# BKV Corp: Form 10-Q for the period ended Mar 31, 2025

- Company: [BKV Corp](/companies/bkv.md) (CIK 1838406)
- Form: 10-Q
- Filed: 2025-05-09
- Accepted by EDGAR: May 9, 2025, 13:38 ET
- Period: 2025-03-31
- Accession: 0001628280-25-024150
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1838406/000162828025024150/bkv-20250331.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1838406/000162828025024150/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2025-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2025-01-01 to 2025-03-31 | $231.0m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Operating income | 3 months, 2025-01-01 to 2025-03-31 | −$93.7m | us-gaap:OperatingIncomeLoss |
| Income tax | 3 months, 2025-01-01 to 2025-03-31 | −$29.2m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2025-01-01 to 2025-03-31 | −$78.7m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2025-01-01 to 2025-03-31 | −$0.93 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2025-01-01 to 2025-03-31 | −$0.93 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2025-01-01 to 2025-03-31 | 84,706,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2025-01-01 to 2025-03-31 | $22.6m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Cash and equivalents | at 2025-03-31 | $15.3m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2025-03-31 | $105.1m | us-gaap:AssetsCurrent |
| Total assets | at 2025-03-31 | $2.25bn | us-gaap:Assets |
| Current liabilities | at 2025-03-31 | $253.6m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2025-03-31 | $769.2m | us-gaap:Liabilities |
| Long-term debt | at 2025-03-31 | $200.0m | us-gaap:LongTermDebt |
| Shareholders' equity | at 2025-03-31 | $1.48bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 44,572 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 report on Form 10-Q and our audited consolidated financial statements and related notes, including “Management's Discussion and Analysis of Financial Condition and Results of Operations” for the year ended December 31, 2024 included in our 2024 Annual Report on Form 10-K filed on March 31, 2025. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expectations. We disclaim any duty to publicly update any forward-looking statements except as otherwise required by applicable law.*

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

### Overview

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

### Recent Developments

- **Second Amendment to the RBL Credit Agreement.** On May 6, 2025, with the unanimous consent of our credit facility lenders, we entered into the Second Amendment to Credit Agreement, which amended the RBL Credit Agreement to, among other things, increase the borrowing base by $100.0 million and the elected commitment by $65.0 million. This amendment constituted the semiannual borrowing base redetermination. See “*Liquidity and Capital Resources — RBL Credit Agreement”* for additional information regarding the RBL Credit Agreement and the covenants contained therein.
- **Strategic CCUS Joint Venture**. As previously announced, on May 8, 2025, BKV dCarbon Ventures, together with C Squared Solutions, Inc., a subsidiary of the Energy Transition Fund managed by Copenhagen Infrastructure Partners, and, for the limited purposes specified therein, BKV Corporation, entered into the BKV-CIP JV Agreement forming the BKV-CIP Joint Venture for the purpose of developing CCUS projects. Also on May 8, 2025 and contemporaneously with their entry into the BKV-CIP JV Agreement, the parties thereto also entered into certain ancillary agreements related to the joint venture. BKV dCarbon Ventures has contributed to the BKV-CIP Joint Venture its ownership of the Barnett Zero and Eagle Ford Projects, and has committed to future contributions of certain CCUS projects, related assets, and/or cash, in exchange for a 51% interest therein. Subject to certain exceptions, BKV intends to develop its CCUS projects exclusively through the BKV-CIP Joint Venture. For more information regarding the terms of the BKV-CIP JV Agreement and ancillary agreements entered into by the Company and BKV dCarbon Ventures in connection therewith, please refer to the Company’s Current Report on Form 8-K filed on May 8, 2025.

### Operational and Financial Highlights

Below are some highlights of our operating and financial results for the three months ended March 31, 2025.

- Production of natural gas, NGLs, and oil was 68.5 Bcfe, or 761.1 MMcfe/d.
- Average realized product prices, excluding the impact of settled derivatives, were $3.15 per Mcfe.
- Production revenues were $216.1 million and midstream revenues were $2.8 million.
- Lease operating expense was $33.7 million, or $0.49 per Mcfe.
- Net loss was $(78.7) million.
- Net cash provided by operating activities was $22.6 million.
- Accrued capital expenditures were $58.0 million.

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

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

***Commodity Pricing.*** The natural gas and NGL industry is cyclical and commodity prices are highly volatile, and we expect these prices to continue to remain volatile in the near future. In order to manage our market exposure of price volatility, we utilize derivative contracts in connection with our natural gas operations to provide an economic hedge of our exposure to commodity price risks associated with anticipated future natural gas and NGL production. However, there are still market risks beyond our control that may impact our financial condition, results of operations, and cash flows.

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

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

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

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

### Production Volumes.

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

| Production Data | Three Months Ended March 31, 2025 | 2024 |
| --- | ---: | ---: |
| Natural gas (MMcf) | 54,121 | 59,644 |
| NGLs (MBbls) | 2,344 | 2,485 |
| Oil (MBbls) | 53 | 28 |
| Total volumes (MMcfe) | 68,503 | 74,722 |
| Average daily total volumes (MMcfe/d) | 761.1 | 821.1 |

### Sources of Revenues

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

### Realized Commodity Prices

NYMEX Henry Hub, for gas prices, and NYMEX WTI, for oil prices, are widely used benchmarks for the pricing of natural gas and oil in the United States. The price we receive for our natural gas and oil production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. As such, our revenues are sensitive to the price of the underlying commodity to which they relate. For further discussion on our derivative contracts, see *Note 5 - 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, 2025 | 2024 |
| --- | ---: | ---: |
| Average NYMEX Henry Hub price | $3.65 | $2.24 |
| Average natural gas realized price (excluding derivatives) | $3.10 | $1.62 |
| Average natural gas realized price (including derivatives) (1) | $2.86 | $2.00 |
| Differential | $(0.55) | $(0.62) |
| **NGLs ($/Bbl):** |  |  |
| Average NGL realized price (excluding derivatives) | $19.06 | $17.47 |
| Average NGL realized price (including derivatives) (1) | $16.89 | $17.53 |
| **Oil ($/Bbl):** |  |  |
| Average oil realized price | $65.28 | $69.07 |
| **High and low daily spot prices:** |  |  |
| **Oil ($/Bbl):** |  |  |
| High NYMEX WTI | $80.73 | $84.39 |
| Low NYMEX WTI | $66.31 | $70.62 |
| **Natural gas ($/Mcf):** |  |  |
| High NYMEX Henry Hub | $9.86 | $13.20 |
| Low NYMEX Henry Hub | $2.93 | $1.25 |

34

(1) Impact of derivatives prices excludes $13.3 million of gains on derivative contract terminations for the three months ended March 31, 2024.

### Results of Operations

### Comparison of the Three Months Ended March 31, 2025 and 2024

### Operating Revenues and Operating Income

Our operating revenues and other income from operations include the activity from the sale of natural gas, NGLs, and oil, midstream revenues, gains and losses on our derivative contracts, marketing revenues, Section 45Q tax credits, related party revenues, and other income from operations. The following table provides information on our revenues and other operating income for the periods presented:

*(in thousands, other than percentages)*

| Revenues | Three Months Ended March 31, 2025 | 2024 | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Natural gas revenues | $167,983 | $96,336 | $71,647 | 74% |
| NGL revenues | 44,683 | 43,417 | 1,266 | 3% |
| Oil revenues | 3,460 | 1,934 | 1,526 | 79% |
| Midstream revenues | 2,771 | 4,128 | (1,357) | (33)% |
| Derivative losses, net | (152,191) | (3,679) | (148,512) | \* |
| Marketing revenues | 6,485 | 4,921 | 1,564 | 32% |
| Section 45Q tax credits | 3,307 | 2,329 | 978 | 42% |
| Related party revenues | 426 | 1,101 | (675) | (61)% |
| Other | 1,896 | 1,427 | 469 | 33% |
| **Total revenues and other operating income** | $78,820 | $151,914 |  |  |
| \*Percentage not meaningful |  |  |  |  |

#### Natural Gas Revenues

Our natural gas revenues increased by approximately $71.6 million, or 74%, to $168.0 million for the three months ended March 31, 2025, from $96.3 million for the three months ended March 31, 2024. The impact of commodity price increases, excluding the effect of derivative settlements, provided an $80.6 million increase in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes). The increase was offset by lower production volumes during the three months ended March 31, 2025, primarily from the assets in the Barnett and from the sale of Chaffee and certain non-operated assets held by Chelsea in June 2024, which collectively accounted for an $8.9 million decrease in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).

#### NGL Revenues

Our NGL revenues increased by approximately $1.3 million, or 3%, to $44.7 million for the three months ended March 31, 2025, from $43.4 million for the three months ended March 31, 2024. The impact of commodity price increases, excluding the effect of derivative settlements, accounted for a $3.7 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 offset by lower production volumes during the three months ended March 31, 2025, which accounted for a $2.5 million decrease in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).

#### Oil Revenues

Our oil revenues increased by approximately $1.5 million, or 79%, to $3.5 million for the three months ended March 31, 2025, from $1.9 million for the three months ended March 31, 2024. The increase was primarily due to higher production volumes during the three months ended March 31, 2025, which accounted for a $1.7 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price). The increase was offset by the impact of commodity price decreases, excluding the effect of derivative settlements, which accounted for a $0.2 million decrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes).

#### Midstream Revenues

Our midstream revenues decreased by approximately $1.4 million, or 33%, to $2.8 million for the three months ended March 31, 2025, from $4.1 million for the three months ended March 31, 2024. This decrease was primarily due to the divestiture of Chaffee of $1.2 million as we sold our Repsol Midstream Interest in connection with this sale. The remainder of the decrease was due to changes in deal structures that reduced midstream transportation revenue while increasing third party gas sales.

#### Derivative Losses, Net

For the three months ended March 31, 2025, we had net realized and unrealized losses on derivative contracts of $152.2 million compared to net realized and unrealized losses on derivative contracts of $3.7 million for the three months ended March 31, 2024. The increased losses for the three months ended March 31, 2025 were from our open derivative positions, which were in more of an unrealized loss position of $134.0 million compared to the three months ended March 31, 2024 of $40.1 million. The increased losses on our derivative contracts were also due to realized losses of $18.2 million compared to realized gains of $36.5 million due to higher natural gas prices during this period compared to the same period in the prior year.

#### Marketing Revenues

Our marketing revenues increased by approximately $1.6 million, or 32% to $6.5 million for the three months ended March 31, 2025 from $4.9 million for the three months ended March 31, 2024. Our marketing revenues are derived under our marketing agreement with a third party pursuant to which we receive a fixed percentage of all net income realized in the resale of our and other producers’ hydrocarbons. The increase in marketing revenues during the three months ended March 31, 2025 was primarily due to a higher pricing environment compared to the same period in 2024.

#### Section 45Q Tax Credits

We generated $3.3 million in Section 45Q tax credits during the three months ended March 31, 2025 related to CO2 waste sequestration activities under our Barnett Zero Project compared to $2.3 million during the three months ended March 31, 2024. The increase period over period was due to more CO2 waste sequestered in 2025 compared to the prior period.

#### Related Party Revenues

Our related party revenues were $0.4 million for the three months ended March 31, 2025, compared to $1.1 million for the three months ended March 31, 2024. The decrease in related party revenues was due to a $0.7 million decrease in operating fee income with BKV-BPP Power, attributable to lower contracted rates.

#### Other Revenues

Other revenues includes the gain (loss) on the sale of assets and the sale of third-party natural gas. Other revenues were $1.9 million for the three months ended March 31, 2025 compared to $1.4 million for the three months ended March 31, 2024. The period-over-period increase was primarily due to an increase in third party gas sales of $2.5 million and an increase in the gain on sale of assets of $0.4 million, offset by the impairment on our asset held for sale of $2.4 million.

### Operating Expenses

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

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

| Operating expenses | Three Months Ended March 31, 2025 | 2024 | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Lease operating and workover | $35,055 | $34,468 | $587 | 2% |
| Taxes other than income | 10,222 | 11,365 | (1,143) | (10)% |
| Gathering and transportation costs | 55,793 | 59,066 | (3,273) | (6)% |
| Depreciation, depletion, amortization, and accretion | 39,970 | 52,166 | (12,196) | (23)% |
| General and administrative | 25,257 | 20,645 | 4,612 | 22% |
| Other | 6,226 | 8,567 | (2,341) | (27)% |
| Total operating expense | $172,523 | $186,277 |  |  |
| **Average costs per Mcfe** |  |  |  |  |
| Lease operating and workover | $0.51 | $0.46 | $0.05 | 11% |
| Taxes other than income | 0.15 | 0.15 | — | 0% |
| Gathering and transportation costs | 0.81 | 0.79 | 0.02 | 3% |
| Depreciation, depletion, amortization, and accretion | 0.58 | 0.70 | (0.12) | (17)% |
| General and administrative | 0.37 | 0.28 | 0.09 | 32% |
| Other | 0.09 | 0.11 | (0.02) | (18)% |
| Total | $2.51 | $2.49 |  |  |
| \*Percentage not meaningful |  |  |  |  |

#### 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, 2025 Amount | Per Mcfe | 2024 Amount | Per Mcfe | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Lease operating expenses | $33,675 | $0.49 | $32,463 | $0.43 | $1,212 | 4% |
| Workover expenses | 1,380 | 0.02 | 2,005 | 0.03 | (625) | (31)% |
| Total lease operating and workover expense | $35,055 | $0.51 | $34,468 | $0.46 | $587 | 2% |

Lease operating and workover expenses were $35.1 million, or $0.51 per Mcfe, for the three months ended March 31, 2025, which was an increase of approximately $0.6 million from $34.5 million, or $0.46 per Mcfe, for the three months ended March 31, 2024. The increase in lease operating expenses during the three months ended March 31, 2025 compared to the same period in 2024 was primarily driven by a credit received of $1.5 million for a water sharing agreement during the three months ended March 31, 2024. The increase was also due to increases in repairs and maintenance and timing of fees of $1.0 million and vehicle expense of $0.4 million during the three months ended March 31, 2025. This was offset by $1.4 million of less workover and operating activity due to winter storms and $1.0 million decreases in compression and water expenses due to well shut-ins during the three months ended March 31, 2025.

#### Taxes Other Than Income

Taxes other than income were $10.2 million, or $0.15 per Mcfe, for the three months ended March 31, 2025, which was a decrease of approximately $1.1 million, or 10%, from $11.4 million, or $0.15 per Mcfe, for the three months ended March 31, 2024. The decrease in taxes other than income during the three months ended March 31, 2025 compared to 2024 was due to decreases in ad valorem and property taxes associated with our operations in the Barnett and NEPA of $4.9 million and $0.2 million, respectively. This was offset by production taxes of $4.0 million in the Barnett. Certain ad valorem and production taxes are not applicable to our NEPA properties.

#### Gathering and Transportation

Gathering and transportation expenses were $55.8 million, or $0.81 per Mcfe, for the three months ended March 31, 2025, which was a decrease of approximately $3.3 million, or 6%, from $59.1 million, or $0.79 per Mcfe, for the three months ended March 31, 2024. This decrease was driven by decreased production in the Barnett of $3.2 million and NGL rate decreases of $0.4 million. This was offset by new contracts we entered into during 2024 where we started outsourcing gathering costs with our midstream business of $0.3 million.

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

Depreciation, depletion, amortization, and accretion was $40.0 million, or $0.58 per Mcfe, for the three months ended March 31, 2025, which was a decrease of approximately $12.2 million, or 23%, from $52.2 million, or $0.70 per Mcfe, for the three months ended March 31, 2024. The decrease in depreciation, depletion, amortization, and accretion during the three months ended March 31, 2025 compared to the three months ended March 31, 2024 was primarily due to a depletion rate adjustment in 2025.

#### General and Administrative

General and administrative expenses were $25.3 million, or $0.37 per Mcfe, for the three months ended March 31, 2025, which was an increase of approximately $4.6 million, or 22%, from $20.6 million, or $0.28 per Mcfe, for the three months ended March 31, 2024. The increase in general and administrative expenses during the three months ended March 31, 2025 compared to the three months ended March 31, 2024 was due to increases from Company-wide growth initiatives of $2.6 million in employee bonuses, contract labor, employee-based compensation, and employee expenses, and $2.0 million in consulting and information technology-related expenses.

#### Other Operating Expenses

Other operating expenses were $6.2 million, or $0.09 per Mcfe, for the three months ended March 31, 2025, which was a decrease of approximately $2.3 million, or 27%, from $8.6 million, or $0.11 per Mcfe, for the three months ended March 31, 2024. The decrease in other operating expenses during the three months ended March 31, 2025 compared to the same period in 2024 was primarily due to $5.0 million of accrued waste emissions costs established by the Inflation Reduction Act recognized during the three months ended March 31, 2024. This was offset by an increase of $1.6 million in third-party natural gas purchases due to increased volumes and increased natural gas prices during the three months ended March 31, 2025 compared to the same period in 2024.

#### Other Income (Expense)

*Gains on contingent consideration liabilities.* For the three months ended March 31, 2024, we recognized a gain on contingent consideration liabilities accruing as an earnout obligation under the purchase agreements executed in connection with the Devon Barnett Acquisition and the Exxon Barnett Acquisition. The gain on contingent consideration liabilities was $6.6 million for the three months ended March 31, 2024, and consisted of gains of $4.6 million and $2.0 million from the Devon Barnett Acquisition and the Exxon Barnett Acquisition, respectively. The contingent considerations under these purchase agreements expired in 2024.

*Losses from equity affiliate.* Losses from our equity affiliate were $9.6 million for the three months ended March 31, 2025, which was a change of $1.9 million, from $7.7 million compared to the same period in 2024. Losses from our equity affiliate are related to our investment in, and our proportionate share in the income or losses of the BKV-BPP Power Joint Venture.

*Interest expense.* Interest expense was $5.1 million for the three months ended March 31, 2025, which was a decrease of $11.0 million, from $16.1 million for the three months ended March 31, 2024. The decrease in interest expense during the three months ended March 31, 2025 was primarily due to lower interest rates incurred during the three months ended March 31, 2025 on our RBL Credit Facility, which we entered into on June 11, 2024, compared to the interest rates on our Term Loan Credit Agreement and Revolving Credit Facilities during the three months ended March 31, 2024.

*Interest expense, related party*. Interest expense from our related party borrowings with BNAC was $2.0 million for the three months ended March 31, 2024, which was paid down in June 2024.

*Interest income*. Interest income was $0.1 million for the three months ended March 31, 2025, which was a decrease of $1.5 million, compared to $1.6 million for the same period in 2024. The decrease was primarily due to the cessation of interest earned on restricted cash following the repayment of the Term Loan Agreement in June 2024, which had previously funded the debt service reserve account.

*Income tax benefit.* For the three months ended March 31, 2025, we had an income tax benefit of $29.2 million, which was an increase of $16.2 million, from a $13.0 million in income tax benefit for the three months ended March 31, 2024. During the three months ended March 31, 2025, the increase in income tax benefit was due to higher net losses and excess tax benefits relating to the vesting of restricted shares.

### Liquidity and Capital Resources

### Capital Commitments

Our primary needs for cash are to fund our upstream development, midstream, power, and CCUS activities, fund operations and capital expenditures, acquisitions, and asset retirement obligations, cover any debt interest or minimum volume commitment obligations, pay down debt, and return capital to stockholders. Our primary use of cash during the three months ended March 31, 2025 and 2024 was to fund the development of our natural gas properties.

During the three months ended March 31, 2025 and 2024, cash paid for capital expenditures was $57.4 million and $19.9 million, respectively. Our current estimated budget for accrued capital expenditures in 2025 is approximately $320 million to $380 million. Capital expenditures for our operated properties are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for natural gas and NGLs, the availability of equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs, and the level of participation by other interest owners. We will continue to monitor commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.

### Capital Resources

Historically, our primary sources of capital and liquidity have consisted of internally generated cash flows from operations, together with loans and capital contributions from our majority stockholder, BNAC. We also enter into financial instruments to reduce the impact of commodity price volatility and provide a level of certainty and stability around cash flows. We currently believe that our cash flows from operations, cash on hand, borrowings under our RBL Credit Agreement, and our commodity hedges in place will provide sufficient liquidity to fund our operations and our capital expenditures into 2025, excluding our CCUS business. We expect to fund up to 50% of our CCUS business from a variety of external sources, which may include joint ventures, 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, 2025 and 2024 (in thousands):

|  | Three Months Ended March 31, 2025 | 2024 |
| --- | ---: | ---: |
| Net cash provided by operating activities | $22,620 | $19,251 |
| Net cash used in investing activities | (56,008) | (19,884) |
| Net cash provided by (used in) financing activities | 33,819 | (1,590) |
| Net increase (decrease) in cash, cash equivalents, and restricted cash | $431 | $(2,223) |

***Cash flows provided by operating activities.*** Net cash provided by operating activities was $22.6 million for the three months ended March 31, 2025, compared to $19.3 million for the three months ended March 31, 2024. Net cash provided by operating activities increased during the three months ended March 31, 2025 compared to the three months ended March 31, 2024 due to a $24.7 million increase in income from operations (excluding net unrealized gains (losses), depreciation, depletion, amortization, and accretion, equity-based compensation, and impairment of asset held for sale), resulting from higher natural gas prices compared to 2024, and a $20.4 million increase in working capital. These increases were offset by cash received in January 2024 for the sale of call options of $23.5 million, cash paid in February 2025 for the purchase of put options of $16.2 million, a decrease in interest income of $1.5 million, and a $0.5 million increase in cash paid for interest.

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

***Cash flows used in investing activities.*** Net cash used in investing activities was $56.0 million for the three months ended March 31, 2025, compared to net cash used in investing activities of $19.9 million for the three months ended March 31, 2024. The change was due to the increase of $39.7 million of capital expenditures (excluding CCUS activities) for the three months ended March 31, 2025 compared to the three months ended March 31, 2024. This was offset by the decrease of $2.2 million of expenditures on CCUS activities over the same period and additional cash proceeds on the sale of assets of $1.3 million.

The following table presents our capital expenditures (excluding leasehold costs and acquisitions) on an accrual basis for the three months ended March 31, 2025 and 2024 and reconciles to cash flows used for capital expenditures in the condensed consolidated statements of cash flows.

|  | Three Months Ended March 31, 2025 | 2024 |
| --- | ---: | ---: |
| Total use of cash and cash equivalents for capital expenditures | $(57,374) | $(19,861) |
| Decrease (increase) in accrued capital expenditures | (628) | 1,833 |
| Capital expenditures (accrued) | $(58,002) | $(18,028) |

***Cash flows provided by (used in) financing activities.*** Net cash provided by financing activities was $33.8 million for the three months ended March 31, 2025, which consisted of net borrowings on debt of $35.0 million, and was offset by payments of $1.2 million for taxes related to net share settlement of restricted stock units. For the three months ended March 31, 2024, net cash used in financing activities was $1.6 million, which was due to net payments on debt of $1.0 million and payments of deferred offering costs of $0.6 million.

### Working Capital

As of March 31, 2025, we had cash and cash equivalents of $15.3 million, compared to $14.9 million of cash and cash equivalents as of December 31, 2024. Our net working capital deficit was $148.5 million as of March 31, 2025, compared to a deficit of $71.6 million as of December 31, 2024.

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

### RBL Credit Agreement

On June 11, 2024, BKV Corporation, as 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, 2025, the RBL Credit Agreement had a borrowing base of $750.0 million, an elected commitment of $600.0 million, and the ability to issue up to $40.0 million in letters of credit. The loans may be borrowed, repaid, and reborrowed during the term of the RBL Credit Agreement. The RBL Credit Agreement will mature on June 12, 2028. The obligations under the RBL Credit Agreement are secured and guaranteed on a secured basis by BKV Corporation, 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. On May 6, 2025, with the unanimous consent of our credit facility lenders, we amended the RBL Credit Agreement to, among other things, increase the borrowing base by $100.0 million and the elected commitment by $65.0 million. This amendment constituted the semiannual borrowing base redetermination. As of May 9, 2025, $230.0 million of revolving borrowings and $14.1 million of letters of credit were outstanding under the RBL Credit Agreement, leaving $420.9 million of available capacity thereunder for future borrowings and letters of credit.

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

Beginning with the fiscal quarter ending September 30, 2024, the RBL Credit Agreement requires BKV Upstream Midstream and its restricted subsidiaries to always hedge not less than 50% of projected production from their proved developed producing reserves for the subsequent 24 calendar month period immediately following such required delivery date.

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

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

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

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 the assets of BKV Corporation, BKV Upstream Midstream and its restricted subsidiaries that are guarantors, and upon an event of default the agent under the RBL Credit Agreement could commence foreclosure proceedings.

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

Under the terms of the BKV-BPP Power LLC Agreement and BKV-BPP Cotton Cove LLC Agreement, we do not have the ability to unilaterally cause BKV-BPP Power or BKV-BPP Cotton Cove to make distributions. During the three months ended March 31, 2025 and 2024, no distributions were made by BKV-BPP Power or BKV-BPP Cotton Cove. In addition, we may be required to make additional capital contributions to one or both joint ventures to fund items approved in their respective annual budgets or other matters approved by their respective boards. Such additional capital contributions, which are not subject to any limit on the potential amount required, would reduce the amount of cash otherwise available to us. However, any additional capital contributions to BKV-BPP Power must be approved by a majority of BKV-BPP Power's ten member board of managers, five of whom are appointed by us and five of whom are appointed by BPPUS. Similarly, any additional capital contributions to BKV-BPP Cotton Cove must receive the unanimous approval of BKV-BPP Cotton Cove, LLC's six member board of managers, four of whom are appointed by us and two of whom are appointed by BPPUS.

### 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, 2025, our material off-balance sheet arrangements and transactions included volume commitments of $304.7 million and letters of credit of $14.1 million against the RBL Credit Agreement. For further information regarding these arrangements, see “*Note 10 - Commitments and Contingencies”* to our condensed consolidated financial statements and under “—*Loan Agreements and Credit Facilities — 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. For more information, see *Note 1 - Business and Basis of Presentation* to our condensed consolidated financial statements. As of March 31, 2025, there have been no material changes to our critical accounting policies and estimates as described in our 2024 Annual Report on Form 10-K for the year ended December 31, 2024.

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

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

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

## Market risk

As filed, 9,692 characters.

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

### Commodity Price Risk and Hedging Activities

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

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

Our financial hedging activities are intended to support natural gas and NGL prices at targeted levels and to manage our exposure to natural gas and NGL price fluctuations. These contracts may include commodity price swaps, whereby we will receive a fixed price and pay a variable market price to the contract counterparty, producer collars that set a floor and ceiling price for the hedged production, or basis differential swaps. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity. The derivative contracts outstanding as of March 31, 2025 consisted of commodity price swaps, basis differential swaps, put and call options, and producer collar agreements, subject to master netting agreements with each individual counterparty.

These derivative contracts cover portions of our projected positions through 2027. Our commodity hedge position as of March 31, 2025 is summarized in “*Note 5 - Derivative Instruments”* to our condensed consolidated financial statements.

We may enter into single hedge transactions with settlements up to 48 months. The aggregation of these executed hedge instruments may not exceed 60% without board of director approval of our forecasted production volumes for the current year and subsequent year, and for up to 40% and 25% of our forecasted production volumes in each of the respective subsequent years thereafter. During the three months ended March 31, 2025 and 2024, a hypothetical increase or decrease of $0.10 per Mcf in NYMEX would have resulted in a $2.7 million and $1.5 million decrease or increase in natural gas hedge revenues, respectively, and a hypothetical increase or decrease of $1.00 per Bbl of NGL purity product price would have resulted in a $1.6 million and $1.1 million decrease or increase in NGL hedge revenues, respectively.

Additionally, to reduce its exposure to fluctuations in the market price of electricity and natural gas, BKV-BPP Power enters into financially settled HRCOs, which are contracts for the financial purchase and sale of power based on a floating price of natural gas at a predetermined location using a predetermined conversion factor, or heat rate, required to turn the fuel input into electricity. BKV-BPP Power is exposed to basis risk in its operations when its derivative contracts settle financially and it delivers physical electricity on different terms. For example, if BKV-BPP Power enters into an HRCO, it hedges its electricity production based on an agreed price for that electricity, but physical electricity must be delivered to delivery points in the market it serves. BKV-BPP Power is exposed to basis risk between the hub price specified in the HRCO and the price that it receives for the sales of physical electricity. BKV-BPP Power attempts to hedge basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the quantities that it requires. BKV-BPP Power’s hedging activities do not provide it with protection for all of its basis risk and could result in economic losses and liabilities, which could have a material adverse effect on BKV-BPP Power, and thus on our business, financial condition, results of operations, and cash flows. Additionally, by using derivative instruments to economically hedge exposure to changes in power prices, we could limit the benefit we would receive from increases in the power prices, which could have an adverse effect on our financial condition. Moreover, in the event BKV-BPP Power is not able to satisfy its obligations under the HRCO, it must purchase power at prevailing market prices to satisfy the HRCO. Likewise, increases in power pricing could limit the benefit we receive under HRCOs and may result in losses. Either such event could have a material adverse effect on BKV-BPP Power, and thus on our business, financial condition, results of operations, and cash flows.

All derivative instruments, other than those that meet the normal purchase and normal sale scope exception, are recorded at fair market value in accordance with GAAP and are included in our condensed consolidated balance sheets as assets or liabilities. The fair values of our derivative instruments are adjusted for non-performance risk. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment; therefore, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our condensed consolidated statements of operations. We present total gains or losses on commodity derivatives (for both settled derivatives and derivative positions which remain open) within operating revenues as derivative 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, 2025, the estimated fair value of our commodity derivative instruments was a net liability of $185.4 million, comprised of current and noncurrent assets and current and noncurrent liabilities. As of December 31, 2024, the estimated fair value of our commodity derivative instruments was a net liability of $67.6 million, comprised of current and noncurrent liabilities.

By removing price volatility from a portion of our expected production through December 2027, we have mitigated, but not eliminated, the potential negative effects of changing prices on our operating cash flows for those periods. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

### Counterparty Credit Risk

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

We enter into International Swap Dealers Association (“ISDA”) Master Agreements with each of our derivative counterparties prior to executing derivative contracts. The terms of the ISDA Master Agreements provide, among other things, the

Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either us or counterparty to a derivative contract.

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

### Interest Rate Risks

As of March 31, 2025, our primary exposure to interest rate risk resulted from our $200.0 million of outstanding borrowings on our RBL Credit Agreement, which has a floating interest rate. As of March 31, 2024, our primary exposure to interest rate risk resulted from our outstanding related party borrowings with BNAC, the Term Loan Credit Agreement, the Revolving Credit Agreement, and our loan agreement previously entered into in March 2022 with Standard Chartered Bank (the “SCB Credit Facility”), all of which had floating interest rates. As of March 31, 2024, we had $75.0 million of outstanding borrowings with BNAC, $456.0 million of outstanding borrowings under the Term Loan Credit Agreement, $35.0 million of outstanding borrowings under the SCB Credit Facility, and $91.0 million of outstanding borrowings under the Revolving Credit Agreement. The average annualized interest rate incurred on our outstanding borrowings during the three months ended March 31, 2025 and 2024 was approximately 7.4% and 9.4%, respectively. We estimate that a 1.0% increase in the applicable average interest rates during the three months ended March 31, 2025 and 2024 would have resulted in increases of $0.5 million and $1.7 million in interest expense, respectively.

## Controls and procedures

As filed, 5,112 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 due to the presence of our material weakness described below, as of March 31, 2025, our disclosure controls and procedures were not effective.

### Material Weakness in Internal Control over Financial Reporting

As of March 31, 2025, a material weakness continued to exist in our internal control over financial reporting. A “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

We did not design and maintain effective controls related to the accounting for income taxes, which were not designed at a sufficient level of precision or rigor to prepare and review the tax rate reconciliation, return to provision, income tax provision, related income tax assets and liabilities, and disclosures in the consolidated financial statements. This material weakness resulted in (i) audit adjustments to income tax benefit, income taxes payable to related party, and deferred tax assets and liabilities in the consolidated financial statements as of December 31, 2021 and for the year then ended, (ii) an immaterial audit adjustment to the supplemental cash flow information for cash payments for income taxes and a reclassification between oil and gas production and other taxes payable and other accrued liabilities within *Note 11 - Accounts Payable and Accrued Liabilities* to our consolidated financial statements as of and for the year ended December 31, 2023, (iii) audit adjustments to deferred tax liabilities and additional paid-in capital as of December 31, 2024, and (iv), the revision of our previously issued financial statements for the interim and annual periods included in the years ended December 31, 2021, 2022, and 2023, and interim periods included in the year ended December 31, 2024. This material weakness could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.

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

### Remediation Efforts to Address the Material Weakness

We have taken steps towards remediating this material weakness primarily by designing and implementing additional internal controls, including those related to the preparation and review of the income tax rate reconciliation, return to provision, income tax provision, related income tax assets and liabilities, and income tax disclosures. Although we believe we are addressing the internal control deficiencies that led to this material weakness, the measures we have taken, and plan to take, may not be effective.

### Inherent Limitations on Effectiveness of Controls and Procedures

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

### Changes in Internal Control over Financial Reporting

There were no changes in the Company's internal control over financial reporting during the quarter ended March 31, 2025 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 2024 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 2024 Annual Report on Form 10-K.

Filed May 9, 2025.
Source: SEC EDGAR, the filing index for accession 0001628280-25-024150. Last ingested by Listed: Oct 26, 2026, 18:55 ET. No prices; not investment advice.