BKV Corporation

11/05/2026 | Press release | Distributed by Public on 11/05/2026 14:58

Quarterly Report for Quarter Ending September 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, as amended by Amendment No. 1 on Form 10-K/A filed on August 19, 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
•Barnett Acquisition. On September 15, 2026, we completed the Barnett Acquisition. Upon closing the Barnett Acquisition, we acquired approximately 117,000 net acres, 65 MMcfe/d of production, nearly 0.35 Tcfe of PDP reserves (using NYMEX strip pricing), and 1,000 gross operated wells. The acquisition also includes operated midstream infrastructure and an operated carbon capture and sequestration project. For additional information, see Note 2 - Acquisitions.
•2031 Convertible Senior Notes. On September 14, 2026, we issued in a private placement $575.0 million of our 2031 Convertible Senior Notes due October 15, 2031. Net proceeds from the offering of the 2031 Convertible Senior Notes were $559.2 million, after deducting the initial purchasers' discounts and commissions and offering expenses paid by us. We used approximately $64.7 million of the net proceeds to fund the cost of privately negotiated capped call transactions and approximately $35.0 million of the net proceeds to fund the cost of concurrent share repurchases. See Note 9 - Stockholders' Equity for further discussion on the capped call transactions and concurrent share repurchases. The remaining net proceeds were used for general corporate purposes, including repayment of outstanding indebtedness and capital expenditures. For additional information regarding the 2031 Convertible Senior Notes, see Note 3 - Debt and under "Liquidity and Capital Resources - 2031 Convertible Senior Notes."
Operational and Financial Highlights
Below are some highlights of our operating and financial results for the three and nine months ended September 30, 2026:
•Production of natural gas, NGLs, and oil was 90.3 Bcfe, or 981.2 MMcfe/d and 262.5 Bcfe, or 961.7 MMcfe/d, respectively.
•Average realized product prices, excluding the impact of settled derivatives, were $2.63 per Mcfe and $2.85 per Mcfe, respectively.
•Power generation of 2,317 GWh and 6,520 GWh, respectively, from the Temple Plants and capacity factors of 71.7% and 67.9%, respectively.
•Upstream/Midstream production revenues were $237.7 million and $747.3 million, respectively, and Power revenues were $87.4 million and $230.8 million respectively.
•Net income attributable to BKV was $29.4 million and $149.3 million, respectively.
•Net cash provided by operating activities for the nine months ended September 30, 2026 was $346.2 million.
•Accrued capital expenditures for the nine months ended September 30, 2026 were $268.8 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 fund capital expenditures to increase production from our existing reserves and add reserves through drilling is dependent on our capital resources and may be constrained by a number of factors, including our ability to access capital in a cost-effective manner and 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 and power data for the periods presented:
Three Months Ended September 30, Nine Months Ended September 30,
2026 2025 2026 2025
Production Data
Natural gas (MMcf) 72,839 60,325 213,703 172,776
NGLs (MBbls) 2,861 2,621 8,001 7,498
Oil (MBbls) 44 29 139 126
Total volumes (MMcfe) 90,269 76,225 262,543 218,520
Average daily total volumes (MMcfe/d) 981.2 828.5 961.7 800.4
Power Data
Power generation (GWh) 2,317 2,246 6,520 5,746
Fuel consumption (thousands of MMBtu) 16,812 16,025 46,800 40,852
Impact of Acquisitions 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 and 2026, 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.
In September 2026, we completed the Barnett Acquisition, which expanded our operated and non-operated asset base in the Barnett and is expected to provide operational synergies with our existing Barnett assets. Because the acquisition closed on September 15, 2026, its impact on our results of operations for the nine months ended September 30, 2026 was limited. However, the acquisition increased our assets and borrowings under the RBL Credit Agreement as of September 30, 2026, and its results will affect comparability in future periods.
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. Prices received for NGLs are generally based on published OPIS pricing indices for individual NGL components at Mont Belvieu, including ethane, propane, isobutane, normal butane, and natural gasoline, and are affected by product mix, regional market conditions, transportation costs, 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 September 30,
Nine Months Ended
September 30,
2026 2025 2026 2025
Average prices:
Natural gas ($/Mcf)
Average NYMEX Henry Hub price $ 2.95 $ 3.07 $ 3.63 $ 3.39
Average natural gas realized price (excluding derivatives) $ 2.31 $ 2.50 $ 2.64 $ 2.75
Average natural gas realized price (including derivatives) $ 2.90 $ 2.81 $ 2.94 $ 2.83
Differential $ (0.64) $ (0.57) $ (0.99) $ (0.64)
NGLs ($/Bbl)
Average NGL realized price (excluding derivatives) $ 23.05 $ 15.17 $ 21.46 $ 16.82
Average NGL realized price (including derivatives) $ 20.13 $ 15.64 $ 19.36 $ 16.29
Oil ($/Bbl)
Average oil realized price $ 84.95 $ 59.62 $ 81.79 $ 61.32
High and low daily spot prices
Natural gas ($/Mcf)
High NYMEX Henry Hub $ 3.34 $ 3.52 $ 30.72 $ 9.86
Low NYMEX Henry Hub $ 2.56 $ 2.70 $ 2.54 $ 2.65
Oil ($/Bbl)
High NYMEX WTI $ 107.02 $ 71.09 $ 114.58 $ 80.73
Low NYMEX WTI $ 69.60 $ 62.22 $ 56.01 $ 58.50
Power
Average power price ($/MWh) (excluding derivatives) $ 34.74 $ 45.41 $ 37.75 $ 37.80
Average power price ($/MWh) (including derivatives) $ 40.37 $ 43.89 $ 44.03 $ 46.77
Average natural gas cost ($/Mcf) $ 2.64 $ 2.88 $ 3.09 $ 3.24
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 September 30, 2026 and 2025:
Three Months Ended September 30,
(in thousands, other than percentages) 2026 2025 Change % Change
Production volume
Total production volumes (MMcfe) 90,269 76,225 14,044 18 %
Average daily production (MMcfe/d)
981.2 828.5 152.7 18 %
Average realized price (excluding derivatives) $ 2.63 $ 2.52 $ 0.11 4 %
Average realized price (including derivatives) $ 3.02 $ 2.78 $ 0.24 9 %
Revenues and other operating income
Natural gas revenues $ 168,039 $ 150,933 $ 17,106 11 %
NGL revenues 65,945 39,773 26,172 66 %
Oil revenues 3,738 1,729 2,009 *
Derivative gains, net 1,510 74,890 (73,380) (98) %
Marketing revenues 65,117 6,880 58,237 *
Other (4) (539) 535 (99) %
Total revenues and other operating income 304,345 273,666 30,679
Operating expenses
Lease operating and workover 46,568 36,920 9,648 26 %
Marketing expense 60,072 3,926 56,146 *
Taxes other than income 11,032 11,643 (611) (5) %
Gathering and transportation 70,501 61,822 8,679 14 %
Depreciation, depletion, amortization, and accretion 44,604 37,344 7,260 19 %
General and administrative 24,461 17,510 6,951 40 %
Other operating expenses
6,617 5,310 1,307 25 %
Total operating expenses 263,855 174,475 89,380
Income from operations $ 40,490 $ 99,191 $ (58,701)
Per unit costs
Lease operating and workover $ 0.52 $ 0.48 $ 0.04 8 %
Marketing expense $ 0.67 $ 0.05 $ 0.62 *
Taxes other than income $ 0.12 $ 0.15 $ (0.03) (20) %
Gathering and transportation $ 0.78 $ 0.81 $ (0.03) (4) %
Depreciation, depletion, amortization, and accretion $ 0.49 $ 0.49 $ - - %
General and administrative $ 0.27 $ 0.23 $ 0.04 17 %
Other operating expenses
$ 0.07 $ 0.07 $ - - %
Total $ 2.92 $ 2.28 $ 0.64
*Percentage not meaningful
Natural Gas Revenues
Our natural gas revenues increased by $17.1 million, or 11%, to $168.0 million for the three months ended September 30, 2026, from $150.9 million for the three months ended September 30, 2025. The increase was primarily due to higher production volumes during the three months ended September 30, 2026, which accounted for a $31.3 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 $14.2 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 $26.2 million, or 66%, to $65.9 million for the three months ended September 30, 2026, from $39.8 million for the three months ended September 30, 2025. The increase was primarily due to commodity price increases, excluding the effect of derivative settlements, which accounted for a $22.5 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 September 30, 2026, which accounted for a $3.6 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).
Oil Revenues
Our oil revenues increased by $2.0 million, to $3.7 million for the three months ended September 30, 2026, from $1.7 million for the three months ended September 30, 2025. The increase was due to the impact of commodity price increases, excluding the effect of derivative settlements, which accounted for a $1.1 million increase in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes). The increase was also due to higher production volumes during the three months ended September 30, 2026, which accounted for a $0.9 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 September 30, 2026, our Upstream/Midstream segment had net realized and unrealized gains on derivative contracts of $1.5 million compared to net realized and unrealized gains on derivative contracts of $74.9 million for the same period in 2025. The decrease in gains for the three months ended September 30, 2026, was primarily attributable to our open derivative positions, which were in an unrealized loss position of $33.4 million, compared to an unrealized gain position of $55.2 million for the same period in 2025. The current period primarily reflects increases 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 June 30, 2025. Offsetting the loss position in our derivative gains, net was our realized gains of $34.9 million, compared to $19.7 million for the three months ended September 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. Starting in the second quarter of 2026, we began marketing all of our own natural gas production, causing our marketing revenues to increase by approximately $58.2 million to $65.1 million for the three months ended September 30, 2026, from $6.9 million for the three months ended September 30, 2025.
Other Revenues
Other revenues include the gain (loss) on sale of assets, which was a loss of $0.5 million for the three months ended September 30, 2025.
Lease Operating and Workover
The following table summarizes our components of lease operating expenses for the periods presented:
Three Months Ended September 30,
2026 2025 $ Change % Change
(in thousands, other than percentages and average costs) Amount Per Mcfe Amount Per Mcfe
Lease operating expenses $ 44,024 $ 0.49 $ 34,760 $ 0.46 $ 9,264 27 %
Workover expenses 2,544 0.03 2,160 0.03 384 18 %
Total lease operating and workover expense $ 46,568 $ 0.52 $ 36,920 $ 0.49 $ 9,648 26 %
Lease operating and workover expenses were $46.6 million, or $0.52 per Mcfe, for the three months ended September 30, 2026, which was an increase of $9.6 million, or 26%, from $36.9 million, or $0.49 per Mcfe, for the three months ended September 30, 2025. The increase in lease operating and workover expenses during the three months ended September 30, 2026, compared to the same period in 2025, 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, and $1.3 million associated with the Barnett Acquisition in September 2026. The increase was partially offset by lower lease operating costs period-over-period.
Marketing Expense
Starting in the second quarter of 2026, we began marketing all of our own natural gas production, causing our marketing expense to increase by approximately $56.1 million to $60.1 million, or $0.67 per Mcfe, for the three months ended September 30, 2026, from $3.9 million, or $0.05 per Mcfe, for the three months ended September 30, 2025.
Taxes Other Than Income
Taxes other than income were $11.0 million, or $0.12 per Mcfe, for the three months ended September 30, 2026, which was a decrease of $0.6 million, or 5%, from $11.6 million, or $0.15 per Mcfe, for the three months ended September 30, 2025. The decrease was primarily driven by a $2.8 million decrease in Texas ad valorem and property taxes due to the increase in the business and personal property tax exemption under Texas House Bill 9. The decrease was also attributable to a $0.3 million decrease in ad valorem and property tax in NEPA. These decreases were offset by a $1.9 million increase in production taxes and ad valorem and property taxes attributable to BKV Barnett II.
Gathering and Transportation
Gathering and transportation expenses were $70.5 million, or $0.78 per Mcfe, for the three months ended September 30, 2026, which was an increase of $8.7 million, or 14%, from $61.8 million, or $0.81 per Mcfe, for the three months ended September 30, 2025. This increase was primarily driven by $8.1 million and $1.6 million of higher costs associated with natural gas and NGL production volumes, respectively, and $1.8 million of NGL rate increases. These increases were offset by $2.9 million of natural gas rate decreases.
Depreciation, Depletion, Amortization, and Accretion
Depreciation, depletion, amortization, and accretion was $44.6 million, or $0.49 per Mcfe, for the three months ended September 30, 2026, which was an increase of $7.3 million, or 19%, from $37.3 million, or $0.49 per Mcfe, for the three months ended September 30, 2025. The increase was primarily attributable to an additional $3.3 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 $24.5 million, or $0.27 per Mcfe, for the three months ended September 30, 2026, which was an increase of $7.0 million, from $17.5 million, or $0.23 per Mcfe, for the three months ended September 30, 2025. The increase was primarily attributable to $6.1 million of higher information technology costs, employee and office expenses, and consulting and contracting costs, which resulted in increased corporate allocations to the Upstream/Midstream segment.
Other Operating Expenses
Other operating expenses were $6.6 million, or $0.07 per Mcfe, for the three months ended September 30, 2026, which was an increase of $1.3 million, from $5.3 million, or $0.07 per Mcfe, for the three months ended September 30, 2025. The increase in
other operating expenses during the three months ended September 30, 2026, compared to the same period in 2025, was primarily attributable to $4.5 million of acquisition and integration costs with the Barnett Acquisition incurred during the current period compared to $3.8 million in integration costs from the Bedrock Acquisition incurred during the same period in the prior year, a $0.5 million write-off of accounts receivable from the Bedrock Acquisition, and $0.5 million from inactive well reclamation costs, both incurred during the current period. These increases were partially offset by a $0.4 million period-over-period decrease in emissions monitoring.
Power Segment
Comparison of the three months ended September 30, 2026 and 2025:
Three Months Ended September 30,
(in thousands, other than percentages) 2026 2025 Change % Change
Temple I capacity factor 75.9 % 71.1 % 4.8 % 7 %
Temple II capacity factor 67.4 % 67.5 % (0.1) % - %
Total power generation (GWh)
2,317 2,246 71 3 %
Fuel consumption (thousands of MMBtu) 16,812 16,025 787 5 %
Average generation price (excluding derivatives)
$ 34.74 $ 45.41 $ (10.67) (23) %
Average generation price (including derivatives)
$ 40.37 $ 43.89 $ (3.52) (8) %
Average natural gas cost $ 2.64 $ 2.88 $ (0.24) (8) %
Average spark spread $ 21.18 $ 23.32 $ (2.14) (9) %
Revenues and other operating income
Power revenues
$ 87,445 $ 85,018 $ 2,427 3 %
Derivative gains, net 83,358 93,845 (10,487) (11) %
Total revenues and other operating income 170,803 178,863 (8,060)
Operating expenses
Fuel commodity costs 44,459 46,173 (1,714) (4) %
Purchased power 44,659 41,427 3,232 8 %
Marketing expense 762 737 25 3 %
Taxes other than income 5,110 3,948 1,162 29 %
Depreciation, depletion, amortization, and accretion 9,482 9,546 (64) (1) %
Power operating and maintenance
17,402 17,647 (245) (1) %
General and administrative 8,889 5,585 3,304 59 %
Other operating expenses
1,521 1,695 (174) (10) %
Total operating expenses 132,284 126,758 5,526
Income from operations $ 38,519 $ 52,105 $ (13,586)
*Percentage not meaningful
Power Revenues
During the three months ended September 30, 2026, our Power revenues were $87.4 million, which was an increase of $2.4 million, or 3%, from $85.0 million for the three months ended September 30, 2025, which include merchant energy sales and revenue from our retail business. The increase was primarily due to the increase in retail sales, which was attributable to an increase in retail customers period-over-period.
Derivative Gains, Net
For the three months ended September 30, 2026, our Power segment had net realized and unrealized gains on derivative contracts of $83.4 million, compared to net realized and unrealized gains of $93.8 million for the same period in 2025, representing a decrease of $10.5 million. The decrease is primarily due to a $10.1 million unfavorable change in unrealized gains on our power derivatives driven by an increase in the forward power curve relative to the fixed contracted prices. The remaining
decreases were due to a $41.6 million unfavorable change in net realized gains on our power derivatives driven by higher realized market power prices relative to contracted prices between periods, offset by a $39.4 million favorable change in realized gains on HRCO settlements and a $1.4 million favorable change in realized results on our natural gas hedges.
Fuel Commodity Costs
Fuel commodity costs were $44.5 million for the three months ended September 30, 2026, which was a decrease of $1.7 million, or 4%, from $46.2 million for the three months ended September 30, 2025. The decrease was due to lower gas prices during the three months ended September 30, 2026 compared to the three months ended September 30, 2025, offset by higher fuel consumption period-over-period.
Purchased Power
Purchased power costs for the retail business were $44.7 million for the three months ended September 30, 2026, which was an increase of $3.2 million, or 8%, from $41.4 million for the three months ended September 30, 2025. The increase in purchased power was due to higher sales from our retail business. This increase was offset by a $4.6 million favorable period-over-period change in the unrealized fair value of power derivatives included in purchased power costs, which resulted in a net unrealized gain of $3.6 million during the three months ended September 30, 2026, compared to a net unrealized loss of $1.0 million during the same period in 2025. The change in the unrealized fair value reflects changes in forward market power prices from the respective prior valuation dates, as well as differences in the outstanding derivative positions.
Marketing Expense
Marketing expense was $0.8 million for the three months ended September 30, 2026 and $0.7 million for the three months ended September 30, 2025.
Taxes Other Than Income
Taxes other than income were $5.1 million for the three months ended September 30, 2026, which was an increase of $1.2 million, or 29%, from $3.9 million for the three months ended September 30, 2025. The increase was driven by a subsequent property tax reassessment from the county that resulted in a higher assessed property value, including a catch-up amount related to prior periods.
Depreciation, Depletion, Amortization, and Accretion
Depreciation, depletion, amortization, and accretion was $9.5 million for both the three months ended September 30, 2026 and 2025, 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 $17.4 million for the three months ended September 30, 2026, which was a decrease of $0.2 million, or 1%, from $17.6 million for the three months ended September 30, 2025. The decrease was primarily due to a $0.7 million decrease in salaries and wages due to employees moving from the Power segment to Corporate and Other, offset by a $0.4 million increase in BKV-BPP Retail's service costs.
General and Administrative
General and administrative expenses were $8.9 million for the three months ended September 30, 2026, which was an increase of $3.3 million, from $5.6 million for the three months ended September 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, and BKV-BPP Retail's costs to acquire new customers.
Other Operating Expenses
Other operating expenses were $1.5 million for the three months ended September 30, 2026, which was a decrease of $0.2 million, from $1.7 million for the three months ended September 30, 2025. The decrease was due to lower transaction costs related to the BKV-BPP Power Joint Venture Transaction period-over-period.
Other Income Statement Line Items
Section 45Q Tax Credits
Our Section 45Q tax credits decreased by $0.5 million, or 12%, to $3.3 million during the three months ended September 30, 2026, from $3.7 million during the three months ended September 30, 2025. Our Section 45Q tax credits relate to CO2 waste sequestration activities under our Barnett Zero, Cotton Cove and Eagle Ford projects. The decrease was primarily attributable to the recognition of a 7% and 8% discount to the face of Section 45Q tax credits generated in 2025 and 2026, respectively, in connection with their sale to a third party during the three months ended September 30, 2026. The decrease was partially offset by increased Section 45Q tax credits generated from higher volumes of CO2 waste sequestered following the commencement of injection operations at the Cotton Cove and Eagle Ford projects during the first half of 2026.
General and Administrative
General and administrative expenses were $10.9 million, for the three months ended September 30, 2026, which was an increase of $2.6 million, from $8.3 million, for the three months ended September 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 and consulting expenses and a reclassification of early-stage CCUS project development costs from general and administrative expenses into other operating expenses during the three months ended September 30, 2026.
Other Operating Expenses
Other operating expenses were $3.3 million for the three months ended September 30, 2026, which was a decrease of $3.7 million, from $7.1 million, for the three months ended September 30, 2025. The decrease was primarily attributable to a $5.6 million ERP write-off recognized during the three months ended September 30, 2025. This decrease was partially offset by a $1.8 million reclassification of early-stage CCUS project development costs from general and administrative expenses into other operating expenses during the three months ended September 30, 2026. These costs were incurred before the related projects were placed in service and before we and our joint venture partners began funding the projects.
Other Income (Expense)
Interest expense. Interest expense was $25.7 million for the three months ended September 30, 2026, which was an increase of $8.1 million, from $17.5 million for the three months ended September 30, 2025. The increase in interest expense during the three months ended September 30, 2026 was primarily due to an increase of $8.8 million of interest on the 2030 Senior Notes, $0.6 million of higher debt amortization expense, $0.6 million of interest on the Promissory Note, and $0.4 million of interest on our 2031 Convertible Senior Notes. These increases were partially offset by $1.4 million and $0.9 million of lower interest expense on the Temple Term Loan Facility and the RBL Credit Agreement, 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 September 30, 2026, which was a decrease of $1.0 million, from $5.0 million for the three months ended September 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 $2.0 million for the three months ended September 30, 2026, which was an increase of $1.1 million, from $1.0 million for the three months ended September 30, 2025. The increase was due to higher average cash balances during the three months ended September 30, 2026, compared to the same period in 2025.
Income tax expense. For the three months ended September 30, 2026, we had an income tax expense of $3.0 million, which was a decrease of $20.9 million, from a $23.9 million income tax expense for the three months ended September 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 nine months ended September 30, 2026 and 2025:
Nine Months Ended September 30,
(in thousands, other than percentages) 2026 2025 Change % Change
Production volume
Total production volumes (MMcfe) 262,543 218,520 44,023 20 %
Average daily production (MMcfe/d)
961.7 800.4 161.3 20 %
Average realized price (excluding derivatives) $ 2.85 $ 2.78 $ 0.07 3 %
Average realized price (including derivatives) $ 3.03 $ 2.83 $ 0.20 7 %
Revenues and other operating income
Natural gas revenues $ 564,291 $ 474,478 $ 89,813 19 %
NGL revenues 171,665 126,086 45,579 36 %
Oil revenues 11,369 7,726 3,643 47 %
Derivative gains, net 54,318 34,907 19,411 56 %
Marketing revenues 111,102 26,305 84,797 *
Other 456 (1,704) 2,160 *
Total revenues and other operating income 913,201 667,798 245,403
Operating expenses
Lease operating and workover 136,125 106,151 29,974 28 %
Marketing expense 87,528 11,570 75,958 *
Taxes other than income 38,577 35,269 3,308 9 %
Gathering and transportation 206,398 180,641 25,757 14 %
Depreciation, depletion, amortization, and accretion 128,116 114,479 13,637 12 %
General and administrative 68,785 46,313 22,472 49 %
Other operating expenses
12,043 8,942 3,101 35 %
Total operating expenses 677,572 503,365 174,207
Income from operations $ 235,629 $ 164,433 $ 71,196
Per unit costs
Lease operating and workover $ 0.52 $ 0.49 $ 0.03 6 %
Marketing expense $ 0.33 $ 0.05 $ 0.28 *
Taxes other than income $ 0.15 $ 0.16 $ (0.01) (6) %
Gathering and transportation $ 0.79 $ 0.83 $ (0.04) (5) %
Depreciation, depletion, amortization, and accretion $ 0.49 $ 0.52 $ (0.03) (6) %
General and administrative $ 0.26 $ 0.21 $ 0.05 24 %
Other operating expenses
$ 0.05 $ 0.04 $ 0.01 25 %
Total $ 2.59 $ 2.30 $ 0.29
*Percentage not meaningful
Natural Gas Revenues
Our natural gas revenues increased by $89.8 million, or 19%, to $564.3 million for the nine months ended September 30, 2026, from $474.5 million for the nine months ended September 30, 2025. The increase was due to higher production volumes during the nine months ended September 30, 2026, which accounted for a $112.4 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 $22.6 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 $45.6 million, or 36%, to $171.7 million for the nine months ended September 30, 2026, from $126.1 million for the nine months ended September 30, 2025. The increase was due to $37.1 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 an $8.5 million increase (calculated as the change in period-to-period volumes times the prior period average price).
Oil Revenues
Our oil revenues increased by $3.6 million, or 47%, to $11.4 million for the nine months ended September 30, 2026, from $7.7 million for the nine months ended September 30, 2025. The increase was primarily due to the impact of commodity price increases, excluding the effect of derivative settlements, which accounted for a $2.8 million increase in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes) and higher production volumes, which accounted for a $0.8 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).
Derivative Gains, Net
For the nine months ended September 30, 2026, our Upstream/Midstream segment had net realized and unrealized gains on derivative contracts of $54.3 million, compared to net realized and unrealized gains of $34.9 million for the same period in 2025. The favorable change during the nine months ended September 30, 2026, was primarily attributable to our realized gains of $47.8 million compared to $10.8 million for the nine months ended September 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. Offsetting the gain position in our derivative gains, net, our open derivative positions were in an unrealized gain position of $6.5 million, compared to $24.1 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.
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. Starting in the second quarter of 2026, we began marketing all of our own natural gas production, causing our marketing revenues to increase by approximately $84.8 million to $111.1 million for the nine months ended September 30, 2026, from $26.3 million for the nine months ended September 30, 2025.
Other Revenues
Other revenues include the gain (loss) on sale of assets, which was a gain of $0.5 million for the nine months ended September 30, 2026, compared to a loss of $1.7 million for the same period in 2025. The period-over-period increase was primarily due to a gain on sale of assets of $0.3 million during the nine months ended September 30, 2026, whereas the prior year period included a loss of $2.9 million on the sale of the Bridgeport building, offset by a gain on sale of assets of $1.1 million.
Lease Operating and Workover
The following table summarizes our components of lease operating expenses for the periods presented:
Nine Months Ended September 30,
2026 2025 $ Change % Change
(in thousands, other than percentages and average costs) Amount Per Mcfe Amount Per Mcfe
Lease operating expenses $ 127,880 $ 0.48 $ 101,112 $ 0.46 $ 26,768 26 %
Workover expenses 8,245 0.04 5,039 0.03 3,206 64 %
Total lease operating and workover expense $ 136,125 $ 0.52 $ 106,151 $ 0.49 $ 29,974 28 %
Lease operating and workover expenses were $136.1 million, or $0.52 per Mcfe, for the nine months ended September 30, 2026, which was an increase of $30.0 million, or 28%, from $106.2 million, or $0.49 per Mcfe, for the nine months ended September 30, 2025. The increase in lease operating and workover expenses during the nine months ended September 30, 2026, compared to the same period in 2025, was primarily attributable to $29.2 million of lease operating and workover expenses associated with BKV Barnett II, which was acquired in connection with the Bedrock Acquisition in September 2025, and $1.3 million associated with the Barnett Acquisition in September 2026.
Marketing Expense
Beginning in the second quarter of 2026, we began marketing all of our own natural gas production, causing our marketing expenses to increase by approximately $76.0 million to $87.5 million for the nine months ended September 30, 2026, from $11.6 million for the nine months ended September 30, 2025.
Taxes Other Than Income
Taxes other than income were $38.6 million, or $0.15 per Mcfe, for the nine months ended September 30, 2026, which was an increase of $3.3 million, or 9%, from $35.3 million, or $0.16 per Mcfe, for the nine months ended September 30, 2025. The increase was primarily driven by a $6.4 million increase in production taxes and ad valorem and property taxes attributable to BKV Barnett II and $2.3 million of higher production tax in the legacy Barnett. These increases were offset by a $2.9 million production tax refund, a $2.1 million decrease in Texas ad valorem and property taxes due to the increase in the business and personal property tax exemption under Texas House Bill 9, and a $0.3 million decrease in ad valorem and property tax in NEPA.
Gathering and Transportation
Gathering and transportation expenses were $206.4 million, or $0.79 per Mcfe, for the nine months ended September 30, 2026, which was an increase of $25.8 million, or 14%, from $180.6 million, or $0.83 per Mcfe, for the nine months ended September 30, 2025. This increase was primarily driven by $14.8 million and $3.6 million of higher costs associated with natural gas and NGL production volumes, respectively, and $6.1 million and $1.3 million of rate increases in natural gas and NGL, respectively.
Depreciation, Depletion, Amortization, and Accretion
Depreciation, depletion, amortization, and accretion was $128.1 million, or $0.49 per Mcfe, for the nine months ended September 30, 2026, which was an increase of $13.6 million, or 12%, from $114.5 million, or $0.52 per Mcfe, for the nine months ended September 30, 2025. The increase was primarily due to an additional $10.2 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 $68.8 million, or $0.26 per Mcfe, for the nine months ended September 30, 2026, which was an increase of $22.5 million, from $46.3 million, or $0.21 per Mcfe, for the nine months ended September 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 $12.0 million, or $0.05 per Mcfe, for the nine months ended September 30, 2026, which was an increase of $3.1 million, from $8.9 million, or $0.04 per Mcfe, for the nine months ended September 30, 2025. The increase was primarily attributable to $4.6 million of integration costs with the Barnett Acquisition incurred during the current period, a
$1.6 million increase in integration costs from the Bedrock Acquisition and a $1.0 million reduction in emissions costs period-over-period, and $0.5 million of write-off of accounts receivable from the Bedrock Acquisition, and $0.4 million from inactive well reclamation costs, both incurred during the current period. These increases were partially offset by a $2.1 million deficiency payment incurred under our minimum volume commitments on our midstream pipeline recognized during the same period in 2025 and a $2.0 million reduction in legal and consulting fees.
Power Segment
Comparison of the nine months ended September 30, 2026 and 2025:
Nine Months Ended September 30,
(in thousands, other than percentages) 2026 2025 Change % Change
Temple I capacity factor 69.9 % 60.2 % 9.7 % 16 %
Temple II capacity factor 65.9 % 58.8 % 7.1 % 12 %
Total power generation (GWh)
6,520 5,746 774 13 %
Fuel consumption (thousands of MMBtu) 46,800 40,852 5,948 15 %
Average generation price (excluding derivatives)
$ 37.75 $ 37.80 $ (0.05) - %
Average generation price (including derivatives)
$ 44.03 $ 46.77 $ (2.74) (6) %
Average natural gas cost $ 3.09 $ 3.24 $ (0.15) (5) %
Average spark spread $ 21.88 $ 23.73 $ (1.85) (8) %
Revenues and other operating income
Power revenues
$ 230,797 $ 190,806 $ 39,991 21 %
Derivative gains, net 226,914 222,471 4,443 2 %
Total revenues and other operating income 457,711 413,277 44,434
Operating expenses
Fuel commodity costs 144,412 132,388 12,024 9 %
Purchased power 101,516 89,588 11,928 13 %
Marketing expense 2,167 1,881 286 15 %
Taxes other than income 13,646 13,154 492 4 %
Depreciation, depletion, amortization, and accretion 30,838 28,709 2,129 7 %
Power operating and maintenance
52,346 53,341 (995) (2) %
General and administrative 25,705 19,022 6,683 35 %
Other operating expenses
10,568 2,518 8,050 *
Total operating expenses 381,198 340,601 40,597
Income from operations $ 76,513 $ 72,676 $ 3,837
*Percentage not meaningful
Power Revenues
During the nine months ended September 30, 2026, our Power revenues were $230.8 million, which was an increase of $40.0 million, or 21%, compared to $190.8 million during the nine months ended September 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 and retail sales,which was due to an increase in retail customers period-over-period.
Derivative Gains, Net
For the nine months ended September 30, 2026, our Power segment had net realized and unrealized gains on derivative contracts of $226.9 million, compared to $222.5 million for the same period in 2025, representing an increase in net realized and unrealized gains on derivative contracts of $4.4 million. The increase in gains reflected a $108.7 million favorable change in realized gains on HRCO settlements, 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, a $14.5 million favorable change in unrealized gains on our power derivatives, and a $3.1 million favorable change in unrealized losses on our natural gas hedges. This was offset by a $120.9 million decrease in net realized gains on our power derivatives driven by higher realized market power prices relative to contracted prices and a $1.0 million unfavorable change in realized results on our natural gas hedges.
Fuel Commodity Costs
Fuel commodity costs were $144.4 million for the nine months ended September 30, 2026, which was an increase of $12.0 million, or 9%, from $132.4 million for the nine months ended September 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 $101.5 million for the nine months ended September 30, 2026, which was an increase of $11.9 million, or 13%, from $89.6 million for the nine months ended September 30, 2025. The increase in purchased power costs was due to higher sales from our retail business. This increase was also due to a $1.6 million favorable period-over-period change in the unrealized fair value of power derivatives included in purchased power costs, which resulted in a net unrealized gain of $0.2 million during the nine months ended September 30, 2026, compared to a net unrealized loss of $1.4 million during the same period in 2025. The change in the unrealized fair value reflects changes in forward market power prices from the respective prior valuation dates, as well as differences in the outstanding derivative positions.
Taxes Other Than Income
Taxes other than income were $13.6 million for the nine months ended September 30, 2026, which was an increase of $0.5 million, or 4%, from $13.2 million for the nine months ended September 30, 2025. The increase was driven by a subsequent property tax reassessment from the county that resulted in a higher assessed property value, including a catch-up amount related to prior periods.
Depreciation, Depletion, Amortization, and Accretion
Depreciation, depletion, amortization, and accretion was $30.8 million for the nine months ended September 30, 2026, which was an increase of $2.1 million, or 7%, from $28.7 million for the nine months ended September 30, 2025. The increase was primarily due to the true-up of depreciation on equipment during the nine months ended September 30, 2026.
Power Operating and Maintenance
Power operating and maintenance expenses are costs incurred to run the Temple Plants and were $52.3 million for the nine months ended September 30, 2026, which was a decrease of $1.0 million, or 2%, from $53.3 million for the nine months ended September 30, 2025. The decrease was primarily due to a $1.6 million decrease in salaries and wages due to employees moving from the Power segment to Corporate and Other, offset by a $0.7 million increase in BKV-BPP Retail's service costs.
General and Administrative
General and administrative expenses were $25.7 million for the nine months ended September 30, 2026, which was an increase of $6.7 million, from $19.0 million for the nine months ended September 30, 2025. The increase was primarily attributable to higher allocations of corporate general and administrative costs and $3.9 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 $10.6 million for the nine months ended September 30, 2026, which was an increase of $8.1 million, from $2.5 million for the nine months ended September 30, 2025. The increase was due to $7.8 million of higher transaction costs related to the BKV-BPP Power Joint Venture Transaction period-over-period. In addition, there were $0.2 million of increased gas transportation and storage expense during the nine months ended September 30, 2026 compared to the same period in 2025.
Other Income Statement Line Items
Section 45Q Tax Credits
Our Section 45Q tax credits decreased by $0.2 million, or 2%, to $9.4 million during the nine months ended September 30, 2026, from $9.6 million during the nine months ended September 30, 2025. Our Section 45Q tax credits related to CO2 waste sequestration activities under our Barnett Zero, Cotton Cove and Eagle Ford projects. The decrease was primarily attributable to the recognition of a 7% and 8% discount to the face of Section 45Q tax credits generated in 2025 and 2026, respectively, in connection with their sale to a third party during the nine months ended September 30, 2026. The decrease was offset by increased Section 45Q tax credits generated from higher volumes of CO2 waste sequestered following the commencement of injection operations at the Cotton Cove and Eagle Ford projects during the first half of 2026.
Other Revenues
For the nine months ended September 30, 2026, other revenues was a loss of $3.6 million, which included the impairment of our asset held for sale.
General and Administrative
General and administrative expenses were $34.3 million, for the nine months ended September 30, 2026, which was an increase of $6.7 million, from $27.6 million, for the nine months ended September 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 $7.0 million for the nine months ended September 30, 2026, which was a decrease of $10.4 million, from $17.3 million for the nine months ended September 30, 2025. The decrease was due to activity during the nine months ended September 30, 2025, which included a $5.6 million ERP write-off, $3.1 million of costs related to the CCUS equity raise, $2.3 million in CCUS transaction fees, and $1.1 million in a project write-off. The decrease was also due to a $0.6 million and a $0.4 million decrease in CCUS operating expenses and emissions monitoring, respectively, period-over-period. This decrease was partially offset by a $1.8 million reclassification of early-stage CCUS project development costs from general and administrative expenses into other operating expenses during the nine months ended September 30, 2026. These costs were incurred before the related projects were placed in service and prior to being funded by us and our joint venture partners.
Other Income (Expense)
Interest expense. Interest expense was $73.4 million for the nine months ended September 30, 2026, which was an increase of $23.4 million, from $49.9 million for the nine months ended September 30, 2025. The increase in interest expense during the nine months ended September 30, 2026 was primarily due to $27.4 million of interest on the 2030 Senior Notes, $2.0 million of higher debt amortization expense, $1.7 million of interest on the Promissory Note, an increase of $0.9 million of interest on our letters of credit, and $0.4 million of interest on the 2031 Convertible Senior Notes. These increases were partially offset by $5.2 million and $4.0 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 $12.3 million for the nine months ended September 30, 2026, which was a decrease of $2.9 million, from $15.1 million for the nine months ended September 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 $5.7 million for the nine months ended September 30, 2026, which was an increase of $3.3 million, from $2.5 million for the nine months ended September 30, 2025. The increase was due to higher average cash balances during the nine months ended September 30, 2026, compared to the same period in 2025.
Income tax expense. For the nine months ended September 30, 2026, we had an income tax expense of $34.6 million, which was an increase of $12.2 million, from a $22.4 million income tax expense for the nine months ended September 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 nine months ended September 30, 2026 included the development of our natural gas properties, deposits for modular power generation equipment and associated reservation fees, funding the Barnett Acquisition, land acquisitions, and funding the BKV-BPP Power Joint Venture transaction. Our primary uses of cash during the nine months ended September 30, 2025 included funding the Bedrock Acquisition and the development of our natural gas properties.
Operating and Development Capital Expenditures
During the nine months ended September 30, 2026 and 2025, cash paid for capital expenditures was $274.9 million and $209.6 million, respectively, and deposits paid as part of our strategic growth initiatives were $243.3 million and $15.0 million, respectively. Our current estimated 2026 budget for total accrued capital expenditures is approximately $850 million to $920 million on a Company-wide basis. This includes deposits and equipment payments made directly by lenders in connection with our strategic capital program. To help fund these capital expenditures, we expect to receive approximately $160 million to $180 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 accrued capital expenditure range to $690 million to $740 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 March 25, 2026 and May 15, 2026, we entered into two separate equipment supply contracts related to a planned modular power generation project. Under the agreements, BKV Corporation and BKV-BPP Power are 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 nine months ended September 30, 2026, we paid $171.3 million of the purchase payments. If BKV-BPP Power terminates the contracts before manufacturing of the equipment begins, BKV Corporation and BKV-BPP Power would be required to pay 60% of the contract price, and if BKV-BPP Power terminates the contracts after manufacturing of the equipment begins, BKV Corporation and BKV-BPP Power would be required to pay 100% of the contract price. Based on our respective ownership of BKV-BPP Power, BPPUS has agreed to fund its pro rata share of any such payments made by BKV Corporation.
On October 2, 2026, we entered into an equipment and services contract for a planned power generation project in Texas. The contract provides for the purchase of power generation equipment with aggregate generation capacity of up to approximately 1,230 MW, as well as related technical advisory, performance testing and training services. Our aggregate purchase commitment is $797.5 million, subject to adjustments, including $80.0 million, which had previously been paid as non-refundable reservation fees during the nine months ended September 30, 2026. Accordingly, approximately $717.5 million remains payable under the contract. Payments are principally scheduled through December 2028, with the final 2.5% payable upon substantial and final completion in June and July 2030, respectively. Inclusive of the $80.0 million we previously paid for, approximately $200.0 million is due on or before March 31, 2027, of which $120.0 million remains payable. Approximately 90% of the portion of the $200.0 million that is due on or before March 31, 2027 is covered by way of a backstop agreement with a leading investment-grade hyperscaler. This hyperscaler is also the intended offtaker for our prospective power generation project. If we have not reached mutually agreeable offtake arrangements by March 31, 2027, then we may at such time terminate this contract for convenience and have no further payment obligations thereunder.
On October 9, 2026, BKV Corporation and BKV-BPP Power each entered into a separate equipment supply contract related to the planned modular power generation project. BKV Corporation guaranteed BKV-BPP Power's obligations under its contract and BPPUS has agreed to fund its pro rata share of any such payments made by BKV Corporation. Under the agreements, BKV
Corporation and BKV-BPP Power are committed to pay approximately $242.6 million and $235.5 million, respectively, in aggregate purchase payments, less the commitment amounts previously paid, for the manufacture, delivery and commissioning of the additional equipment. The stated purchase commitments exclude separately reimbursable duties, tariffs and certain taxes and are subject to a limited foreign-currency adjustment. BKV Corporation's and BKV-BPP Power's payments under these contracts are scheduled in phases from 2026 through 2030 and 2026 through 2028, respectively. On October 13, 2026, BKV Corporation and BKV-BPP Power paid $24.3 million and $40.1 million, respectively, of the purchase payments. If either BKV Corporation or BKV-BPP Power cancels its respective agreement for convenience, it generally would be required to pay a cancellation fee ranging from 30% to 100% of the applicable contract price, depending on the date of cancellation, less any portion of the contract price previously paid.
In connection with the equipment supply contract entered into by BKV-BPP Power, on October 9, 2026, BKV-BPP Power entered into a cost reimbursement agreement with the intended offtaker for the prospective power project. If mutually agreeable offtake arrangements are not agreed to by November 18, 2026 (subject to extension by mutual agreement), then BKV-BPP Power may terminate the supply contract and the intended offtaker will be required to reimburse eligible termination fees and realized losses up to $179.3 million. The agreement contemplates an extension to December 21, 2026, and the ability to extend further, each on mutual agreement. Under certain circumstances, the intended offtaker may elect to take assignment of the equipment supply contract in which case it would reimburse BKV-BPP Power for eligible costs, subject to an aggregate cap of $374.1 million. This agreement also allows us to maintain our development schedule while advancing commercial discussions toward a long-term power purchase agreement.
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 our joint venture partners, 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.
Short-Term Liquidity
We believe that our cash flows from operations, cash on hand, availability under our RBL Credit Agreement, expected contributions from our joint venture partners, and our commodity and power hedges in place will provide sufficient liquidity to fund our expected operations, planned capital expenditures and other material cash requirements, and to service our debt, through September 30, 2027. These requirements include the material contractual payments due during this current period, including payments under our power-equipment commitments and scheduled debt maturities, as applicable.
Long-Term Liquidity
Beyond September 30, 2027, our material cash requirements include our planned capital program, contractual commitments related to our power-growth initiatives, debt service, and scheduled debt maturities. We expect to fund these requirements through a combination of cash flows from operations, cash on hand, borrowings under our existing credit facilities, capital contributions from joint venture partners, project-level financing, and, as appropriate, potential debt or equity issuances and asset monetizations. 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. If our capital requirements exceed these sources, we may pursue asset sales, leasehold or mineral-interest sales, or additional debt or equity issuances, none of which may be available on satisfactory terms, or at all. The availability and timing of these sources may be affected by commodity prices, operating performance, capital market conditions, and the timing of third-party and joint venture funding.
The following table summarizes our cash flows for the nine months ended September 30, 2026 and 2025 (in thousands):
Nine Months Ended September 30,
2026 2025
Net cash provided by operating activities $ 346,211 $ 214,803
Net cash used in investing activities (858,746) (435,673)
Net cash provided by financing activities 884,074 299,088
Net increase in cash, cash equivalents, and restricted cash $ 371,539 $ 78,218
Cash flows provided by operating activities. Net cash provided by operating activities was $346.2 million for the nine months ended September 30, 2026, compared to $214.8 million for the nine months ended September 30, 2025. Net cash provided by operating activities increased during the nine months ended September 30, 2026, compared to the nine months ended September 30, 2025 due to an $86.8 million increase in income from operations (excluding noncash items), resulting from higher production volumes and higher 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, an $11.8 million favorable change in working capital, and increases of $3.3 million and $1.9 million in interest income and other income, respectively. These cash inflows were partially offset by an $8.6 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 $858.7 million for the nine months ended September 30, 2026, compared to $435.7 million for the nine months ended September 30, 2025. The increase was driven by a $228.3 million increase in cash deposits on equipment supply and manufacturing reservations, $200.4 million of cash paid in the Barnett Acquisition, and $140.9 million in purchases of land. The increase was also attributable to higher capital expenditures, including a $28.6 million increase in the Power segment, a $20.0 million increase in CCUS capital expenditures, and a $17.7 million increase in the Upstream/Midstream segment, partially offset by a $1.0 million decrease in the Corporate and Other segment. Contributing to the cash outflow during the nine months ended September 30, 2025, was $220.3 million of cash paid for the Bedrock Acquisition, partially offset by $6.9 million in proceeds from the sales of assets and $2.1 million of cash acquired in the consolidation of a VIE in 2025.
The following table presents our capital expenditures (excluding leasehold costs and acquisitions) on an accrual basis for the nine months ended September 30, 2026 and 2025 and reconciles to cash flows used for capital expenditures in the condensed consolidated statements of cash flows.
Nine Months Ended September 30,
2026 2025
Total use of cash and cash equivalents for capital expenditures
$ (274,855) $ (209,599)
Decrease (increase) in accrued capital expenditures 6,105 (7,392)
Capital expenditures (accrued)
$ (268,750) $ (216,991)
Cash flows provided by financing activities. Net cash provided by financing activities was $884.1 million for the nine months ended September 30, 2026, which consisted of $559.2 million of cash proceeds from the issuance of the 2031 Convertible Senior Notes, net of initial purchasers' discounts and commissions and offering expenses, $240.0 million in net borrowings on the RBL Credit Agreement, $185.5 million of net proceeds from the issuance of common stock, $78.8 million of cash contributions from noncontrolling interests, $59.6 million of net proceeds on the Power Equipment Financing Facility, $46.0 million of proceeds from the Promissory Note, and $0.9 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, $64.7 million of payments for capped call transactions, $35.0 million of cash paid for repurchase of common stock, $31.6 million of payments on the Temple Term Loan Facility, $29.0 million of payments on the Temple I Loan Agreements, $5.4 million of cash distributions to noncontrolling interest, $2.9 million of debt issuance costs on the Power Equipment Financing Facility and the 2030 Senior Notes, and $2.2 million of payments for taxes related to net share settlement of restricted stock units. For the nine months ended September 30, 2025, net cash provided by financing activities was $299.1 million, primarily consisting of $490.0 million in net proceeds from the issuance of the 2030 Senior Notes and $11.0 million of cash contributions from noncontrolling interest, offset by $165.0 million of net payments under the RBL Credit Agreement, $16.9 million of payments on the Temple Term Loan Facility, $14.0 million of payments on the Temple I Loan Agreements, $4.4 million of payments on debt issuance costs, and $1.6 million of payments for taxes related to net share settlement of restricted stock units.
Working Capital
As of September 30, 2026, we had cash and cash equivalents of $619.6 million and restricted cash of $16.3 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 $658.0 million as of September 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.
2031 Convertible Senior Notes
On September 14, 2026, we issued $575.0 million aggregate principal amount of 1.625% convertible senior notes due October 15, 2031 (the "2031 Convertible Senior Notes"), which includes the full exercise of the initial purchasers' option to purchase up to an additional $75.0 million principal amount of the 2031 Convertible Senior Notes. The 2031 Convertible Senior Notes were issued pursuant to an indenture dated September 14, 2026, by and between the Company and U.S. Bank Trust Company, N.A., as trustee, and resulted in proceeds of $559.2 million, after deducting initial purchasers' discounts and commissions, and debt issuance costs and offering expenses of $15.8 million. These debt issuance costs are amortized to interest expense on the condensed consolidated statements of income over the term of the 2031 Convertible Senior Notes. The proceeds were used to fund privately negotiated capped call transactions and concurrent share repurchases, with the remainder used for general corporate purposes, including repayment of outstanding indebtedness and capital expenditures.
Interest on the 2031 Convertible Senior Notes is payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2027. The 2031 Convertible Senior Notes are senior unsecured obligations of BKV Corporation and rank equally in right of payment with our existing and future senior unsecured indebtedness, senior in right of payment to our existing and future indebtedness that is expressly subordinated to the 2031 Convertible Senior Notes and are effectively subordinate to our existing and future secured debt, to the extent of the value of the collateral securing that indebtedness, including borrowings under the RBL Credit Agreement and the Promissory Note. The indenture governing the 2031 Convertible Senior Notes contains limited covenants and sets forth certain events of default after which the 2031 Convertible Senior Notes may be declared due and payable and sets forth certain types of bankruptcy or insolvency events of default involving BKV Corporation, after which the 2031 Convertible Senior Notes become automatically due and payable.
We may redeem the 2031 Convertible Senior Notes, in whole or in part, at our option, from time to time, on or after October 15, 2029 and on or before the 50th scheduled trading day immediately preceding the maturity date, but only if specified conditions are satisfied. These conditions include that the 2031 Convertible Senior Notes are freely tradable as of the date we send the related redemption notice and that the last reported sale price per share of our common stock exceeds 130% of the conversion price for the required period.We may also redeem all, but not less than all, of the 2031 Convertible Senior Notes if the aggregate principal amount outstanding is less than 10% of the aggregate principal amount of the notes originally issued, including any additional notes issued upon exercise of the initial purchasers' option, in each case subject to specified conditions. In addition, holders may require us to repurchase the 2031 Convertible Senior Notes upon the occurrence of a fundamental change, as defined in the indenture, at a repurchase price equal to 100% of the principal amount of the notes to be repurchased, plus accrued and unpaid interest, if any, to, but excluding, the fundamental change repurchase date. For more information regarding the 2031 Convertible Senior Notes, see Note 3 - Debt. For more information regarding the capped call transactions and concurrent share repurchases, see Note 9 - Stockholders' Equity.
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.
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 September 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.
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 September 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 September 30, 2026 and December 31, 2025, $5.0 million and $6.9 million, respectively, of unamortized debt issuance costs remained outstanding.
As of November 5, 2026, $280.0 million of borrowings and $15.5 million of letters of credit were outstanding under the RBL Credit Agreement, leaving $504.5 million of available capacity thereunder for future borrowings and letters of credit.
BKV-BPP Power Loan Agreements and Credit Facilities
Power Equipment Financing Facility
On September 16, 2026, BKV Corporation, as a guarantor, and BKV Power Ventures Bell, as borrower, entered into a Master Loan and Security Agreement (the "Power Equipment Financing Facility") with Citizens Asset Finance, a division of Citizens Bank, N.A. ("Citizens"), as administrative agent, and Citizens and Bangkok Bank Public Company Limited, New York Branch ("Bangkok Bank"), as lenders to finance the purchase of power generation equipment.
The Power Equipment Financing Facility provides for aggregate maximum borrowings of $161.3 million to finance eligible progress payments related to modular generation equipment for future power plant facilities in Temple, Texas. Each advance is subject to customary conditions, including delivery of equipment milestone documentation, invoices, lien waivers and other supporting information. Amounts repaid under the Power Equipment Financing Facility may not be reborrowed.
As of September 30, 2026, BKV Power Ventures Bell borrowed $84.4 million under the Power Equipment Financing Facility through separate secured promissory notes issued to Citizens and Bangkok Bank, each in an original principal amount of $42.2 million. The borrowings bear a weighted-average interest rate of one-month SOFR plus 3.95%, with interest payable monthly, commencing on October 16, 2026.
The Power Equipment Financing Facility will mature on the earliest of (i) March 16, 2028, (ii) the date that is 90 days following testing completion of the final applicable equipment unit block, or (iii) the date on which qualifying project financing for the related power generation project is funded. Prior to maturity, BKV Power Ventures Bell may voluntarily prepay the Power Equipment Financing Facility in full without penalty or premium.
Borrowings are secured by a first-priority lien on the financed equipment and components, related rights under the equipment supply contracts, warranties, insurance proceeds, accounts, and other associated collateral. The Power Equipment Financing Facility does not contain financial covenants, but contains customary covenants and events of default, upon which the lenders may accelerate outstanding borrowings, terminate further borrowings, and exercise remedies against the collateral.
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.
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 six-month SOFR plus 5.25% per annum. Interest on the loans is payable on a semi-annual basis. The Temple I Loan Agreements originally matured on November 1, 2026, and were subsequently amended on October 27, 2026, which extended the maturity date to November 1, 2027. 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 September 30, 2026 and December 31, 2025, the outstanding principal balance of the Temple I Loan Agreements for each affiliate was $81.0 million and $95.5 million, respectively.
As of September 30, 2026 and December 31, 2025, the weighted average effective interest rate on the outstanding balances under the RBL Credit Agreement, the Power Equipment Financing Facility, the Temple I Loan Agreements, and the Temple Credit Facilities was 8.40% and 8.86%, respectively.
BKV-BPP Power and BKV-BPP Cotton Cove Joint Ventures
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 - Acquisitions.
Under the terms of the BKV-BPP Power LLC Agreement, we do not have the ability to unilaterally cause BKV-BPP Power to make distributions. No distributions were made by BKV-BPP Power during the nine months ended September 30, 2026 or 2025. We may also be required to make additional capital contributions to BKV-BPP Power to fund items approved in its respective annual budgets or other matters approved by its 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.
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. Pursuant to the capital call issued by BKV-BPP Power on June 30, 2026, BKV Corporation and BPPUS contributed $190.4 million and $65.4 million, respectively, totaling $255.8 million to BKV-BPP Power. On July 17, 2026, BKV Corporation satisfied $49.5 million of its capital call through deposits for power equipment paid directly to the equipment manufacturer. On August 29, 2026, BKV Corporation satisfied $140.5 million through contributions of power equipment, deposits on power equipment, and land, and on September 1, 2026, satisfied the remaining $0.4 million capital call in cash. Also, on September 1, 2026, BPPUS funded its $65.4 million capital call through a cash contribution to BKV-BPP Power.
Under the terms of the BKV-BPP Cotton Cove LLC Agreement, we do not have the ability to unilaterally cause BKV-BPP Cotton Cove to make distributions. No distributions were made by BKV-BPP Cotton Cove during the nine months ended September 30, 2026 or 2025. We may be required to make additional capital contributions to BKV-BPP Cotton Cove to fund items approved in its annual budget or other matters approved by its board of managers. Such capital contributions are not subject to a limit on the potential amount required and would reduce the cash otherwise available to us. 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 nine months ended September 30, 2026, BKV dCarbon Ventures and BPPUS made no contributions to BKV-BPP Cotton Cove.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that could give rise to material off-balance sheet arrangements. As of September 30, 2026, our material off-balance sheet arrangements and transactions included transportation commitments of $208.6 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. 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 initial public offering. 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 November 05, 2026, and is solely responsible for the information contained herein. Distributed via EDGAR on November 05, 2026 at 20:58 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]