three months ended June 30, 2025. The increase was primarily attributable to higher allocations of corporate general and administrative costs and higher administrative service expenses charged by BKV under the administrative services agreement due to an increase in contracted rates. These increases were partially offset by lower credit loss expense.
Other Operating Expenses
Other operating expenses were $4.9 million for the three months ended June 30, 2026, which was an increase of approximately $4.5 million, from $0.4 million for the three months ended June 30, 2025. The increase was due to $4.3 million in transaction costs related to the BKV-BPP Power Joint Venture Transaction.
Other Income Statement Line Items
Other Revenues
For the three months ended June 30, 2026, other revenues reflected a loss of $3.5 million, which included the impairment of our asset held for sale.
Section 45Q Tax Credits
Our Section 45Q tax credits increased by approximately $0.5 million, or 18%, to $3.0 million during the three months ended June 30, 2026, from $2.6 million during the three months ended June 30, 2025. Our Section 45Q tax credits related to CO2 waste sequestration activities under our Barnett Zero, Cotton Cove and Eagle Ford projects. The increase period-over-period was due to more CO2 waste sequestered in 2026 due to Cotton Cove and Eagle Ford injections beginning in the first half of 2026.
General and Administrative
General and administrative expenses were $11.8 million, for the three months ended June 30, 2026, which was an increase of approximately $0.3 million, from $11.4 million, for the three months ended June 30, 2025. The increase was primarily due to higher payroll, legal, and contract labor costs. The increase also reflected changes in the administrative service agreement allocated to the Power segment, with the corresponding intercompany amounts eliminated within Corporate and Other for segment reporting purposes. These increases were partially offset by lower employee and office, information technology, and consulting expenses.
Other Operating Expenses
Other operating expenses were $1.3 million for the three months ended June 30, 2026, which was a decrease of approximately $6.1 million, from $7.4 million for the three months ended June 30, 2025. The decrease was due to prior year's $3.1 million of costs related to the CCUS equity raise, $1.6 million in CCUS transaction fees and $1.1 million in a project write-off and a $0.4 million decrease in emissions monitoring period-over-period.
Other Income (Expense)
Interest expense. Interest expense was $24.9 million for the three months ended June 30, 2026, which was an increase of $8.5 million, from $16.4 million for the three months ended June 30, 2025. The increase in interest expense during the three months ended June 30, 2026 was primarily due to $9.3 million of interest on the 2030 Senior Notes, $0.9 million of higher debt amortization expense, $0.6 million of interest on the Promissory Note, and an increase of $0.3 million of interest on our letters of credit. These increases were partially offset by $1.4 million and $1.3 million of lower interest expense on the RBL Credit Agreement and the Temple Term Loan Facility, respectively, compared to the same period in 2025.
Interest expense, related party. Interest expense, related party was $4.0 million for the three months ended June 30, 2026, which was a decrease of $1.0 million, from $5.0 million for the three months ended June 30, 2025. The decrease was primarily due to a lower outstanding balance on the Temple I Loan Agreements period-over-period.
Interest income. Interest income was $2.2 million for the three months ended June 30, 2026, which was an increase of $1.5 million, from $0.7 million for the three months ended June 30, 2025. The increase was due to higher average cash balances during the three months ended June 30, 2026, compared to the same period in 2025.
Income tax benefit (expense). For the three months ended June 30, 2026, we had an income tax expense of $20.1 million, which was a change of $9.1 million, from a $29.2 million income tax expense for the three months ended June 30, 2025. The period-over-period change was primarily due to lower pretax earnings, which resulted in a lower income tax provision.
Business Segment Results of Operations
The following sections present our results of operations for our two reportable segments, which include Upstream/Midstream and Power. Management believes this information is useful to investors in understanding the Company's financial condition, results of operations, and trends and uncertainties. See Note 14 - Reportable Segments to our condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q.
Upstream/Midstream Segment
Comparison of the Six Months Ended June 30, 2026 and 2025:
Six Months Ended June 30,
(in thousands, other than percentages) 2026 2025 Change % Change
Production volume
Total production volumes (MMcfe) 172,273 142,295 29,978 21 %
Average daily production (MMcfe/d)
951.8 786.2 165.6 21 %
Average realized price (excluding derivatives) $ 2.96 $ 2.92 $ 0.04 1 %
Average realized price (including derivatives) $ 3.03 $ 2.86 $ 0.17 6 %
Revenues and other operating income
Natural gas revenues $ 396,252 $ 323,545 $ 72,707 22 %
NGL revenues 105,720 86,313 19,407 22 %
Oil revenues 7,631 5,997 1,634 27 %
Derivative gains (losses), net 52,808 (39,983) 92,791 *
Marketing revenues 45,985 19,425 26,560 *
Other 460 (1,165) 1,625 *
Total revenues and other operating income 608,856 394,132 214,724
Operating expenses
Lease operating and workover 89,557 69,231 20,326 29 %
Marketing expense 27,656 7,645 20,011 *
Taxes other than income 27,545 23,626 3,919 17 %
Gathering and transportation 135,897 118,819 17,078 14 %
Depreciation, depletion, amortization, and accretion 83,512 77,135 6,377 8 %
General and administrative 43,585 27,978 15,607 56 %
Other operating expenses
6,251 3,689 2,562 69 %
Total operating expenses 414,003 328,123 85,880
Income from operations $ 194,853 $ 66,009 $ 128,844
Per unit costs
Lease operating and workover $ 0.52 $ 0.49 $ 0.03 6 %
Marketing expense $ 0.16 $ 0.05 $ 0.11 *
Taxes other than income $ 0.16 $ 0.17 $ (0.01) (6) %
Gathering and transportation $ 0.79 $ 0.84 $ (0.05) (6) %
Depreciation, depletion, amortization, and accretion $ 0.48 $ 0.54 $ (0.06) (11) %
General and administrative $ 0.25 $ 0.20 $ 0.05 25 %
Other operating expenses
$ 0.04 $ 0.03 $ 0.01 33 %
Total $ 2.40 $ 2.32 $ 0.08
*Percentage not meaningful
Natural Gas Revenues
Our natural gas revenues increased by approximately $72.7 million, or 22%, to $396.3 million for the six months ended June 30, 2026, from $323.5 million for the six months ended June 30, 2025. The increase was due to higher production volumes during the six months ended June 30, 2026, which accounted for a $81.7 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price). The impact was offset by commodity price decreases, excluding the effect of derivative settlements, which provided a $9.0 million decrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes).
NGL Revenues
Our NGL revenues increased by approximately $19.4 million, or 22%, to $105.7 million for the six months ended June 30, 2026, from $86.3 million for the six months ended June 30, 2025. The increase was due to $14.8 million of commodity price increases, excluding the effect of derivative settlements (calculated as the change in the period-to-period average price times current period production volumes) and higher production volumes, which accounted for a $4.6 million increase (calculated as the change in period-to-period volumes times the prior period average price).
Oil Revenues
Our oil revenues increased by approximately $1.6 million, or 27%, to $7.6 million for the six months ended June 30, 2026, from $6.0 million for the six months ended June 30, 2025. The increase was primarily due to the impact of commodity price increases, excluding the effect of derivative settlements, which accounted for a $1.7 million increase in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes). This was slightly offset by lower production volumes during the six months ended June 30, 2026, which accounted for a $0.1 million decrease in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).
Derivative Gains, Net
For the six months ended June 30, 2026, our Upstream/Midstream segment had net realized and unrealized gains on derivative contracts of $52.8 million, compared to net realized and unrealized losses of $40.0 million for the same period in 2025. The favorable change during the six months ended June 30, 2026, was primarily attributable to our open derivative positions, which were in an unrealized gain position of $39.9 million, compared to an unrealized loss position of $31.1 million for the same period in 2025. The current period primarily reflects decreases in the forward curve of natural gas prices relative to December 31, 2025, whereas the prior year period reflected increases in future natural gas prices compared to December 31, 2024. In addition, we purchased put options of $16.2 million in the first quarter of 2025, limiting our 2026/2027 pricing downside. Also increasing our favorable change for the six months ended June 30, 2026 were realized gains of $12.9 million, compared to realized losses of $8.9 million for the six months ended June 30, 2025, which were due to slightly lower natural gas prices settled in the current period compared to the same period in the prior year.
Marketing Revenues
Our marketing revenues were derived under our marketing agreement with a third party pursuant to which we received a fixed percentage of all net income realized in the resale of our and other producers' hydrocarbons. Beginning in the second quarter of 2026, we began marketing all of our own natural gas production, causing our marketing revenues to increase by approximately $26.6 million to $46.0 million for the six months ended June 30, 2026, from $19.4 million for the six months ended June 30, 2025.
Other Revenues
Other revenues include the gain (loss) on sale of assets, which was a gain of $0.5 million for the six months ended June 30, 2026, compared to a loss of $1.2 million for the same period in 2025. The period-over-period increase was primarily due to a gain on sale of assets of $0.4 million during the six months ended June 30, 2026, whereas the prior year period included an impairment of $2.4 million on the Bridgeport building held for sale, offset by a gain on sale of assets of $1.2 million.
Lease Operating and Workover
The following table summarizes our components of lease operating expenses for the periods presented:
Six Months Ended June 30,
2026 2025 $ Change % Change
(in thousands, other than percentages and average costs) Amount Per Mcfe Amount Per Mcfe
Lease operating expenses $ 83,856 $ 0.48 $ 66,352 $ 0.47 $ 17,504 26 %
Workover expenses 5,701 0.04 2,879 0.02 2,822 98 %
Total lease operating and workover expense $ 89,557 $ 0.52 $ 69,231 $ 0.49 $ 20,326 29 %
Lease operating and workover expenses were $89.6 million, or $0.52 per Mcfe, for the six months ended June 30, 2026, which was an increase of approximately $20.3 million, or 29%, from $69.2 million, or $0.49 per Mcfe, for the six months ended June 30, 2025. The increase in lease operating and workover expenses during the six months ended June 30, 2026, compared to the same period in 2025, was primarily attributable to $19.9 million of lease operating and workover expenses associated with BKV Barnett II, which was acquired in connection with the Bedrock Acquisition in September 2025.
Marketing Expense
During the three months ended June 30, 2026, we began marketing all of our own natural gas production, causing our marketing expenses to increase by approximately $20.0 million to $27.7 million for the six months ended June 30, 2026, from $7.6 million for the six months ended June 30, 2025.
Taxes Other Than Income
Taxes other than income were $27.5 million, or $0.16 per Mcfe, for the six months ended June 30, 2026, which was an increase of approximately $3.9 million, or 17%, from $23.6 million, or $0.17 per Mcfe, for the six months ended June 30, 2025. The increase was primarily driven by a $2.9 million increase in production taxes attributable to BKV Barnett II and $1.7 million of higher production taxes in the Barnett. This was offset by a $2.9 million production tax refund. In addition, ad valorem and property taxes increased by $2.3 million, reflecting higher gas prices, of which $1.6 million was attributable to BKV Barnett II.
Gathering and Transportation
Gathering and transportation expenses were $135.9 million, or $0.79 per Mcfe, for the six months ended June 30, 2026, which was an increase of approximately $17.1 million, or 14%, from $118.8 million, or $0.84 per Mcfe, for the six months ended June 30, 2025. This increase was primarily driven by $12.2 million of higher costs associated with natural gas production and $6.7 million and $3.6 million of NGL and natural gas rate increases, respectively. These increases were offset by a $0.9 million decrease in NGL production.
Depreciation, Depletion, Amortization, and Accretion
Depreciation, depletion, amortization, and accretion was $83.5 million, or $0.49 per Mcfe, for the six months ended June 30, 2026, which was an increase of approximately $6.4 million, or 8%, from $77.1 million, or $0.54 per Mcfe, for the six months ended June 30, 2025. The increase was primarily due to an additional $6.9 million of expense related to BKV Barnett II, which was acquired in connection with the Bedrock Acquisition in September 2025. Slightly offsetting the increase was our lower depletion rate resulting from an increase in our proved reserves.
General and Administrative
General and administrative expenses were $43.6 million, or $0.25 per Mcfe, for the six months ended June 30, 2026, which was an increase of approximately $15.6 million, from $28.0 million, or $0.20 per Mcfe, for the six months ended June 30, 2025. The increase was primarily attributable to higher information technology costs, employee and office, and consulting and contracting costs, which resulted in increased corporate allocations to the Upstream/Midstream segment.
Other Operating Expenses
Other operating expenses were $6.3 million, or $0.04 per Mcfe, for the six months ended June 30, 2026, which was an increase of approximately $2.6 million, from $3.7 million, or $0.03 per Mcfe, for the six months ended June 30, 2025. The increase was due to a $5.3 million increase in integration and transaction costs due to the Bedrock Acquisition, a $1.0 million
reduction in emissions costs in 2025, and $0.8 million of project write-offs. This was offset by a $2.4 million reduction in legal and consulting fees and a $2.1 million deficiency payment incurred under our minimum volume commitments on our midstream pipeline recognized during the same period in 2025.
Power Segment
Comparison of the Six Months Ended June 30, 2026 and 2025:
Six Months Ended June 30,
(in thousands, other than percentages) 2026 2025 Change % Change
Temple I capacity factor 66.9 % 54.7 % 12.2 % 22 %
Temple II capacity factor 65.1 % 54.5 % 10.6 % 19 %
Total power generation (GWh)
4,203 3,500 703 20 %
Fuel consumption (MMBtu)
29,989 24,827 5,162 21 %
Average generation price (excluding derivatives)
$ 39.41 $ 32.92 $ 6.49 20 %
Average generation price (including derivatives)
$ 46.04 $ 48.63 $ (2.59) (5) %
Average natural gas cost $ 3.33 $ 3.47 $ (0.14) (4) %
Average spark spread $ 22.26 $ 24.00 $ (1.74) (7) %
Revenues and other operating income
Power revenues
$ 143,352 $ 105,788 $ 37,564 36 %
Derivative gains, net 143,556 128,626 14,930 12 %
Total revenues and other operating income 286,908 234,414 52,494
Operating expenses
Fuel commodity costs 99,953 86,215 13,738 16 %
Purchased power 56,857 48,161 8,696 18 %
Marketing expense 1,563 1,143 420 37 %
Taxes other than income 8,536 9,206 (670) (7) %
Depreciation, depletion, amortization, and accretion 21,356 19,163 2,193 11 %
Power operating and maintenance
36,864 38,465 (1,601) (4) %
General and administrative 13,980 10,169 3,811 37 %
Other operating expenses
9,047 824 8,223 *
Total operating expenses 248,156 213,346 34,810
Income from operations 38,752 21,068 17,684
*Percentage not meaningful
Power Revenues
During the six months ended June 30, 2026, our Power revenues were $143.4 million compared to $105.8 million during the six months ended June 30, 2025, which include merchant energy sales and revenue from our retail business. The increase was primarily due to the increase in merchant energy sales, which was attributable to higher power prices, power generation, and capacity at the Temple Plants.
Derivative Gains, Net
For the six months ended June 30, 2026, our Power segment had net realized and unrealized gains on derivative contracts of $143.6 million, compared to net realized and unrealized gains of $128.6 million for the same period in 2025. The increase was primarily attributable to our open derivative positions, which were in an unrealized gain position of $22.8 million as of June 30, 2026, compared to an unrealized loss position of $4.5 million for the same period in 2025. This change is largely due to decreases in power prices relative to hedged prices and the value of optionality. We also had an increase in realized gains of $69.3 million on our HRCOs during the six months ended June 30, 2026, which was primarily due to higher contracted capacity with four
contracts totaling 600 MW in 2026, compared to two contracts totaling 200 MW in the prior year period. These increases were offset by a $79.3 million decrease in net realized gains on our power derivatives driven by higher realized market power prices relative to contracted prices.
Fuel Commodity Costs
Fuel commodity costs were $100.0 million for the six months ended June 30, 2026, which was an increase of $13.7 million, or 16%, from $86.2 million for the six months ended June 30, 2025. The increase was due to higher fuel consumption compared to the same period in 2025.
Purchased Power
Purchased power costs for the retail business were $56.9 million for the six months ended June 30, 2026, which was an increase of $8.7 million, or 18%, from $48.2 million for the six months ended June 30, 2025. The increase was primarily driven by our net realized and unrealized loss position on the power derivatives, which was $13.0 million compared to a net realized and unrealized loss of $4.4 million for the same period in 2025. As the retail power derivatives are in a long position, increases in market prices reduced the spread between fixed contract prices and settlement prices, which resulted in higher realized losses.
Taxes Other Than Income
Taxes other than income were $8.5 million for the six months ended June 30, 2026, which was a decrease of approximately $0.7 million, or 7%, from $9.2 million for the six months ended June 30, 2025. The decrease was driven by BKV-BPP Power's property tax reassessment.
Depreciation, Depletion, Amortization, and Accretion
Depreciation, depletion, amortization, and accretion was $21.4 million for the six months ended June 30, 2026, which was an increase of approximately $2.2 million, or 11%, from $19.2 million for the six months ended June 30, 2025. The increase was primarily due to the true-up of depreciation on equipment during the six months ended June 30, 2026.
Power Operating and Maintenance
Power operating and maintenance expenses are costs incurred to run the Temple Plants and were $36.9 million for the six months ended June 30, 2026, which was a decrease of approximately $1.6 million, or 4%, from $38.5 million for the six months ended June 30, 2025. The decrease was primarily due to employees moving from the Power segment to Corporate and Other.
General and Administrative
General and administrative expenses were $14.0 million for the six months ended June 30, 2026, which was an increase of approximately $3.8 million, from $10.2 million for the six months ended June 30, 2025. The increase was primarily attributable to higher allocations of corporate general and administrative costs and $2.6 million of higher administrative service expenses charged by BKV under the administrative services agreement due to an increase in contracted rates. These increases were partially offset by $3.0 million of lower credit loss expense with BKV-BPP Retail customers as the prior year period included significant write-offs related to 2024 and 2025 customer balances.
Other Operating Expenses
Other operating expenses were $9.0 million for the six months ended June 30, 2026, which was an increase of approximately $8.2 million, from $0.8 million for the six months ended June 30, 2025. The increase was due to $8.0 million in transaction costs related to the BKV-BPP Power Joint Venture Transaction.
Other Income Statement Line Items
Other Revenues
For the six months ended June 30, 2026, other revenues was a loss of $3.5 million, which included the impairment of our asset held for sale.
General and Administrative
General and administrative expenses were $24.7 million, for the six months ended June 30, 2026, which was an increase of approximately $4.0 million, from $20.6 million, for the six months ended June 30, 2025. The increase was primarily due to higher payroll, legal, and contract labor costs. The increase also reflected changes in the administrative service agreement allocated to the
Power segment, with the corresponding intercompany amounts eliminated within Corporate and Other for segment reporting purposes. These increases were partially offset by lower employee and office, information technology, and consulting expenses.
Other Operating Expenses
Other operating expenses were $2.8 million for the six months ended June 30, 2026, which was a decrease of approximately $7.4 million, from $10.2 million for the six months ended June 30, 2025. The decrease was due to prior year's $3.1 million of costs related to the CCUS equity raise, $2.3 million in CCUS transaction fees, and $1.5 million in a project write-off and a $0.4 million decrease in emissions monitoring period-over-period.
Section 45Q Tax Credits
Our Section 45Q tax credits increased by approximately $0.2 million, or 4%, to $6.1 million during the six months ended June 30, 2026, from $5.9 million during the six months ended June 30, 2025. Our Section 45Q tax credits related to CO2 waste sequestration activities under our Barnett Zero, Cotton Cove and Eagle Ford projects. The increase was due to more CO2 waste sequestered in 2026, attributable to Cotton Cove and Eagle Ford injections beginning in the first half of 2026, offset by decreased injections at Barnett Zero due to routine fluctuations in activity levels that occur as part of our normal operations.
Other Income (Expense)
Interest expense. Interest expense was $47.7 million for the six months ended June 30, 2026, which was an increase of $15.3 million, from $32.4 million for the six months ended June 30, 2025. The increase in interest expense during the six months ended June 30, 2026 was primarily due to $18.6 million of interest on the 2030 Senior Notes, $1.5 million of higher debt amortization expense, $1.2 million of interest on the Promissory Note, and an increase of $0.7 million of interest on our letters of credit. These increases were partially offset by $4.2 million and $2.6 million of lower interest expense on the RBL Credit Agreement and the Temple Term Loan Facility, respectively, compared to the same period in 2025.
Interest expense, related party. Interest expense, related party was $8.2 million for the six months ended June 30, 2026, which was a decrease of $1.9 million, from $10.1 million for the six months ended June 30, 2025. The decrease was primarily due to a lower outstanding balance on the Temple I Loan Agreements period-over-period.
Interest income. Interest income was $3.7 million for the six months ended June 30, 2026, which was an increase of $2.2 million, from $1.5 million for the six months ended June 30, 2025. The increase was due to higher average cash balances during the six months ended June 30, 2026, compared to the same period in 2025.
Income tax benefit (expense). For the six months ended June 30, 2026, we had an income tax expense of $31.6 million, which was a change of $33.0 million, from a $1.4 million income tax benefit for the six months ended June 30, 2025. The change was primarily due to an increase in pretax earnings period-over period, and the prior year's deferred tax balance remeasurement for Pennsylvania.
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 six months ended June 30, 2026 included deposits for modular power generation equipment and associated reservation fees, development of our natural gas properties, land acquisitions, and funding the BKV-BPP Power Joint Venture transaction. Our primary use of cash during the six months ended June 30, 2025 included funding the development of our natural gas properties.
Operating and Development Capital Expenditures
During the six months ended June 30, 2026 and 2025, cash paid for capital expenditures was $193.4 million and $124.1 million, respectively. Our current estimated budget for total accrued capital expenditures in 2026 is approximately $690 million to $875 million on a Company-wide basis. To help fund these capital expenditures, we expect to receive approximately $120 million to $150 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 2026 net capital expenditure range to $570 million to $725 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. In addition, the development of our power business is capital intensive, requiring ongoing investments in land, modular equipment, and turbine generators. 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.
Strategic Power Growth Commitments
On January 14, 2026, the Company entered into a manufacturing reservation agreement related to a planned power generation project. Under the agreement, the Company is 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 MW in total generation capacity. During the six months ended June 30, 2026, the Company paid $60.0 million of the reservation fees. Amounts paid are generally non-refundable and will be credited against the purchase price if a definitive supply agreement is executed.
On March 25, 2026 and May 15, 2026, the Company entered into two separate equipment supply contracts related to a planned power generation project. Under the agreements, the Company is committed to pay up to an aggregate of $248.2 million in purchase payments, scheduled in phases from 2026 through 2027, to secure the manufacture of modular power generation equipment. During the six months ended June 30, 2026, the Company paid $96.8 million of the purchase payments, and on July 17, 2026, made an additional purchase payment on each contract, each in the amount of $24.8 million. If the Company terminates the contracts before manufacturing of the equipment begins, the Company would be required to pay 60% of the contract price, and if the Company terminates the contracts after manufacturing of the equipment begins, the Company would be required to pay 100% of the contract price.
Capital Resources
Historically, our primary sources of capital and liquidity have consisted of internally generated cash flows from operations, together with loans, capital contributions from our majority stockholder, BNAC, and issuances of equity or debt. We also enter into financial instruments to reduce the impact of commodity and power 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, proceeds from the issuance of the 2026 Equity Offering, contributions from our joint venture partners, and our commodity and power hedges in place will provide sufficient liquidity to fund our operations and our capital expenditures for the remainder of 2026, excluding our CCUS business. If capital expenditures were to exceed such capital sources during the remainder of 2026, we expect to fund such excess capital expenditures through the sale of oil and natural gas producing assets, leasehold interests or mineral interests, and potential issuances of equity or debt, none of which may be available on satisfactory terms, or at all. 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 six months ended June 30, 2026 and 2025 (in thousands):
Six Months Ended June 30,
2026 2025
Net cash provided by operating activities $ 181,731 $ 105,748
Net cash used in investing activities (469,881) (130,087)
Net cash provided by financing activities 192,136 32,429
Net increase (decrease) in cash, cash equivalents, and restricted cash $ (96,014) $ 8,090
Cash flows provided by operating activities. Net cash provided by operating activities was $181.7 million for the six months ended June 30, 2026, compared to $105.7 million for the six months ended June 30, 2025. Net cash provided by operating activities increased during the six months ended June 30, 2026, compared to the six months ended June 30, 2025 due to a $64.6 million increase in income from operations (excluding noncash items), resulting from higher natural gas and production volumes and higher power prices, power generation, and capacity at the Temple Plants. Cash from operations also increased period-over-period due to the absence of $20.0 million and $16.2 million of cash paid in 2025 for the settlement of contingent liabilities and the purchase of put options, respectively, and an increase of $2.2 million in interest income. These increases were partially offset by a $14.3 million unfavorable change in working capital and a $12.5 million increase in cash paid for interest period-over-period.
Operating cash flow fluctuations are substantially driven by realized commodity prices, production volumes, power prices, power generated, and operating expenses. Prices for natural gas, NGLs, and power 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 used in investing activities. Net cash used in investing activities was $469.9 million for the six months ended June 30, 2026, compared to $130.1 million for the six months ended June 30, 2025. The increase was driven by $151.0 million of cash deposits on equipment supply and manufacturing reservations and $118.7 million of cash paid for land. The increase was also attributable to higher capital expenditures, including a $30.3 million increase in the Upstream/Midstream segment, a $21.9 million increase in the Power segment, and a $17.0 million increase in Corporate and Other, which includes a $22.0 million increase in CCUS capital expenditures. In addition, we had a $0.8 million decrease in proceeds from the sales of assets period-over-period.
The following table presents our capital expenditures (excluding leasehold costs and acquisitions) on an accrual basis for the six months ended June 30, 2026 and 2025 and reconciles to cash flows used for capital expenditures in the condensed consolidated statements of cash flows.
Six Months Ended June 30,
2026 2025
Total use of cash and cash equivalents for capital expenditures
$ (193,365) $ (124,102)
Decrease (increase) in accrued capital expenditures 2,373 (12,965)
Capital expenditures (accrued)
$ (190,992) $ (137,067)
Cash flows provided by financing activities. Net cash provided by financing activities was $192.1 million for the six months ended June 30, 2026, which consisted of $185.5 million of net proceeds from the issuance of common stock, $100.0 million in net borrowings on the RBL Credit Agreement, proceeds of $46.0 million from the Promissory Note, $13.4 million of cash contributions from noncontrolling interest, and $0.3 million of cash received for common stock issued pursuant to the ESPP. These inflows were offset by $115.1 million of cash paid for a portion of the consideration for the BKV-BPP Power Joint Venture Transaction, $19.9 million of payments on the Temple Term Loan Facility, $15.0 million of payments on the Temple I Loan Agreements, $2.1 million of payments for taxes related to net share settlement of restricted stock units, and $0.9 million of payments on debt issuance costs. For the six months ended June 30, 2025, net cash provided by financing activities was $32.4 million, primarily consisting of $35.0 million of net borrowings under the RBL Credit Agreement and $4.4 million of cash contributions from noncontrolling interest, offset by a $5.0 million payment on the Temple Term Loan Facility, $1.2 million of payments for taxes related to net share settlement of restricted stock units, and $0.7 million of payments on debt issuance costs.
Working Capital
As of June 30, 2026, we had cash and cash equivalents of $152.2 million and restricted cash of $16.1 million, compared to $248.4 million of cash and cash equivalents and restricted cash of $15.8 million as of December 31, 2025. Our net working capital surplus was $59.1 million as of June 30, 2026, compared to a net working capital deficit of $53.2 million as of December 31, 2025.
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, power prices, power generation, 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 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 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 $14.5 million, which are amortized to interest expense on the condensed consolidated statements of income 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. These guarantees are full, unconditional, joint, and several among the guarantors of the 2030 Senior Notes, 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 May 20, 2026, BKV Corporation, BKV Upstream Midstream, the lenders and the administrative agent amended the RBL Credit Agreement to, among other things, redetermine and reaffirm the borrowing base at $1.0 billion in connection with the scheduled semiannual borrowing base redetermination. As of June 30, 2026, the borrowing base and elected commitment remained unchanged at $1.0 billion, and $800.0 million, respectively.
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. During the three and six months ended June 30, 2026, BKV Upstream Midstream recognized $0.8 million and $1.7 million, respectively, of commitment fees, which are included in interest expense on the condensed consolidated statements of income. During the three and six months ended June 30, 2025, BKV Upstream Midstream recognized $0.5 million, and $1.0 million, respectively, of commitment fees.
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 BKV Upstream Midstream 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). As of June 30, 2026, BKV Upstream Midstream was in compliance with such covenants 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.
Financing costs related to the RBL Credit Agreement are deferred and capitalized as debt issuance costs and are included within other assets on the condensed consolidated balance sheets. As of June 30, 2026 and December 31, 2025, $5.6 million and $6.9 million, respectively, of unamortized debt issuance costs remained outstanding.
As of August 6, 2026, $120.0 million of borrowings and $15.5 million of letters of credit were outstanding under the RBL Credit Agreement, leaving $664.5 million of available capacity thereunder for future borrowings and letters of credit.
Promissory Note
On March 3, 2026, in accordance with the terms of a real estate option agreement entered into on February 27, 2026, by and between a wholly-owned subsidiary of BKV Corporation, as seller, and an unaffiliated third party, as buyer, BKV Corporation, as borrower, received $46.0 million, representing an advance of a portion of the purchase price set forth in the real estate option agreement (the "Advance"). The Advance is evidenced by a promissory note (the "Promissory Note") and is secured by a first-priority security interest in the real property that is the subject of the real estate option agreement. For more information regarding the Advance and Promissory Note, see Note 3 - Debt.
BKV-BPP Power Loan Agreements and Credit Facilities
Temple I Loan Agreements
On October 14, 2021, BKV-BPP Power entered into a Loan Agreement (the "$141 Million Banpu Loan Agreement") with BNAC, which allowed for a single drawdown in the amount of $141.0 million. On November 1, 2021, BKV-BPP Power borrowed $141.0 million under the $141 Million Banpu Loan Agreement for the purpose of acquiring Temple I and working capital.
On October 15, 2021, BKV-BPP Power entered into a Loan Agreement (the "$141 Million BPPUS Loan Agreement" and, together with the $141 Million Banpu Loan Agreement, the "Temple I Loan Agreements") with BPPUS, which allowed for a single drawdown in the amount of $141.0 million. On November 21, 2021, BKV-BPP Power borrowed $141.0 million under the $141 Million BPPUS Loan Agreement (and in addition to the $141.0 million borrowed under the $141 Million Banpu Loan Agreement) for the purpose of acquiring Temple I and working capital.
BKV-BPP Power's payment obligations under the Temple I Loan Agreements are senior unsecured indebtedness. The Temple I Loan Agreements bear interest at 6-month SOFR plus 5.25% per annum. Interest on the loans is payable on a semi-annual basis, and the loans will mature on November 1, 2026. BKV-BPP Power is permitted to prepay the loans at any time, with no prepayment premium. The Temple I Loan Agreements include covenants that, among other things, prohibit BKV-BPP Power from merging, incurring liens or incurring any additional indebtedness or guarantees. The Temple I Loan Agreements include financial covenants that require BKV-BPP Power to maintain a minimum net worth (as defined in the Temple I Loan Agreements, but generally meaning total assets minus total liabilities). In the $141 Million Banpu Loan Agreement, the minimum net worth requirement is $120.0 million and in the $141 Million BPPUS Loan Agreement, the minimum net worth requirement is $40.0 million. Under the Temple I Loan Agreements, BNAC and BPPUS have no recourse to BKV Corporation with respect to any amounts owed to them thereunder and BKV Corporation is not liable in any manner (and is not required to provide security) for any obligations owed to BNAC or BPPUS thereunder. As of June 30, 2026 and December 31, 2025, the outstanding principal balance of the Temple I Loan Agreements for each affiliate was $88.0 million and $95.5 million, respectively.
Temple Credit Facilities
On July 10, 2023, Temple Generation Intermediate Holdings II, LLC ("Temple Intermediate II"), an indirect subsidiary of BKV-BPP Power, as borrower, Temple Generation I, LLC ("Temple Generation I"), Temple Generation II, LLC ("Temple Generation II"), each of Temple Generation I and Temple Generation II being a subsidiary of Temple Intermediate II, and Temple Generation SF LLC ("Temple Generation SF"), a joint subsidiary of Temple Generation I and Temple Generation II, each as subsidiary guarantors, entered into a credit agreement (the "Beal Credit Agreement") with Beal Bank USA and the other lenders from time to time party thereto that provides the following credit facilities (collectively, the "Temple Credit Facilities"): (i) a senior secured term loan facility with an aggregate principal amount of $500.0 million (the "Temple Term Loan Facility"), which was fully drawn in an amount equal to $500.0 million on the closing date, and (ii) a senior secured revolving credit facility in the aggregate principal amount not to exceed $60.0 million (the "Temple Revolving Facility"), which was fully drawn in an amount equal to $60.0 million on the closing date. The interest is payable annually for the Temple Credit Facilities at a rate equal to SOFR plus an interest rate margin of 4.60%.
The Temple Term Loan Facility requires a quarterly repayment at a minimum of $2.5 million per quarter, beginning on September 30, 2023. The final aggregate principal installment for the Temple Term Loan Facility is due and payable on July 10, 2028 (subject to extension by up to two additional one-year periods), and the Temple Revolving Facility terminates five business days prior to the Temple Term Loan Facility maturity date. On the closing date, Temple Intermediate II applied the proceeds of the Temple Term Loan Facility to fund a portion of the Temple II acquisition and applied the proceeds of the Temple Revolving Facility for general corporate purposes, including working capital and operating expenses. Any prepayment of the Temple Term Loan Facility prior to the third anniversary of the closing date thereof is subject to a prepayment penalty. Amounts repaid by Temple Intermediate II with respect to the Temple Term Loan Facility may not be reborrowed. Amounts repaid by Temple Intermediate II with respect to the Temple Revolving Facility may be reborrowed upon satisfaction of customary conditions.
The obligations under the Temple Credit Facilities are secured by (i) all of the assets of Temple Intermediate II, Temple Generation I, Temple Generation II, and Temple Generation SF, including the Temple Plants and all other personal property and real property of such entities and (ii) 100.0% of the equity interests in each of Temple Generation I, Temple Generation II, Temple Generation SF, and Temple Intermediate II. This collateral will remain pledged to Beal Bank until all secured obligations under the Temple Credit Facilities have been satisfied in full. Upon the occurrence and continuation of an event of default under either of the Temple Credit Facilities, Beal Bank has customary secured creditor remedies, including the right to foreclose upon the pledged collateral.
As of June 30, 2026 and December 31, 2025, the weighted average effective interest rate on the outstanding balances under the RBL Credit Agreement, the Temple I Loan Agreements, and the Temple Credit Facilities was 8.13% and 8.86%, respectively.
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 six months ended June 30, 2026 and 2025, 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, 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 board of 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. During the six months ended June 30, 2026, BKV dCarbon Ventures and BPPUS made no contributions to BKV-BPP Cotton Cove.
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. For additional information, see Note 2 - Acquisition.
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 June 30, 2026, our material off-balance sheet arrangements and transactions included transportation commitments of $224.8 million and letters of credit of $15.5 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.
Other than the items described in this Quarterly Report on Form 10-Q, there have been no material changes to our critical accounting policies and estimates from those disclosed in our 2025 Annual Report on Form 10-K. Refer to Note 1 - Business and Basis of Presentation.
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 (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 August 06, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on August 06, 2026 at 18:26 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]