# BKV Corp: Form 10-Q for the period ended Mar 31, 2026

- Company: [BKV Corp](/companies/bkv.md) (CIK 1838406)
- Form: 10-Q
- Filed: 2026-05-07
- Accepted by EDGAR: May 7, 2026, 16:38 ET
- Period: 2026-03-31
- Accession: 0001628280-26-032241
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1838406/000162828026032241/bkv-20260331.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1838406/000162828026032241/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2026-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2026-01-01 to 2026-03-31 | $376.5m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Operating income | 3 months, 2026-01-01 to 2026-03-31 | $86.0m | us-gaap:OperatingIncomeLoss |
| Income tax | 3 months, 2026-01-01 to 2026-03-31 | $11.5m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2026-01-01 to 2026-03-31 | $44.1m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2026-01-01 to 2026-03-31 | $0.42 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2026-01-01 to 2026-03-31 | $0.42 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2026-01-01 to 2026-03-31 | 102,304,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2026-01-01 to 2026-03-31 | $72.0m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 3 months, 2026-01-01 to 2026-03-31 | $106.5m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Cash and equivalents | at 2026-03-31 | $288.5m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2026-03-31 | $568.0m | us-gaap:AssetsCurrent |
| Total assets | at 2026-03-31 | $4.17bn | us-gaap:Assets |
| Current liabilities | at 2026-03-31 | $432.6m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2026-03-31 | $1.86bn | us-gaap:Liabilities |
| Long-term debt | at 2026-03-31 | $1.08bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2026-03-31 | $185.4m | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2026-03-31 | $2.21bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 65,237 characters.

*The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included in Item 1 of Part I, Financial Statements in this Quarterly Report on Form 10-Q and our audited consolidated financial statements and related notes, including “Management's Discussion and Analysis of Financial Condition and Results of Operations” for the year ended December 31, 2025 included in our 2025 Annual Report on Form 10-K filed on March 6, 2026. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expectations. We disclaim any duty to publicly update any forward-looking statements except as otherwise required by applicable law.*

*In this section, references to “BKV,” the “Company,” “we,” “us,” and “our” refer to BKV Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires. For more information on our organizational structure, see Note 1 - Business and Basis of Presentation to our condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q.*

### Recent Developments

- **BKV-BPP Power Joint Venture Transaction.** On January 30, 2026, we completed the previously announced acquisition of an additional 25% interest in the BKV-BPP Power Joint Venture for aggregate consideration consisting of $115.1 million in cash and 5,315,390 shares of our common stock. We funded the cash consideration with a combination of cash on hand and the net proceeds from the 2025 Equity Offering. Following the closing of the transaction, the BKV-BPP Power Joint Venture is owned 75% by BKV Corp and 25% by BPPUS, and the financial results of BKV-BPP Power have been consolidated into our financial statements for all periods presented. For additional information, see *Note 2 - Acquisition* and *Note 14 - Reportable Segments.*
- **2026 Equity Offering.** On March 12, 2026, we completed the 2026 Equity Offering for net proceeds to the Company of $186.2 million, which were used for general corporate purposes, including working capital, operating expenses and capital expenditures. For additional information, see *Note 9 - Stockholders' Equity.*

### Operational and Financial Highlights

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

- Production of natural gas, NGLs, and oil was 83.3 Bcfe, or 925.0 MMcfe/d, respectively.
- Average realized product prices, excluding the impact of settled derivatives, was $3.46 per Mcfe.
- Power generation of 1,981 GWh from the Temple Plants and capacity factor of 62.4%.
- Upstream/Midstream production revenues were $287.7 million, and Power revenues were $69.0 million.
- Net income attributable to BKV was $44.1 million.
- Net cash provided by operating activities for the three months ended March 31, 2026 was $72.0 million.
- Accrued capital expenditures for the three months ended March 31, 2026 were $118.6 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 of price volatility, we utilize derivative contracts in connection with our operations to provide an economic hedge of our exposure to commodity price risks associated with anticipated future natural gas and NGL production and power generation. However, there are still market risks beyond our control that may impact our financial condition, results of operations, and cash flows.

***Supply, Demand, Market Risk, and the Impact on Natural Gas, NGLs, and Power Prices***. Natural gas, NGL, and power prices are subject to large fluctuations in response to relatively minor changes in the demand for natural gas, NGLs, and power. Natural gas and NGL prices are affected by current and expected supply and demand dynamics, including the level of drilling, completion, and production activities by other natural gas production companies, industry-wide supply chain disruptions, widespread shortages of labor, material, and services. Other factors impacting supply and demand include weather conditions (including severe weather events), pipeline capacity constraints, basis differentials, export capacity, supply chain quality and availability. Power prices in the ERCOT market are subject to large fluctuations in response to relatively minor changes in the weather, time of day and generation mix, along with current and expected supply and demand dynamics in the ERCOT market. The majority of the factors noted above are outside of our control.

***Power Business.*** The consolidated financial statements include the results of our power business for all periods presented, reflecting the retrospective recast of prior periods, as the BKV-BPP Power Joint Venture Transaction was accounted for as a transfer between entities under common control. However, the power business has historically operated separately from our other operations and has a different operating profile. Businesses engaged in power generation are subject to seasonal, daily, and hourly fluctuations in demand, periods of peak load, and changes in supply and demand dynamics, which can result in variability in revenues and operating costs. In addition, the power business is more capital intensive, requiring ongoing investments in land, modular generation equipment, and turbine generators, and its growth is dependent on access to capital and the ability to obtain necessary commercial agreements. As a result, our consolidated results may not be fully comparable across periods and may not be indicative of the results that would have been achieved if the power business had been operated as part of our company during those periods or of our future performance.

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

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

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

### Production Volumes and Power Data

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

| Production Data | Three Months Ended March 31, 2026 | 2025 |
| --- | ---: | ---: |
| Natural gas (MMcf) | 68,079 | 54,121 |
| NGLs (MBbls) | 2,490 | 2,344 |
| Oil (MBbls) | 39 | 53 |
| Total volumes (MMcfe) | 83,253 | 68,503 |
| Average daily total volumes (MMcfe/d) | 925.0 | 761.1 |
| **Power Data** |  |  |
| Power generation (GWh) | 1,981 | 1,588 |
| Fuel consumption | 14,016 | 11,232 |

***Impact of Acquisition and Joint Venture Transactions***. Our financial condition and results of operations for the periods presented were impacted by acquisitions and joint venture transactions completed during 2025, which changed the scale, composition, and ownership structure of our operations.

In May 2025, as part of our CCUS business strategy, we partnered with the Class B Member to form the BKV-CIP Joint Venture, and beginning in the third quarter of 2025, we consolidated the BKV-BPP Cotton Cove Joint Venture. These transactions resulted in changes to the accounting treatment of certain assets and results, including the recognition of noncontrolling interests and fair value adjustments, further affecting comparability across periods.

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

As a result of these transactions, our historical operating, financial, and reserve data may not be comparable between periods presented in this Quarterly Report on Form 10-Q.

### Sources of Revenues

Our core businesses are the production of natural gas and the generation of natural gas-fired power from our owned and operated assets. Currently, a significant portion of our revenues are derived from the sale of our natural gas production and the NGLs that are extracted from processing our natural gas, as well as from the sale of our power generated out of the Temple plants and sold to a third party at either market or negotiated contract terms. A smaller portion of our revenues are generated from the sale of crude oil, midstream and surface operations, and certain marketing revenue and other income. Our midstream and surface operations primarily support our own exploration and production operations, with revenues generated primarily from fees charged for midstream and surface services, including transportation, freshwater sourcing and disposal, and other services to us and our affiliates and, to a lesser extent, third parties.

### Realized Commodity Prices

NYMEX Henry Hub, for gas prices, and NYMEX WTI, for oil prices, are widely used benchmarks for the pricing of natural gas and oil in the United States. The price we receive for our natural gas and oil production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. In addition, we are exposed to fluctuations in wholesale electricity prices, primarily in the ERCOT market, related to our power generation and marketing activities. Power prices are influenced by several factors, including natural gas prices, weather, and market supply and demand. As such, our revenues are sensitive to the price of the underlying commodity to which they relate. For further discussion on our derivative contracts, see *Note 6 - Derivative Instruments* to the unaudited condensed consolidated financial statements. The following is a comparison of average pricing excluding and including the effects of derivatives:

| Average prices: Natural gas ($/Mcf) | Three Months Ended March 31, 2026 | 2025 |
| --- | ---: | ---: |
| Average NYMEX Henry Hub price | $5.04 | $3.65 |
| Average natural gas realized price (excluding derivatives) | $3.53 | $3.10 |
| Average natural gas realized price (including derivatives) | $3.14 | $2.86 |
| Differential | $(1.51) | $(0.55) |
| **NGLs ($/Bbl)** |  |  |
| Average NGL realized price (excluding derivatives) | $17.98 | $19.06 |
| Average NGL realized price (including derivatives) | $17.98 | $16.89 |
| **Oil ($/Bbl)** |  |  |
| Average oil realized price | $70.87 | $65.28 |
| **High and low daily spot prices** |  |  |
| **Natural gas ($/Mcf)** |  |  |
| High NYMEX Henry Hub | $30.72 | $9.86 |
| Low NYMEX Henry Hub | $2.82 | $2.93 |
| **Oil ($/Bbl)** |  |  |
| High NYMEX WTI | $104.69 | $80.73 |
| Low NYMEX WTI | $56.01 | $66.31 |
| **Power** |  |  |
| Average power price ($/MWh) (excluding derivatives) | $19.73 | $8.89 |
| Average power price ($/MWh) (including derivatives) | $51.04 | $52.87 |
| Average natural gas cost ($/Mcf) | $4.08 | $4.13 |

45

### 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 March 31, 2026 and 2025:

*(in thousands, other than percentages)*

| Production volume | Three Months Ended March 31, 2026 | 2025 | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Total production volumes (MMcfe) | 83,253 | 68,503 | 14,750 | 22% |
| Average daily production (MMcfe/d) | 925.0 | 761.1 | 163.9 | 22% |
| Average realized price (excluding derivatives) | $3.46 | $3.15 | $0.31 | 10% |
| Average realized price (including derivatives) | $3.14 | $2.89 | $0.25 | 9% |
| Revenues and other operating income |  |  |  |  |
| Natural gas revenues | $240,151 | $167,983 | $72,168 | 43% |
| NGL revenues | 44,760 | 44,683 | 77 | —% |
| Oil revenues | 2,764 | 3,460 | (696) | (20)% |
| Midstream revenues | 2,296 | 2,771 | (475) | (17)% |
| Derivative losses, net | (42,476) | (152,191) | 109,715 | \* |
| Marketing revenues | 17,527 | 9,686 | 7,841 | 81% |
| Other | 132 | (1,305) | 1,437 | \* |
| Total revenues and other operating income | 265,154 | 75,087 | 190,067 |  |
| Operating expenses |  |  |  |  |
| Lease operating and workover | 45,075 | 35,055 | 10,020 | 29% |
| Taxes other than income | 15,961 | 10,221 | 5,740 | 56% |
| Gathering and transportation | 67,802 | 55,793 | 12,009 | 22% |
| Depreciation, depletion, amortization, and accretion | 40,691 | 39,491 | 1,200 | 3% |
| General and administrative | 21,908 | 10,174 | 11,734 | \* |
| Other operating expenses | 8,860 | 4,038 | 4,822 | \* |
| Total operating expenses | 200,297 | 154,772 | 45,525 |  |
| Income (loss) from operations | $64,857 | $(79,685) | $144,542 |  |
| Per unit costs |  |  |  |  |
| Lease operating and workover | $0.54 | $0.51 | $0.03 | 6% |
| Taxes other than income | $0.19 | $0.15 | $0.04 | 27% |
| Gathering and transportation | $0.81 | $0.81 | $— | —% |
| Depreciation, depletion, amortization, and accretion | $0.49 | $0.58 | $(0.09) | (16)% |
| General and administrative | $0.26 | $0.15 | $0.11 | 73% |
| Other operating expenses | $0.11 | $0.06 | $0.05 | 83% |
| Total | $2.40 | $2.26 | $0.14 |  |
| \*Percentage not meaningful |  |  |  |  |

46

#### Natural Gas Revenues

Our natural gas revenues increased by approximately $72.2 million, or 43%, to $240.2 million for the three months ended March 31, 2026, from $168.0 million for the three months ended March 31, 2025. The increase was due to higher production volumes during the three months ended March 31, 2026, which accounted for a $43.4 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 also due to commodity price increases, excluding the effect of derivative settlements, which provided a $28.8 million increase 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 were $44.8 million for the three months ended March 31, 2026 and $44.7 million for the three months ended March 31, 2025, remaining relatively consistent period-over-period. Higher production volumes during the three months ended March 31, 2026 increased NGL revenues by $2.8 million (calculated as the change in period-to-period volumes times the prior period average price), which was largely offset by a $2.7 million decrease attributable to lower commodity prices, excluding the effect of derivative settlements (calculated as the change in the period-to-period average price times current period production volumes).

#### Oil Revenues

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

#### Midstream Revenues

Our midstream revenues decreased by approximately $0.5 million, or 17%, to $2.3 million for the three months ended March 31, 2026, from $2.8 million for the three months ended March 31, 2025. This decrease was primarily due to decreased throughput and pricing period-over-period.

#### Derivative Gains (Losses), Net

For the three months ended March 31, 2026, our Upstream/Midstream segment had net realized and unrealized losses on derivative contracts of $42.5 million, compared to net realized and unrealized losses of $152.2 million for the same period in 2025. The decrease in losses for the three months ended March 31, 2026, was primarily attributable to our open derivative positions, which were in an unrealized loss position of $16.1 million, compared to an unrealized loss position of $134.0 million for the same period in 2025. The current period primarily reflects slight increases in the forward curve of natural gas prices relative to December 31, 2025, whereas the prior year period reflected higher 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. Increasing the derivative losses for the three months ended March 31, 2026 were realized losses of $26.3 million, compared to realized losses of $18.2 million for the three months ended March 31, 2025, which were due to slightly higher natural gas prices settled in the current period compared to the same period in the prior year.

#### Marketing Revenues

Our marketing revenues are derived under our marketing agreement with a third party pursuant to which we receive a fixed percentage of all net income realized in the resale of our and other producers' hydrocarbons. Our marketing revenues increased by approximately $7.9 million to $17.6 million for the three months ended March 31, 2026, from $9.7 million for the three months ended March 31, 2025. The increase in marketing revenues during the three months ended March 31, 2026, was primarily due to a higher pricing environment and more volumes sold compared to the same period in 2025.

#### Other Revenues

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

#### Lease Operating and Workover

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

*(in thousands, other than percentages and average costs)*

|  | Three Months Ended March 31, 2026 Amount | Per Mcfe | 2025 Amount | Per Mcfe | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Lease operating expenses | $42,780 | $0.51 | $33,675 | $0.49 | $9,105 | 27% |
| Workover expenses | 2,295 | 0.04 | 1,380 | 0.02 | 915 | 66% |
| Total lease operating and workover expense | $45,075 | $0.55 | $35,055 | $0.51 | $10,020 | 29% |

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

#### Taxes Other Than Income

Taxes other than income were $16.0 million, or $0.19 per Mcfe, for the three months ended March 31, 2026, which was an increase of approximately $5.7 million, or 56%, from $10.2 million, or $0.15 per Mcfe, for the three months ended March 31, 2025. The increase was primarily driven by higher production taxes in the Barnett of $4.1 million, including $2.1 million attributable to BKV Barnett II. In addition, ad valorem and property taxes in the Barnett increased by $1.7 million, reflecting higher gas prices, of which $0.4 million was attributable to BKV Barnett II.

#### Gathering and Transportation

Gathering and transportation expenses were $67.8 million, or $0.81 per Mcfe, for the three months ended March 31, 2026, which was an increase of approximately $12.0 million, or 22%, from $55.8 million, or $0.81 per Mcfe, for the three months ended March 31, 2025. This increase was primarily driven by natural gas and NGL production of $11.9 million and $1.1 million, respectively, and natural gas rate increases of $0.3 million. These increases were offset by NGL rate decreases of $0.9 million and decreases in gathering costs associated with our midstream business of $0.4 million.

#### Depreciation, Depletion, Amortization, and Accretion

Depreciation, depletion, amortization, and accretion was $40.7 million, or $0.49 per Mcfe, for the three months ended March 31, 2026, which was an increase of approximately $1.2 million, or 3%, from $39.5 million, or $0.58 per Mcfe, for the three months ended March 31, 2025. The increase was primarily due to an increase in our proved reserves in the current period compared to the same period in 2025.

#### General and Administrative

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

#### Other Operating Expenses

Other operating expenses were $8.9 million, or $0.11 per Mcfe, for the three months ended March 31, 2026, which was an increase of approximately $4.8 million, from $4.0 million, or $0.06 per Mcfe, for the three months ended March 31, 2025. The increase in other operating expenses during the three months ended March 31, 2026, compared to the same period in 2025, was due to a $2.9 million increase in integration and transaction costs primarily due to the Bedrock Acquisition, a $1.0 million reduction in emissions costs in 2025, and an increase of $0.9 million in gas purchases due to higher gas prices.

### Power Segment

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

*(in thousands, other than percentages)*

|  | Three Months Ended March 31, 2026 | 2025 | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Temple I capacity factor | 64.5% | 45.4% | 19.1% | 42% |
| Temple II capacity factor | 60.3% | 54.2% | 6.1% | 11% |
| Total power generation (GWh) | 1,981 | 1,588 | 393 | 25% |
| Fuel consumption (MMBtu) | 14,016 | 11,232 | 2,784 | 25% |
| Average generation price (excluding derivatives) | $19.73 | $8.89 | $10.84 | \* |
| Average generation price (including derivatives) | $51.04 | $52.87 | $(1.83) | (3)% |
| Average natural gas cost | $4.08 | $4.13 | $(0.05) | (1)% |
| Average spark spread | $22.21 | $23.67 | $(1.46) | (6)% |
| Revenues and other operating income |  |  |  |  |
| Power revenues | $68,990 | $43,864 | $25,126 | 57% |
| Derivative gains, net | 95,585 | 53,808 | 41,777 | 78% |
| Total revenues and other operating income | 164,575 | 97,672 | 66,903 |  |
| Operating expenses |  |  |  |  |
| Fuel commodity costs | 57,121 | 46,363 | 10,758 | 23% |
| Purchased power | 27,355 | 18,667 | 8,688 | 47% |
| Taxes other than income | 4,234 | 4,569 | (335) | (7)% |
| Depreciation, depletion, amortization, and accretion | 11,804 | 9,627 | 2,177 | 23% |
| Power operating and maintenance | 19,679 | 20,213 | (534) | (3)% |
| General and administrative | 6,740 | 5,232 | 1,508 | 29% |
| Other operating expenses | 4,156 | 390 | 3,766 | \* |
| Total operating expenses | 131,089 | 105,061 | 26,028 |  |
| Income (loss) from operations | $33,486 | $(7,389) | $40,875 |  |
| \*Percentage not meaningful |  |  |  |  |

#### Power Revenues

During the three months ended March 31, 2026, our Power revenues were $69.0 million compared to $43.9 million during the three months ended March 31, 2025, which include merchant energy sales and revenue from our retail business. The increase was primarily due to the increase in merchant energy sales, which was attributable to higher power prices, power generation, and capacity at the Temple Plants.

#### Derivative Gains (Losses), Net

For the three months ended March 31, 2026, our Power segment had net realized and unrealized gains on derivative contracts of $95.6 million, compared to net realized and unrealized gains of $53.8 million for the same period in 2025. The increase was primarily attributable to our open derivative positions, which were in an unrealized gain position of $33.6 million as of March 31, 2026, compared to an unrealized loss position of $16.0 million for the same period in 2025. This change is largely due to decreases in power prices relative to hedged prices and the value of optionality. We also had an increase in realized gains of $35.2 million on our HRCOs during the three months ended March 31, 2026, which was primarily due to higher contracted capacity with four contracts totaling 600 MW in 2026, compared to two contracts totaling 200 MW in the prior year period. These increases were offset by a $39.8 million decrease in net realized gains on our power derivatives driven by higher realized market power prices relative to contracted prices. As the activity in the derivative gains (losses), net includes fixed-power forward sales, increases in market prices reduced the spread between fixed contract prices and settlement prices, resulting in lower realized gains. Additionally, reduced price volatility and/or lower contract volumes may have contributed to the decrease.

#### Fuel Commodity Costs

Fuel commodity costs were $57.1 million for the three months ended March 31, 2026, which was an increase of $10.8 million, or 23%, from $46.4 million for the three months ended March 31, 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 $27.4 million for the three months ended March 31, 2026, which was an increase of $8.7 million, or 47%, from $18.7 million for the three months ended March 31, 2025. The increase was primarily driven by our net realized and unrealized loss position on the power derivatives, which was $13.0 million compared to a net realized and unrealized loss of $4.4 million for the same period in 2025. As the retail power derivatives are in a long position, increases in market prices reduced the spread between fixed contract prices and settlement prices, which resulted in higher realized losses.

#### Taxes Other Than Income

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

#### Depreciation, Depletion, Amortization, and Accretion

Depreciation, depletion, amortization, and accretion was $11.8 million for the three months ended March 31, 2026, which was an increase of approximately $2.2 million, or 23%, from $9.6 million for the three months ended March 31, 2025. The increase was primarily due to the true-up of depreciation on equipment during the three months ended March 31, 2026.

#### Power Operating and Maintenance

Power operating and maintenance expenses are costs incurred to run the Temple Plants and remained relatively consistent period-over-period. These expenses were $19.7 million for the three months ended March 31, 2026, which was a decrease of approximately $0.5 million, or 3%, from $20.2 million for the three months ended March 31, 2025.

#### General and Administrative

General and administrative expenses were $6.7 million for the three months ended March 31, 2026, which was an increase of approximately $1.5 million, from $5.2 million for the three months ended March 31, 2025. The increase was primarily attributable to Company-wide growth initiatives, including higher headcount and employee expenses, and an increase in consulting and information technology expenses, which resulted in increased corporate allocations to the Power segment. This was offset by a $2.6 million decrease in lower credit loss expense with BKV-BPP Retail customers as the prior year period included significant write-offs related to 2024 and 2025 customer balances.

#### Other Operating Expenses

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

### Other Income Statement Line Items

#### Section 45Q Tax Credits

Our Section 45Q tax credits decreased by approximately $0.2 million, or 7%, to $3.1 million during the three months ended March 31, 2026, from $3.3 million during the three months ended March 31, 2025. Our Section 45Q tax credits related to CO2 waste sequestration activities under our Barnett Zero Project. The decrease period-over-period was due to less CO2 waste sequestered in 2026, reflecting routine fluctuations in activity levels that occur as part of our normal operations.

#### Other Income (Expense)

*Interest expense.* Interest expense was $22.8 million for the three months ended March 31, 2026, which was an increase of $6.8 million, from $16.0 million for the three months ended March 31, 2025. The increase in interest expense during the three months ended March 31, 2026 was primarily due to $9.4 million of interest on the 2030 Senior Notes, $0.6 million of interest on the Promissory Note, and $0.5 million of higher debt amortization expense. These increases were partially offset by $2.4 million and $1.3 million of lower interest expense on the RBL Credit Agreement and the Temple Term Loan Facility, respectively, compared to the same period in 2025.

*Interest expense, related party.* Interest expense, related party was $4.3 million for the three months ended March 31, 2026, which was a decrease of $0.8 million, from $5.1 million for the three months ended March 31, 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 $1.5 million for the three months ended March 31, 2026, which was an increase of $0.8 million, from $0.7 million for the three months ended March 31, 2025. The increase was due to a higher cash balance during the three months ended March 31, 2026, compared to the same period in 2025.

*Income tax benefit (expense).* For the three months ended March 31, 2026, we had an income tax expense of $11.5 million, which was a change of $42.1 million, from a $30.7 million income tax benefit for the three months ended March 31, 2025. The period-over-period change was primarily due to a pre-tax income for the three months ended March 31, 2026, compared to a pre-tax loss for the three months ended March 31, 2025.

### 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 three months ended March 31, 2026 included funding the BKV-BPP Power Joint Venture transaction, development of our natural gas properties, land acquisitions, deposits for modular power generation equipment and associated reservation fees. Our primary use of cash during the three months ended March 31, 2025, included funding the development of our natural gas properties.

During the three months ended March 31, 2026 and 2025, cash paid for capital expenditures was $106.5 million and $57.6 million, respectively. Our current estimated budget for total accrued capital expenditures in 2026 is approximately $570 million to $740 million on a Company-wide basis. To help fund these capital expenditures, we expect to receive approximately $85 million to $105 million of capital contributions from our joint venture partners in our CCUS and power businesses. Expected contributions from our joint venture partners would bring our 2026 net capital expenditure range to $485 million to $635 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.

On January 14, 2026, we entered into a manufacturing reservation agreement related to a planned power generation project. Under the agreement, we are committed to pay up to an aggregate of $80.0 million in reservation fees, scheduled in phases during 2026, to secure future manufacturing capacity through 2028 for turbines with up to approximately 1,230 MW in total generation capacity. During the three months ended March 31, 2026, we paid $30.0 million of the reservation fees. Amounts paid are generally non-refundable and will be credited against the purchase price if a definitive supply agreement is executed.

On March 25, 2026, we entered into an equipment supply contract related to a planned power generation project. Under the agreement, we are committed to pay up to an aggregate of $124.1 million in purchase payments, scheduled in phases from 2026 through 2027, to secure the manufacture of modular power generation equipment. During the three months ended March 31, 2026, we paid $2.5 million of the purchase payments, and on April 1, 2026, we paid an additional $33.5 million. If we terminate the contract before manufacturing of the equipment begins, we would be required to pay 60% of the contract price, and if we terminate the contract after manufacturing of the equipment begins, we would be required to pay 100% of the contract price. We have an option to exercise a contract with similar terms, pricing, payment, and equipment manufacture and delivery lead times.

### Capital Resources

Historically, our primary sources of capital and liquidity have consisted of internally generated cash flows from operations, together with loans, capital contributions from our majority stockholder, BNAC, and issuances of equity or debt. We also enter into financial instruments to reduce the impact of commodity and power price volatility and provide a level of certainty and stability around cash flows. We currently believe that our cash flows from operations, cash on hand, borrowings under our RBL Credit Agreement, proceeds from the issuance of the 2026 Equity Offering, and our commodity and power hedges in place will provide sufficient liquidity to fund our operations and our capital expenditures for the remainder of 2026, excluding our CCUS business. If capital expenditures were to exceed such capital sources during the remainder of 2026, we expect to fund such excess capital expenditures through the sale of oil and natural gas producing assets, leasehold interests or mineral interests, and potential issuances of equity or debt, none of which may be available on satisfactory terms, or at all. We expect to fund the majority of our CCUS business from a variety of external sources, including contributions from our joint ventures with the Class B Member and BPPUS, project-based equity partnerships, debt financing, and federal grants, with the remaining capital needs being funded with cash flows from operations.

The following table summarizes our cash flows for the three months ended March 31, 2026 and 2025 (in thousands):

|  | Three Months Ended March 31, 2026 | 2025 |
| --- | ---: | ---: |
| Net cash provided by operating activities | $71,989 | $16,453 |
| Net cash used in investing activities | (232,820) | (56,246) |
| Net cash provided by financing activities | 201,068 | 31,319 |
| Net increase (decrease) in cash, cash equivalents, and restricted cash | $40,237 | $(8,474) |

***Cash flows provided by operating activities.*** Net cash provided by operating activities was $72.0 million for the three months ended March 31, 2026, compared to $16.5 million for the three months ended March 31, 2025. Net cash provided by operating activities increased during the three months ended March 31, 2026, compared to the three months ended March 31, 2025 due to a $28.0 million increase in income from operations (excluding noncash items), resulting from higher natural gas and production volumes, and higher power prices, power generation, and capacity at the Temple Plants. Cash from operations also increased period-over-period due to the absence of $20.0 million and $16.2 million of cash paid in 2025 for the settlement of contingent liabilities and the purchase of put options, respectively, and a $3.9 million decrease in cash paid for interest. These increases were partially offset by a $12.4 million unfavorable change in working capital 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 $232.8 million for the three months ended March 31, 2026, compared to $56.2 million for the three months ended March 31, 2025. The increase was driven by $93.4 million of cash paid for land, and $33.1 million of cash deposits on equipment supply and manufacturing reservations. The increase was also attributable to higher capital expenditures, including a $24.7 million increase in Upstream/Midstream segment capital expenditures, a $16.6 million increase in Power segment capital expenditures, a $6.6 million increase in CCUS capital expenditures, and a $1.0 million increase in corporate and other capital expenditures, as well as a $0.9 million decrease in proceeds from the sales of assets.

The following table presents our capital expenditures (excluding leasehold costs and acquisitions) on an accrual basis for the three months ended March 31, 2026 and 2025 and reconciles to cash flows used for capital expenditures in the condensed consolidated statements of cash flows.

|  | Three Months Ended March 31, 2026 | 2025 |
| --- | ---: | ---: |
| Total use of cash and cash equivalents for capital expenditures | $(106,527) | $(57,612) |
| Increase in accrued capital expenditures | (11,440) | (487) |
| Capital expenditures (accrued) | $(117,967) | $(58,099) |

***Cash flows provided by financing activities.*** Net cash provided by financing activities was $201.1 million for the three months ended March 31, 2026, which consisted of $186.2 million of net proceeds from the issuance of common stock,

$100.0 million in net borrowings on the RBL Credit Agreement, the $46.0 million Advance, $4.2 million of cash contributions from noncontrolling interest, and $0.3 million of cash received for common stock issued pursuant to the ESPP. These inflows were offset by $115.1 million of cash paid for a portion of the consideration for the BKV-BPP Power Transaction, $15.0 million of payments on the Temple I Loan Agreements, a $2.5 million payment on the Temple Term Loan Facility, $2.1 million of payments for taxes related to net share settlement of restricted stock units, and $0.9 million of payments on debt issuance costs. For the three months ended March 31, 2025, net cash provided by financing activities was $31.3 million, primarily consisting of $35.0 million of net borrowings under the RBL Credit Agreement, offset by a $2.5 million payment on the Temple Term Loan Facility and $1.2 million of payments for taxes related to net share settlement of restricted stock units.

### Working Capital

As of March 31, 2026, we had cash and cash equivalents of $288.5 million and restricted cash of $16.0 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 $135.4 million as of March 31, 2026, compared to a net working capital deficit of $53.2 million as of December 31, 2025.

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

### 2030 Senior Notes

On September 26, 2025, BKV Upstream Midstream issued in a private placement $500.0 million of 7.50% senior unsecured notes due October 15, 2030 (the "2030 Senior Notes"). The 2030 Senior Notes were issued at par and resulted in proceeds of $490.0 million, after deducting underwriters’ discounts and commissions. The proceeds were used to repay a portion of the outstanding borrowings under the RBL Credit Agreement and fund a portion of the cash consideration for the Bedrock Acquisition, with the remainder of the purchase price being funded with shares of our common stock. In connection with the issuance of the 2030 Senior Notes, we recorded debt issuance costs of $13.6 million, which are amortized to interest expense on the condensed consolidated statements of operations over the term of the 2030 Senior Notes.

Interest on the 2030 Senior Notes is payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2026. The 2030 Senior Notes are guaranteed on a senior unsecured basis by us and all of BKV Upstream Midstream's existing restricted subsidiaries and certain future subsidiaries. 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. As of March 31, 2026, the RBL Credit Agreement had a borrowing base of $1.0 billion, an elected commitment of $800.0 million, and the ability to issue up to $40.0 million in letters of credit.

The loans under the RBL Credit Agreement may be borrowed, repaid, and reborrowed during the term of the RBL Credit Agreement. The RBL Credit Agreement will mature on June 12, 2028. The obligations under the RBL Credit Agreement are secured and guaranteed on a senior secured basis by BKV Upstream Midstream and all of BKV Upstream Midstream’s current and future material restricted subsidiaries. Loans under the RBL Credit Agreement bear interest at one, three, or six-month term SOFR or ABR, as applicable, plus a credit spread adjustment of 0.10% for SOFR borrowings, plus an applicable margin per annum. Interest is payable on the last day of each interest period and at maturity. We are obligated to pay certain fees to the lenders and administrative agent under the RBL Credit Agreement, including commitment fees on the average daily amount of the undrawn portion of the commitments. During the three months ended March 31, 2026 and 2025, BKV Upstream Midstream recognized $0.9 million and $0.5 million, respectively, of commitment fees, which are included in interest expense on the condensed consolidated statements of operations.

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 March 31, 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 March 31, 2026 and December 31, 2025, $6.3 million and $6.9 million, respectively, of unamortized debt issuance costs remained outstanding.

As of May 7, 2026, $130.0 million of borrowings and $15.0 million of letters of credit were outstanding under the RBL Credit Agreement, leaving $655.0 million of available capacity thereunder for future borrowings and letters of credit.

### Promissory Note

On March 3, 2026, in accordance with the terms of a real estate option agreement entered into on February 27, 2026, by and between a wholly-owned subsidiary of BKV Corporation, as seller, and an unaffiliated third party, as buyer, BKV Corporation, as borrower, received $46.0 million, representing an advance of a portion of the purchase price set forth in the real estate option agreement (the "Advance"). The Advance is evidenced by a promissory note (the "Promissory Note") and is secured by a first-priority security interest in the real property that is the subject of the real estate option agreement. For more information regarding the Advance and Promissory Note, see *Note 3 - Debt.*

### BKV-BPP Power Loan Agreements and Credit Facilities

#### Temple I Loan Agreements

On October 14, 2021, BKV-BPP Power entered into a Loan Agreement (the “$141 Million Banpu Loan Agreement”) with BNAC, which allowed for a single drawdown in the amount of $141.0 million. On November 1, 2021, BKV-BPP Power borrowed $141.0 million under the $141 Million Banpu Loan Agreement for the purpose of acquiring Temple I and working capital.

On October 15, 2021, BKV-BPP Power entered into a Loan Agreement (the “$141 Million BPPUS Loan Agreement” and, together with the $141 Million Banpu Loan Agreement, the “Temple I Loan Agreements”) with BPPUS, which allowed for a single drawdown in the amount of $141.0 million. On November 21, 2021, BKV-BPP Power borrowed $141.0 million under the $141 Million BPPUS Loan Agreement (and in addition to the $141.0 million borrowed under the $141 Million Banpu Loan Agreement) for the purpose of acquiring Temple I and working capital.

BKV-BPP Power’s payment obligations under the Temple I Loan Agreements are senior unsecured indebtedness. The Temple I Loan Agreements bear interest at 6-month SOFR plus 5.25% per annum. Interest on the loans is payable on a semi-annual basis, and the loans will mature on November 1, 2026. BKV-BPP Power is permitted to prepay the loans at any time, with no prepayment premium. The Temple I Loan Agreements include covenants that, among other things, prohibit BKV-BPP 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 March 31, 2026 and December 31, 2025, the outstanding principal balance of the Temple I Loan Agreements for each affiliate was $88.0 million and $95.5 million, respectively.

#### Temple Credit Facilities

On July 10, 2023, Temple Generation Intermediate Holdings II, LLC (“Temple Intermediate II”), an indirect subsidiary of BKV-BPP Power, as borrower, Temple Generation I, LLC (“Temple Generation I”), Temple Generation II, LLC (“Temple Generation II”), each of Temple Generation I and Temple Generation II being a subsidiary of Temple Intermediate II, and Temple Generation SF LLC (“Temple Generation SF”), a joint subsidiary of Temple Generation I and Temple Generation II, each as subsidiary guarantors, entered into a credit agreement (the “Beal Credit Agreement”) with Beal Bank USA and the other lenders from time to time party thereto that provides the following credit facilities (collectively, the “Temple Credit Facilities”): (i) a senior secured term loan facility with an aggregate principal amount of $500.0 million (the “Temple Term Loan Facility”), which was fully drawn in an amount equal to $500.0 million on the closing date, and (ii) a senior secured revolving credit facility in the aggregate principal amount not to exceed $60.0 million (the “Temple Revolving Facility”), which was fully drawn in an amount equal to $60.0 million on the closing date. The interest is payable annually for the Temple Credit Facilities at a rate equal to SOFR plus an interest rate margin of 4.60%.

The Temple Term Loan Facility requires a quarterly repayment at a minimum of $2.5 million per quarter, beginning on September 30, 2023. The final aggregate principal installment for the Temple Term Loan Facility is due and payable on July 10, 2028 (subject to extension by up to two additional one-year periods), and the Temple Revolving Facility terminates five business days prior to the Temple Term Loan Facility maturity date. On the closing date, Temple Intermediate II applied the proceeds of the Temple Term Loan Facility to fund a portion of the Temple II acquisition and applied the proceeds of the Temple Revolving Loan 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 Loan Facilities have been satisfied in full. Upon the occurrence and continuation of an event of default under either of the Temple Credit Facilities, Beal Bank has customary secured creditor remedies, including the right to foreclose upon the pledged collateral.

As of March 31, 2026 and December 31, 2025, the effective interest rate on the outstanding balances under the RBL Credit Agreement, the Temple I Loan Agreements, and the Temple Credit Facilities was 8.24% and 8.86%, respectively.

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

Under the terms of the BKV-BPP Power LLC Agreement and BKV-BPP Cotton Cove LLC Agreement, as applicable, we do not have the ability to unilaterally cause BKV-BPP Power or BKV-BPP Cotton Cove to make distributions. During the three months ended March 31, 2026 and 2025, no distributions were made by BKV-BPP Power or BKV-BPP Cotton Cove. In addition, we may be required to make additional capital contributions to one or both joint ventures to fund items approved in their respective annual budgets or other matters approved by their respective boards. Such additional capital contributions, which are not subject to any limit on the potential amount required, would reduce the amount of cash otherwise available to us. However, following the closing of the BKV-BPP Power Joint Venture Transaction on January 30, 2026, any additional capital contributions to BKV-BPP Power must be approved by a majority of BKV-BPP Power's twelve member board of managers, nine of whom are appointed by us and three of whom are appointed by BPPUS. Similarly, any additional capital contributions to BKV-BPP Cotton Cove must receive the unanimous approval of the BKV-BPP Cotton Cove Joint Venture's six-member board of managers, four of whom are appointed by us and two of whom are appointed by BPPUS. During the three months ended March 31, 2026, BKV dCarbon Ventures and BPPUS made no contributions to BKV-BPP Cotton Cove.

On January 30, 2026, we completed the previously announced BKV-BPP Power Joint Venture Transaction for aggregate consideration consisting of $115.1 million in cash and 5,315,390 shares of our common stock. We funded the cash consideration with a combination of cash on hand and the net proceeds from the 2025 Equity Offering. For additional information, see *Note 2 - Acquisition.*

### Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that could give rise to material off-balance sheet arrangements. As of March 31, 2026, our material off-balance sheet arrangements and transactions included transportation commitments of $242.3 million and letters of credit of $15.0 million against the RBL Credit Agreement. For further information regarding these arrangements, see *Note 11 - Commitments and Contingencies* to our condensed consolidated financial statements and under “—*Liquidity and Capital Resources — RBL Credit Agreement.”*

### Critical Accounting Policies and Estimates

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

Other than the items described in this Quarterly Report on Form 10-Q, there have been no material changes to our critical accounting policies and estimates from those disclosed in our 2025 Annual Report on Form 10-K. Refer to *Note 1 - Business and Basis of Presentation.*

### Tariffs and Trading Relationships

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

### Emerging Growth Company Status

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

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

We may take advantage of these provisions until the last day of our fiscal year following the fifth anniversary of the date of our IPO. Such fifth anniversary will occur in 2029. However, if certain events occur prior to the end of such five-year period, including if (i) we become a “large accelerated filer,” which requires that the market value of our common equity held by non-affiliates be at least $700 million as of the end of the most recently completed second fiscal quarter, (ii) our gross revenues for any fiscal year equal or exceed $1.235 billion, or (iii) we issue more than $1.0 billion of non-convertible debt in any three-year period, then we will cease to be an emerging growth company prior to the end of such five-year period. We expect to lose our emerging growth company status as of December 31, 2026.

## Market risk

As filed, 10,030 characters.

There has been no material change in our market risks since December 31, 2025, as set forth in our 2025 Annual Report on Form 10-K.

### Commodity Price Risk and Hedging Activities

As of March 31, 2026, we did not enter into any trading market risk sensitive instruments, and our market risk sensitive instruments consisted entirely of non-trading instruments entered into for risk management purposes related to our natural gas and NGL production and power operations. Pricing is primarily driven by spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas, NGLs and power has historically been volatile and unpredictable, and we expect this volatility to continue in the future. The prices we receive for our production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

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

Our financial hedging activities are intended to support natural gas, NGL, and power prices at targeted levels and to manage our exposure to natural gas, NGL and power price fluctuations. These contracts may include commodity price swaps, whereby we will receive a fixed price and pay a variable market price to the contract counterparty, producer collars that set a floor and ceiling price for the hedged production, or basis differential swaps. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity. The derivative contracts outstanding as of March 31, 2026 consisted of commodity swaps, basis swaps, put and call options, producer collar agreements, fixed-price natural gas forwards, fixed price power forwards, and HRCOs, subject to master netting agreements with each individual counterparty.

These derivative contracts cover portions of our projected positions through 2029. Our commodity hedge position as of March 31, 2026 is summarized in *Note 6 - Derivative Instruments* to our condensed consolidated financial statements.

We may enter into single hedge transactions with settlements up to 48 months. The aggregate notional volumes of these executed hedge instruments may not exceed certain limits without board of director approval of our forecasted production volumes. During the three months ended March 31, 2026, a hypothetical increase or decrease of $0.10 per Mcf in NYMEX natural gas prices would have resulted in a $4.6 million decrease or increase in natural gas hedge revenues, respectively. During the three months ended March 31, 2026, a hypothetical increase or decrease of $1.00 per Bbl of NGL purity product price would have resulted in a $1.7 million decrease or increase in NGL hedge revenues, respectively.

Additionally, to reduce our exposure to fluctuations in the market price of power and natural gas, we enter into financially settled HRCOs, which are contracts for the financial purchase and sale of power based on a floating price of natural gas at a predetermined location using a predetermined conversion factor, or heat rate, required to convert natural gas into power. We are exposed to basis risk in our operations when our derivative contracts are financially settled while physical power is delivered at different pricing locations or under different terms. For example, when we enter into an HRCO, we hedge our power production at an agreed price, but physical power must be delivered into the market it serves, which may result in pricing differences. Accordingly, we are exposed to basis risk between the hub price specified in the HRCO and the price received for power sales. These HRCOs are entered into to economically hedge power price and fuel cost exposures rather than for trading purposes. We attempt to hedge basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the quantities that it requires. Our hedging activities do not provide us with protection for all of our basis risk and could result in economic losses and liabilities, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows. Additionally, by using derivative instruments to economically hedge exposure to changes in power prices, we could limit the benefit we would receive from increases in the power prices, which could have an adverse effect on our financial condition. Moreover, in the event we are not able to satisfy our obligations under the HRCO, we must purchase power at prevailing market prices to satisfy the HRCO. Likewise, increases in power pricing could limit the benefit we receive under HRCOs and may result in losses. Either such event could have a material adverse effect on our business, financial condition, results of operations, and cash flows. During the three months ended March 31, 2026, a hypothetical increase or decrease of $0.10 per MMBtu in Houston Ship Channel (HSC) natural gas daily prices would have resulted in a $0.4 million increase or decrease in power hedge revenues, respectively.

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

Mark-to-market adjustments of derivative instruments cause earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled or monetized prior to settlement. We expect continued volatility in the fair value of our derivative instruments. Our cash flows are only impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty. As of March 31, 2026, the estimated fair value of our commodity derivative instruments was a net asset of $90.0 million, comprised of current and noncurrent assets and current and noncurrent liabilities.

By removing price volatility from a portion of our expected production through December 2029, we have mitigated, but not eliminated, the potential negative effects of changing prices on our operating cash flows for those periods. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

### Counterparty Credit Risk

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

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

In addition, we utilize an unaffiliated third party to market all of our natural gas production to various purchasers, which consist of credit-worthy counterparties, including utilities, LNG producers, industrial consumers, major corporations, and super majors in our industry. We rely on the creditworthiness of such third party marketer, who collects directly from the purchasers and remits to us the total of all amounts collected on our behalf, less their fee for making such sales.

### Interest Rate Risks

As of March 31, 2026, our primary exposure to interest rate risk was due to the balances on our Temple I Loan Agreements and the Temple Credit Facilities and our RBL Credit Agreement, which have floating interest rates. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate 2030 Senior Notes, but can affect their fair values. For more information on our 2030 Senior Notes, see *Note 3 - Debt* and *Note 5 - Fair Value Measurements* to our condensed consolidated financial statements included in Item 1 of Part I of this report. As of March 31, 2026, there were $176.0 million, $459.4 million, and $100.0 million of outstanding borrowings under the Temple I Loan Agreements, the Temple Credit Facilities, and our RBL Credit Agreement, respectively. The average annualized interest rate incurred on our outstanding variable rate borrowings during the three months ended March 31, 2026, was approximately 7.79%. We estimate that a 1.0% increase in the applicable average interest rates during the three months ended March 31, 2026 would have resulted in an increase of $1.7 million in interest expense.

## Controls and procedures

As filed, 1,868 characters.

### Evaluation of Disclosure Controls and Procedures

As required by Rules 13a-15(b) and 15d-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the Commission's rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of March 31, 2026, our disclosure controls and procedures were effective.

Because of its inherent limitations, disclosure controls and procedures may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

### Changes in Internal Control over Financial Reporting

There were no changes in the Company's internal control over financial reporting during the quarter ended March 31, 2026 that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting.

## Risk factors

As filed, 340 characters.

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

Filed May 7, 2026.
Source: SEC EDGAR, the filing index for accession 0001628280-26-032241. Last ingested by Listed: Oct 26, 2026, 18:55 ET. No prices; not investment advice.