# BKV Corp: Form 10-Q for the period ended Sep 30, 2024

- Company: [BKV Corp](/companies/bkv.md) (CIK 1838406)
- Form: 10-Q
- Filed: 2024-11-13
- Accepted by EDGAR: Nov 13, 2024, 14:57 ET
- Period: 2024-09-30
- Accession: 0001628280-24-047546
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1838406/000162828024047546/bkv-20240930.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1838406/000162828024047546/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2024-09-30.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2024-07-01 to 2024-09-30 | $137.8m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Revenue | 9 months, 2024-01-01 to 2024-09-30 | $430.3m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Operating income | 3 months, 2024-07-01 to 2024-09-30 | −$21.0m | us-gaap:OperatingIncomeLoss |
| Operating income | 9 months, 2024-01-01 to 2024-09-30 | −$98.5m | us-gaap:OperatingIncomeLoss |
| Income tax | 3 months, 2024-07-01 to 2024-09-30 | $11.3m | us-gaap:IncomeTaxExpenseBenefit |
| Income tax | 9 months, 2024-01-01 to 2024-09-30 | −$30.1m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 3 months, 2024-07-01 to 2024-09-30 | $12.9m | us-gaap:NetIncomeLoss |
| Net income | 9 months, 2024-01-01 to 2024-09-30 | −$85.4m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2024-07-01 to 2024-09-30 | $0.18 | us-gaap:EarningsPerShareDiluted |
| Diluted EPS | 9 months, 2024-01-01 to 2024-09-30 | −$1.28 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2024-07-01 to 2024-09-30 | $0.19 | us-gaap:EarningsPerShareBasic |
| Basic EPS | 9 months, 2024-01-01 to 2024-09-30 | −$1.28 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2024-07-01 to 2024-09-30 | 70,637,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Diluted shares (weighted) | 9 months, 2024-01-01 to 2024-09-30 | 66,891,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 9 months, 2024-01-01 to 2024-09-30 | $74.8m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Share repurchases | 9 months, 2024-01-01 to 2024-09-30 | $2.1m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2024-09-30 | $31.3m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2024-09-30 | $125.7m | us-gaap:AssetsCurrent |
| Total assets | at 2024-09-30 | $2.27bn | us-gaap:Assets |
| Current liabilities | at 2024-09-30 | $139.0m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2024-09-30 | $668.3m | us-gaap:Liabilities |
| Long-term debt | at 2024-09-30 | $190.0m | us-gaap:LongTermDebt |
| Shareholders' equity | at 2024-09-30 | $1.60bn | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 65,924 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 Part I, Item 1, 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, 2023 included in our final prospectus dated September 25, 2024 (the “Prospectus”) filed with the Securities and Exchange Commission (“SEC”). 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 Part I, Item 1 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; natural gas gathering, processing and transportation (our “natural gas midstream business”); power generation; and carbon capture, utilization and sequestration (“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 CCUS project 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

### Initial Public Offering

- **Initial Public Offering.** On September 27, 2024, we completed our initial public offering (the “IPO”) of 15,000,000 shares of common stock at a price to the public of $18.00 per share. After underwriting discounts and commissions of $16.2 million, we received net proceeds from the offering of $253.8 million. We also granted the IPO underwriters a 30-day option to purchase up to 2,250,000 additional shares of common stock on the same terms. The underwriters partially exercised the option and, on October 28, 2024, purchased 701,003 shares of common stock, resulting in additional net proceeds of $11.9 million, after deducting underwriting discounts and commissions of $0.8 million.

### Dispositions

- **Sales of Chaffee and Chelsea Assets**. On June 14, 2024, we sold our wholly-owned subsidiary, BKV Chaffee Corners, LLC (“Chaffee”), which owned a non-operated interest in approximately 9,800 net acres and 116 gross (24.2 net) wells and 122 Bcfe of proved reserves in the Marcellus Shale in the Appalachian Basin of Northeast Pennsylvania (“NEPA”), as well as our interest in the Repsol Oil & Gas operated midstream system, for a purchase price of $106.7 million. On June 28, 2024, our wholly-owned subsidiary, BKV Chelsea, LLC (“Chelsea”), sold certain of its non-operated upstream assets, including its interest in approximately 6,800 net acres and 214 gross (15.4 net) wells and 35 Bcfe of proved reserves in NEPA for a purchase price of $25.0 million.

### Credit Facilities

- **Refinancing.** On June 11, 2024, the amounts outstanding under the Term Loan Credit Agreement, the Revolving Credit Agreement and the SCB Credit Facility (each as defined in the notes to our condensed consolidated financial statements included in Part I Item 1 of this report) were paid off with proceeds from the loans under the RBL

Credit Agreement (as defined below) and cash on hand. The Term Loan Credit Agreement, the Revolving Credit Agreement, and the SCB Credit Facility were terminated concurrently with the repayment of the remaining amounts owed thereunder. See “*Liquidity and Capital Resources — Loan Agreements and Credit Facilities”* for additional information regarding our loan agreements and credit facilities.

- **RBL Credit Agreement.** On June 11, 2024, BKV Corporation and BKV Upstream Midstream, LLC (“BKV Upstream Midstream”) entered into a reserve-based lending agreement (the “RBL Credit Agreement”), with Citibank, N.A. as administrative agent and the financial institutions party thereto, and with BKV Corporation as the guarantor and BKV Upstream Midstream as the borrower. The RBL Credit Agreement has a maximum credit commitment of $1.5 billion. As of September 30, 2024, the RBL Credit Agreement had an outstanding balance of $190.0 million, a borrowing base of $800.0 million, and an elected commitment of $600.0 million. The RBL Credit Agreement includes a $50.0 million sublimit for the issuance of letters of credit. See “*Liquidity and Capital Resources — Loan Agreements and Credit Facilities”* for additional information regarding the RBL Credit Agreement and the covenants contained therein.

### Operational and Financial Highlights

Below are some highlights of our operating and financial results for the three and nine months ended September 30, 2024.

- Production of natural gas, NGLs, and oil was 70.2 Bcfe and 217.2 Bcfe for the three and nine months ended September 30, 2024, respectively.
- Average realized product prices, excluding the impact of settled derivatives, were $1.81 per Mcfe and $1.82 per Mcfe for the three and nine months ended September 30, 2024, respectively.
- For the three and nine months ended September 30, 2024, production revenues were $127.0 million and $394.5 million, respectively, and midstream revenues were $2.7 million and $10.2 million, respectively.
- Lease operating expense was $32.8 million, or $0.47 per Mcfe and $98.2 million, or $0.45 per Mcfe for the three and nine months ended September 30, 2024, respectively.
- Net income (loss) for the three and nine months ended September 30, 2024 was $12.9 million and $(85.4) million, respectively.
- Net cash provided by operating activities for the nine months ended September 30, 2024 was $74.8 million.
- Accrued capital expenditures were $57.3 million for the nine months ended September 30, 2024.

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

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

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

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

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

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

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

### Production Volumes.

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

| Production Data | Three Months Ended September 30, 2024 | 2023 | Nine Months Ended September 30, 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Natural gas (MMcf) | 55,456 | 61,792 | 172,213 | 188,690 |
| NGLs (MBbls) | 2,428 | 2,625 | 7,415 | 7,905 |
| Oil (MBbls) | 23 | 29 | 75 | 92 |
| Total volumes (MMcfe) | 70,162 | 77,716 | 217,153 | 236,672 |
| Average daily total volumes (MMcfe/d) | 762.6 | 844.7 | 792.5 | 866.9 |

### Sources of Revenues

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

### Realized Commodity Prices

NYMEX Henry Hub, for gas prices, and NYMEX WTI, for oil prices, are widely used benchmarks for the pricing of natural gas and oil in the United States. The price we receive for our natural gas and oil production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. As such, our revenues are sensitive to the price of the underlying commodity to which they relate. For further discussion on our derivative contracts, see

*Note 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 September 30, 2024 | 2023 | Nine Months Ended September 30, 2024 | 2023 |
| --- | ---: | ---: | ---: | ---: |
| Average NYMEX Henry Hub price | $2.16 | $2.55 | $2.10 | $2.69 |
| Average natural gas realized price (excluding derivatives) | $1.58 | $1.97 | $1.55 | $2.01 |
| Average natural gas realized price (including derivatives) (1) | $2.21 | $2.00 | $2.06 | $2.19 |
| Differential to NYMEX Henry Hub | $(0.58) | $(0.58) | $(0.55) | $(0.68) |
| **NGLs (Bbl):** |  |  |  |  |
| Average NYMEX WTI price | $76.43 | $82.25 | $78.58 | $77.27 |
| Average NGL realized price (excluding derivatives) | $15.44 | $19.14 | $16.47 | $17.93 |
| Average NGL realized price (including derivatives) (1) | $17.03 | $18.72 | $17.16 | $17.56 |
| Differential to NYMEX WTI | $(60.99) | $(63.11) | $(62.11) | $(59.34) |
| **Oil (Bbl):** |  |  |  |  |
| Average NYMEX WTI price | $76.43 | $82.25 | $78.58 | $77.27 |
| Average oil realized price (excluding derivatives) | $68.91 | $74.52 | $70.92 | $71.27 |
| Average oil realized price (including derivatives) (1) | $68.91 | $74.52 | $70.92 | $71.27 |
| Differential to NYMEX WTI | $(7.52) | $(7.73) | $(7.66) | $(6.00) |
| **High and low NYMEX prices:** |  |  |  |  |
| **Oil (Bbl):** |  |  |  |  |
| High | $85.19 | $93.67 | $87.69 | $93.67 |
| Low | $66.73 | $69.71 | $66.73 | $66.61 |
| **Natural gas (Mcf):** |  |  |  |  |
| High | $2.65 | $2.92 | $13.20 | $3.78 |
| Low | $1.81 | $2.42 | $1.25 | $1.74 |

(1) Impact of derivatives prices excludes $13.3 million of gains for the nine months ended September 30, 2024 and $39.1 million of gains on derivative contract terminations for both the three and nine months ended September 30, 2023.

### Results of Operations

### Comparison of the Three Months Ended September 30, 2024 and 2023

### Operating revenues

Our operating revenues include revenues from the sale of natural gas, NGLs, and oil, midstream revenues, gains and losses on our derivative contracts, marketing revenues, and other revenues. The following table provides information on our revenues for the periods presented:

*(in thousands, other than percentages)*

| Revenues | Three Months Ended September 30, 2024 | 2023 | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Natural gas revenues | $87,878 | $122,012 | $(34,134) | (28)% |
| NGL revenues | 37,489 | 50,241 | (12,752) | (25)% |
| Oil revenues | 1,585 | 2,161 | (576) | (27)% |
| Midstream revenues | 2,662 | 3,799 | (1,137) | (30)% |
| Derivative gains, net | 35,308 | 9,327 | 25,981 | \* |
| Marketing revenues | 1,738 | 1,936 | (198) | (10)% |
| Related party and other | 6,427 | 1,891 | 4,536 | \* |
| **Total revenues and other operating income** | $173,087 | $191,367 |  |  |
| \*Percentage not meaningful |  |  |  |  |

#### Natural gas revenues

Our natural gas revenues decreased by approximately $34.1 million, or 28% to $87.9 million for the three months ended September 30, 2024, from $122.0 million for the three months ended September 30, 2023. The impact of commodity price decreases, excluding the effect of derivative settlements, provided a $21.6 million decrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes). The decrease was also due to lower production volumes, primarily due to the sales of Chaffee and the non-operated assets held by Chelsea, which, during the three months ended September 30, 2024 accounted for a $12.5 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 decreased by approximately $12.8 million, or 25% to $37.5 million for the three months ended September 30, 2024, from $50.2 million for the three months ended September 30, 2023. The impact of commodity price decreases, excluding the effect of derivative settlements, accounted for a $9.0 million decrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes). The decrease was also due to lower production volumes during the three months ended September 30, 2024, which accounted for a $3.8 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 decreased by approximately $0.6 million, or 27% to $1.6 million for the three months ended September 30, 2024, from $2.2 million for the three months ended September 30, 2023. The decrease was primarily due to lower production volumes during the three months ended September 30, 2024, which accounted for a $0.5 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 also driven by a decrease in commodity prices, excluding the effect of derivative settlements, which accounted for a $0.1 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 $1.1 million, or 30%, to $2.7 million for the three months ended September 30, 2024, from $3.8 million for the three months ended September 30, 2023. This decrease was primarily due to the divestiture of Chaffee as we sold our approximate 29.4% non-operated interest in a midstream system operated by Repsol Oil and Gas (our “Repsol Midstream Interest”) in connection with this sale.

#### Derivative gains, net

For the three months ended September 30, 2024, we had net realized and unrealized gains on derivative contracts of $35.3 million compared to net realized and unrealized gains on derivative contracts of $9.3 million for the three months ended September 30, 2023. The increased gains for the three months ended September 30, 2024 were from our settled derivatives, which were in a gain position of $38.3 million due to lower natural gas prices during this period compared to the same period in the prior year. This was offset by the fair value change in our open derivative positions, which were in more of an unrealized loss position of $3.0 million for the three months ended September 30, 2024 compared to the three months ended September 30, 2023.

#### Marketing revenues

Our marketing revenues decreased by approximately $0.2 million, or 10% to $1.7 million for the three months ended September 30, 2024 from $1.9 million for the three months ended September 30, 2023. Our marketing revenues are derived under our marketing agreement with a third party pursuant to which we receive a fixed percentage of all net income realized in the resale of our and other producers’ hydrocarbons.

#### Related party and other

We generate a portion of our revenues from a management fee from our 50% ownership of BKV-BPP Power, LLC (the “Power Joint Venture”), the sale of third-party natural gas, and CCUS revenues generated from Internal Revenue Code (“IRC”) Section 45Q tax credits. Our related party and other revenues were $6.4 million for the three months ended September 30, 2024 compared to $1.9 million for the three months ended September 30, 2023. Other revenues increased during the three months ended September 30, 2024 compared to the three months ended September 30, 2023 primarily due to IRC Section 45Q tax credits of $4.3 million from the injection of CO2 in our Barnett Zero well, which started in the fourth quarter of 2023, as well as an increase in operating fee income of $0.9 million due to contracted rate increases. This was offset by a decrease in management fees of $0.7 million from the Power Joint Venture.

### 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 September 30, 2024 | 2023 | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Lease operating and workover | $33,588 | $33,470 | $118 | 0% |
| Taxes other than income | 10,688 | 17,725 | (7,037) | (40)% |
| Gathering and transportation costs | 54,705 | 62,488 | (7,783) | (12)% |
| Depreciation, depletion, amortization, and accretion | 57,366 | 52,269 | 5,097 | 10% |
| General and administrative | 33,602 | 28,477 | 5,125 | 18% |
| Other | 4,126 | 2,233 | 1,893 | 85% |
| Total operating expense | $194,075 | $196,662 |  |  |
| **Average costs per Mcfe** |  |  |  |  |
| Lease operating and workover | $0.48 | $0.44 | $0.04 | 9% |
| Taxes other than income | 0.15 | 0.23 | (0.08) | (35)% |
| Gathering and transportation costs | 0.78 | 0.80 | (0.02) | (3)% |
| Depreciation, depletion, amortization, and accretion | 0.82 | 0.67 | 0.15 | 22% |
| General and administrative | 0.48 | 0.37 | 0.11 | 30% |
| Other | 0.06 | 0.03 | 0.03 | 100% |
| Total | $2.77 | $2.54 |  |  |

#### 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 September 30, 2024 Amount | Per Mcfe | 2023 Amount | Per Mcfe | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Lease operating expenses | $32,800 | $0.47 | $32,279 | $0.42 | $521 | 2% |
| Workover expenses | 788 | 0.01 | 1,191 | 0.02 | (403) | (34)% |
| Total lease operating and workover expense | $33,588 | $0.48 | $33,470 | $0.44 | $118 | 0% |

Lease operating and workover expenses were $33.6 million, or $0.48 per Mcfe, for the three months ended September 30, 2024, which was an increase of approximately $0.1 million from $33.5 million, or $0.44 per Mcfe, for the three months ended September 30, 2023. The slight increase in lease operating expenses during the three months ended September 30, 2024 compared to the same period in 2023 was due to a slightly higher pricing environment, offset by a decrease in workover expenses due to the reclassification to capital projects of $0.4 million.

#### Taxes other than income

Taxes other than income were $10.7 million, or $0.15 per Mcfe, for the three months ended September 30, 2024, which was a decrease of approximately $7.0 million, or 40%, from $17.7 million, or $0.23 per Mcfe, for the three months ended September 30, 2023. The decrease in taxes other than income during the three months ended September 30, 2024 compared to 2023 was due to decreases in ad valorem and property taxes, and natural gas and NGL production taxes, both associated with our operations in the Barnett of $5.1 million and $1.9 million, respectively. Certain ad valorem and production taxes are not applicable to our NEPA properties.

#### Gathering and transportation

Gathering and transportation expenses were $54.7 million, or $0.78 per Mcfe, for the three months ended September 30, 2024, which was a decrease of approximately $7.8 million, or 12%, from $62.5 million, or $0.80 per Mcfe, for the three months ended September 30, 2023. This decrease was driven by decreased production in the Barnett of $4.4 million and natural gas and NGL rate decreases of $3.5 million and $1.8 million, respectively. This was offset by new contracts we entered into during 2024 where we started incurring gathering costs to commercially sequester the CO2 waste utilizing our Barnett Zero Project of $1.4 million and outsourcing gathering costs with our midstream business of $0.4 million.

#### Depreciation, depletion, amortization, and accretion

Depreciation, depletion, amortization, and accretion was $57.4 million, or $0.82 per Mcfe, for the three months ended September 30, 2024, which was an increase of approximately $5.1 million, or 10%, from $52.3 million, or $0.67 per Mcfe, for the three months ended September 30, 2023. The increase in depreciation, depletion, amortization, and accretion during the three months ended September 30, 2024 compared to the three months ended September 30, 2023 was primarily due to lower estimated proved reserves resulting from lower natural gas prices used in determination of proved reserves and from the divestiture of Chelsea and Chaffee in June 2024.

#### General and administrative

General and administrative expenses were $33.6 million, or $0.48 per Mcfe, for the three months ended September 30, 2024, which was an increase of approximately $5.1 million, or 18%, from $28.5 million, or $0.37 per Mcfe, for the three months ended September 30, 2023. The increase in general and administrative expenses during the three months ended September 30, 2024 compared to the three months ended September 30, 2023 was due to a net increase of $4.3 million in equity-based compensation and an increase in IPO related expenses of $1.9 million and IT expenses of $0.9 million. Also during the three months ended September 30, 2024, we entered into a third party management agreement to expand our CCUS business and recognized $0.4 million. This was offset by $2.0 million of management fees paid to Verde CO2 during the three months ended September 30, 2023. The contract with Verde CO2 terminated in November 2023.

#### Other operating expenses

Other operating expenses were $4.1 million, or $0.06 per Mcfe, for the three months ended September 30, 2024, which was an increase of approximately $1.9 million, or 85%, from $2.2 million, or $0.03 per Mcfe, for the three months ended September 30, 2023. The increase in other operating expenses during the three months ended September 30, 2024 compared to the same period in 2023 was primarily due to increased legal contingencies and costs associated with potential financing and investment activities totaling $1.4 million, emission certificates of $0.7 million, and $0.4 million in CCUS operating expenses for CO2 purchases and fuel, offset by an inventory write-off of $0.8 million during the three months ended September 30, 2023.

#### Other Income (Expense)

*Gains on contingent consideration liabilities.* 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 $3.9 million for the three months ended September 30, 2024, which was an increase of approximately $2.7 million from the $1.2 million gain for the three months ended September 30, 2023. The $3.9 million gain compared to the $1.2 million gain was primarily attributable to the current period's gain on contingent consideration liabilities with the Devon Barnett Acquisition of $3.9 million compared to the prior period’s gain of $0.5 million, as well as the current period's negligible gain on contingent consideration liabilities with the Exxon Barnett Acquisition compared to prior period's gain of $0.7 million. There were higher gains in the current period due to a higher decrease in the forward curve commodity pricing for natural gas (NYMEX) and oil (WTI) assumptions used in the Monte Carlo simulations during the three months ended September 30, 2024 compared to a slight decrease during the three months ended September 30, 2023.

*Earnings from equity affiliate.* Earnings from our equity affiliate was $50.6 million for the three months ended September 30, 2024, which was change of $1.5 million, from $49.1 million compared to the same period in 2023. Earnings from our equity affiliate is related to our investment in, and our proportionate share in the income or losses of the Power Joint Venture.

*Interest expense.* Interest expense was $9.2 million for the three months ended September 30, 2024, which was a decrease of $10.9 million, from $20.1 million for the three months ended September 30, 2023. The decrease in interest expense during the three months ended September 30, 2024 was primarily due to lower interest rates incurred during the three months ended

September 30, 2024 on our RBL Credit Facility compared to the interest rates on our Term Loan Credit Agreement and revolving credit facilities during the three months ended September 30, 2023.

*Interest expense, related party*. Interest expense from our related party was $1.3 million for the three months ended September 30, 2024, which was a decrease of $0.7 million, from $2.0 million for the three months ended September 30, 2023. The decrease was primarily due to the repayment on the BNAC A&R loan of $25.0 million in June 2024.

*Income tax benefit (expense).* For the three months ended September 30, 2024, we had an income tax expense of $11.3 million, which was a change of $6.1 million, from $5.2 million income tax expense for the three months ended September 30, 2023. During the three months ended September 30, 2024, the increase was due to executive compensation disallowance, offset by the benefit from the monetization of certain tax credits under IRC Section 45Q of the Code from the injection of CO2 waste in the Barnett Zero well, IRC Section 45I Marginal Well Credits from marginal production, excess tax benefits relating to the vesting of restricted shares, and by state apportionment changes due to the sale of Chaffee.

### Results of Operations

### Comparison of the Nine Months Ended September 30, 2024 and 2023

### Operating revenues

Our operating revenues include revenues from the sale of natural gas, NGLs, and oil, midstream revenues, gains and losses on our derivative contracts, marketing revenues, and other revenues. The following table provides information on our revenues for the periods presented:

*(in thousands, other than percentages)*

| Revenues | Nine Months Ended September 30, 2024 | 2023 | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Natural gas revenues | $267,053 | $379,044 | $(111,991) | (30)% |
| NGL revenues | 122,121 | 141,718 | (19,597) | (14)% |
| Oil revenues | 5,319 | 6,559 | (1,240) | (19)% |
| Midstream revenues | 10,168 | 12,227 | (2,059) | (17)% |
| Derivative gains, net | 24,143 | 126,274 | (102,131) | (81)% |
| Marketing revenues | 8,705 | 6,668 | 2,037 | 31% |
| Gain on sales of assets | 6,784 | 308 | 6,476 | \* |
| Related party and other | 16,906 | 5,236 | 11,670 | \* |
| **Total revenues and other operating income** | $461,199 | $678,034 |  |  |
| \*Percentage not meaningful |  |  |  |  |

#### Natural gas revenues

Our natural gas revenues decreased by approximately $112.0 million, or 30% to $267.1 million for the nine months ended September 30, 2024, from $379.0 million for the nine months ended September 30, 2023. The impact of commodity price decreases, excluding the effect of derivative settlements, provided a $78.9 million decrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes). The decrease was also due to lower production volumes during the nine months ended September 30, 2024, primarily from the assets from the Exxon Barnett Acquisition, and from the sale of Chaffee and certain non-operated assets held by Chelsea, which collectively accounted for a $33.1 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 decreased by approximately $19.6 million, or 14% to $122.1 million for the nine months ended September 30, 2024, from $141.7 million for the nine months ended September 30, 2023. The decrease was due to the impact of commodity price decreases, excluding the effect of derivative settlements, which accounted for a $10.8 million decrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes). The decrease was also due to lower production volumes during the nine months ended September 30, 2024, which accounted for a $8.8 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 decreased by approximately $1.2 million, or 19%, to $5.3 million for the nine months ended September 30, 2024, from $6.6 million for the nine months ended September 30, 2023. The decrease was due to lower production volumes during the nine months ended September 30, 2024, which accounted for a $1.2 million decrease in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).

#### Midstream revenues

Our midstream revenues decreased by approximately $2.1 million, or 17% to $10.2 million for the nine months ended September 30, 2024, from $12.2 million for the nine months ended September 30, 2023. This decrease was primarily due to the divestiture of Chaffee of $1.5 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 gains, net

For the nine months ended September 30, 2024, we had net realized and unrealized gains on derivative contracts of $24.1 million compared to net realized and unrealized gains on derivative contracts of $126.3 million for the nine months ended September 30, 2023. The decreased gains for the nine months ended September 30, 2024 was primarily attributable to the significant asset positions as of December 31, 2023 reversing due to settlement during the nine months ended September 30, 2024, resulting in unrealized losses of $82.1 million, which included the sale of call options in January 2024 limiting our 2025/2026 pricing upside, and is currently in a long term liability position. The nine months ended September 30, 2023 resulted in unrealized gains of $55.3 million, due to significant liability positions as of December 31, 2022 that reversed and settled during 2023. This was offset by higher realized gains during the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 of $35.3 million due to slightly lower natural gas prices.

#### Marketing revenues

Our marketing revenues increased by approximately $2.0 million to $8.7 million for the nine months ended September 30, 2024 from $6.7 million for the nine months ended September 30, 2023. Our marketing revenues are derived under our marketing agreement with a third party pursuant to which we receive a fixed percentage of all net income realized in the resale of our and other producers’ hydrocarbons. The increase in marketing revenues during the nine months ended September 30, 2024 was primarily due to colder than normal weather in NEPA for the month of January 2024.

#### Gain on sale of assets

For the nine months ended September 30, 2024, we had a net gain on sales of assets of $6.8 million. This was primarily due to the sale of our wholly-owned subsidiary, Chaffee, for $103.2 million, net of third party transaction costs. The assets sold had an approximate carrying value of $97.4 million. The remaining net gain on sales of assets of $1.1 million was due to the gain on sales of other property and equipment during the nine months ended September 30, 2024.

#### Related party and other

We generate a portion of our revenues from a management fee from the Power Joint Venture, the sale of third-party natural gas, and CCUS revenues generated from IRC Section 45Q tax credits. Our related party and other revenues were $16.9 million for the nine months ended September 30, 2024 compared to $5.2 million for the nine months ended September 30, 2023. Other revenues increased during the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 primarily due to IRC Section 45Q tax credits of $10.3 million from the injection of CO2 in our Barnett Zero well, which started in the fourth quarter of 2023, as well as an increase in third party gas sales of $1.2 million compared to the same period in the prior year.

### 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 | Nine Months Ended September 30, 2024 | 2023 | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: |
| Lease operating and workover | $102,228 | $114,193 | $(11,965) | (10)% |
| Taxes other than income | 31,903 | 59,221 | (27,318) | (46)% |
| Gathering and transportation costs | 167,810 | 183,074 | (15,264) | (8)% |
| Depreciation, depletion, amortization, and accretion | 168,845 | 130,623 | 38,222 | 29% |
| General and administrative | 73,543 | 80,965 | (7,422) | (9)% |
| Other | 15,402 | 10,716 | 4,686 | 44% |
| Total operating expense | $559,731 | $578,792 |  |  |
| **Average costs per Mcfe** |  |  |  |  |
| Lease operating and workover | $0.47 | $0.48 | $(0.01) | (2)% |
| Taxes other than income | 0.15 | 0.25 | (0.10) | (40)% |
| Gathering and transportation costs | 0.77 | 0.77 | — | \* |
| Depreciation, depletion, amortization, and accretion | 0.78 | 0.55 | 0.23 | 42% |
| General and administrative | 0.34 | 0.34 | — | \* |
| Other | 0.07 | 0.05 | 0.02 | 40% |
| Total | $2.58 | $2.44 |  |  |
| \*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)*

|  | Nine Months Ended September 30, 2024 Amount | Per Mcfe | 2023 Amount | Per Mcfe | $ Change | % Change |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Lease operating expenses | $98,151 | $0.45 | $108,319 | $0.46 | $(10,168) | (9)% |
| Workover expenses | 4,077 | 0.02 | 5,874 | 0.02 | (1,797) | (31)% |
| Total lease operating and workover expense | $102,228 | $0.47 | $114,193 | $0.48 | $(11,965) | (10)% |

Lease operating and workover expenses were $102.2 million, or $0.47 per Mcfe, for the nine months ended September 30, 2024, which was a decrease of approximately $12.0 million, or 10%, from $114.2 million, or $0.48 per Mcfe, for the nine months ended September 30, 2023. The decrease in lease operating and workover expenses during the nine months ended September 30, 2024 compared to the same period in 2023 was due to decreases in compression and water expenses of $4.5 million, materials and labor of $3.9 million, and repairs and maintenance of $2.3 million, all of which were due to cost savings initiatives that began during the second half of 2023. In addition, during the nine months ended September 30, 2024, we received a credit of $1.5 million for a water sharing agreement that related to 2023.

#### Taxes other than income

Taxes other than income were $31.9 million, or $0.15 per Mcfe, for the nine months ended September 30, 2024, which was a decrease of approximately $27.3 million, or 46%, from $59.2 million, or $0.25 per Mcfe, for the nine months ended September 30, 2023. The decrease in taxes other than income during the nine months ended September 30, 2024 compared to 2023 was due to decreases in ad valorem and property taxes, and natural gas and NGL production taxes, both associated with our operations in the Barnett of $19.2 million and $8.0 million, respectively. Certain ad valorem and production taxes are not applicable to our NEPA properties.

#### Gathering and transportation

Gathering and transportation expenses were $167.8 million, or $0.77 per Mcfe, for the nine months ended September 30, 2024, which was a decrease of approximately $15.3 million, or 8%, from $183.1 million, or $0.77 per Mcfe, for the nine months ended September 30, 2023. This decrease was driven by decreased production in the Barnett and NGL rate decreases of $11.3 million and $7.3 million, respectively. This was offset by new contracts we entered into during 2024 where we started incurring gathering costs to commercially sequester the CO2 waste utilizing our Barnett Zero Project of $2.2 million, outsourcing gathering costs with our midstream business of $0.9 million, and natural gas rate increases of $0.2 million.

#### Depreciation, depletion, amortization, and accretion

Depreciation, depletion, amortization, and accretion was $168.8 million, or $0.78 per Mcfe, for the nine months ended September 30, 2024, which was an increase of approximately $38.2 million, or 29%, from $130.6 million, or $0.55 per Mcfe, for the nine months ended September 30, 2023. The increase in depreciation, depletion, amortization, and accretion during the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 was primarily due to lower estimated proved reserves resulting from lower natural gas prices used in determination of proved reserves and from the divestiture of Chelsea and Chaffee in June 2024.

#### General and administrative

General and administrative expenses were $73.5 million, or $0.34 per Mcfe, for the nine months ended September 30, 2024, which was a decrease of approximately $7.4 million, or 9%, from $81.0 million, or $0.34 per Mcfe, for the nine months ended September 30, 2023. The decrease in general and administrative expenses during the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 was due to our equity-based compensation on our PRSUs of $14.9 million and a decrease of $6.0 million of management fees paid to Verde CO2 both recognized during the nine months ended September 30, 2023. The performance-based restricted stock units (“PRSU”) expenses expired on December 31, 2023 and the contract with Verde CO2 terminated in November 2023. In addition, marketing and subscriptions decreased period over period by $1.5 million. This was offset by the acceleration of the time-based restricted stock units (“TRSU”) portion of our equity-based compensation of $12.6 million, which was recognized upon the IPO and included $2.5 million of associated payroll taxes, and increases in IPO related expenses of $2.7 million during the nine months ended September 30, 2024 compared to the same period in the prior year.

#### Other operating expenses

Other operating expenses were $15.4 million, or $0.07 per Mcfe, for the nine months ended September 30, 2024, which was an increase of approximately $4.7 million, or 44%, from $10.7 million, or 0.05 per Mcfe, for the nine months ended September 30, 2023. The increase in other operating expenses during the nine months ended September 30, 2024 compared to the same period in 2023 was primarily due to costs incurred during the current period related to the newly enacted Environmental Protection Agency fees of $5.0 million established by the Inflation Reduction Act, $2.2 million in CCUS operating expenses for CO2 purchases and fuel, emissions monitoring costs of $1.8 million, and increased legal contingencies and costs associated with potential CCUS equity raise and investments totaling $1.4 million. This increase was offset by lower rig termination fees of $2.5 million, $2.0 million of prior year inventory restocking fees and write-offs, and lower midstream operating expenses and gas purchases of $1.3 million.

#### Other Income (Expense)

*Gains on contingent consideration liabilities.* 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 $10.0 million, for the nine months ended September 30, 2024, which was a decrease of approximately $14.1 million from the $24.1 million gain for the nine months ended September 30, 2023. The $10.0 million gain compared to the $24.1 million gain was primarily attributable to the prior period’s gain on contingent consideration liabilities with the Devon Barnett Acquisition of $14.0 million compared to the current period's gain of $7.8 million, as well as the prior period's gain on contingent consideration liabilities with the Exxon Barnett Acquisition of $10.1 million compared to the current period's gain of $2.2 million. There were higher gains in the prior period due to a significant decrease in the forward curve commodity pricing for natural gas (NYMEX) and oil (WTI) assumptions used in the Monte Carlo simulations during the nine months ended September 30, 2023 compared to slight decreases during the nine months ended September 30, 2024.

*Earnings from equity affiliate.* Earnings from our equity affiliate was $27.6 million for the nine months ended September 30, 2024, which was a decrease of $7.2 million, from $34.8 million compared to the same period in 2023. Earnings from our equity affiliate is related to our investment in, and our proportionate share in the income or losses of the Power Joint Venture.

*Interest expense.* Interest expense was $40.4 million for the nine months ended September 30, 2024, which was a decrease of $14.0 million, from $54.4 million for the nine months ended September 30, 2023. The decrease in interest expense during the nine months ended September 30, 2024 was primarily due to lower interest rates on our RBL Credit Facility, which we entered into on June 11, 2024, and subsequently paid down the outstanding balances on our SCB Credit Facility, the Revolving Credit Agreement, and the Term Loan Credit Agreement, which incurred higher interest rates.

*Interest expense, related party*. Interest expense from our related party was $5.2 million for the nine months ended September 30, 2024, which was an increase of $0.1 million, from $5.1 million for the nine months ended September 30, 2023. The increase was primarily due to the due to the increase in interest rates period over period.

*Income tax benefit (expense).* For the nine months ended September 30, 2024, we had an income tax benefit of $30.1 million, which was a change of $53.1 million, from $23.0 million income tax expense for the nine months ended September 30, 2023. The period-over-period change was primarily due to a pre-tax loss for the nine months ended September 30, 2024 compared to a pre-tax income for the nine months ended September 30, 2023. During the nine months ended September 30, 2024, we also recognized additional income tax expense due to executive compensation disallowance, which was offset by a tax benefit from the monetization of certain tax credits under IRC Section 45Q from the injection of CO2 waste in the Barnett Zero well, IRC Section 45I Marginal Well Credits from marginal production, excess tax benefits relating to the vesting of restricted shares, and by state apportionment changes due to the sale of Chaffee.

### Liquidity and Capital Resources

### Capital Commitments

Our primary needs for cash are to fund our upstream development, midstream, power, and CCUS projects, fund operations and capital expenditures, fund acquisitions, fund asset retirement obligations, cover any debt interest or minimum volume commitment obligations, pay down debt, and return capital to stockholders. Our primary uses of cash during the nine months ended September 30, 2024 and 2023 were to pay down debt and fund the development of our natural gas properties.

During the nine months ended September 30, 2024 and 2023, cash paid for capital expenditures was $52.8 million and $161.1 million, respectively. 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. We believe that our cash flows from operations, cash on hand, and borrowings under our RBL Credit Agreement 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, and federal grants with the remaining capital needs being funded with cash flows from operations. We are targeting completion of third-party CCUS financing in 2025; however, there can be no assurance that we will be able to complete any CCUS financing on our targeted timeline or at all.

The following table summarizes our cash flows for the nine months ended September 30, 2024 and 2023:

|  | Nine Months Ended September 30, 2024 | 2023 |
| --- | ---: | ---: |
| Net cash provided by operating activities | $74,776 | $115,431 |
| Net cash provided by (used in) investing activities | 80,629 | (156,291) |
| Net cash provided by (used in) financing activities | (289,156) | 80,165 |
| Net increase (decrease) in cash, cash equivalents, and restricted cash | $(133,751) | $39,305 |

***Cash flows provided by operating activities.*** Net cash provided by operating activities was $74.8 million for the nine months ended September 30, 2024, compared to $115.4 million for the nine months ended September 30, 2023. Net cash provided by operating activities decreased during the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023 due to a $57.5 million decrease in working capital, a $33.7 million decrease in income from operations (excluding net unrealized gains (losses), depreciation, depletion, amortization, and accretion, equity-based compensation, and gain on sales of assets), resulting from lower natural gas prices compared to 2023, a $14.8 million increase in cash paid for interest, and $3.9 million of transaction costs associated with the sale of Chaffee and Chelsea, offset by reduced settlements of contingent liabilities of $45.0 million and cash received from the sale of call options of $23.5 million.

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

***Cash flows provided by (used in) investing activities.*** Net cash provided by investing activities was $80.6 million for the nine months ended September 30, 2024, compared to net cash used in investing activities of $156.3 million for the nine months ended September 30, 2023. Contributing to the cash inflow during the nine months ended September 30, 2024 were the total proceeds from the sale of Chaffee and Chelsea of $131.7 million. The change was also due to the decrease of $108.3 million of capital expenditures for the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023, as well as the decrease of $23.4 million of expenditures on CCUS activities over the same period. This was offset by additional cash used of $6.6 million in other investing activities.

The following table presents our capital expenditures (excluding leasehold costs and acquisitions) on an accrual basis for the nine months ended September 30, 2024 and 2023 and reconciles to cash flows used for capital expenditures in the condensed consolidated statements of cash flows.

|  | Nine Months Ended September 30, 2024 | 2023 |
| --- | ---: | ---: |
| Total use of cash and cash equivalents for capital expenditures | $(52,774) | $(161,068) |
| (Increase) decrease in accrued capital expenditures | (4,546) | 13,482 |
| Capital expenditures (accrued) | $(57,320) | $(147,586) |

***Cash flows provided by (used in) financing activities.*** Net cash used in financing activities was $289.2 million for the nine months ended September 30, 2024, which consisted of net payments on debt of $468.0 million, payments of $53.2 million for taxes related to net share settlement of restricted stock units, and payments of debt issuance costs and debt extinguishment costs of $18.3 million. This was offset by net proceeds from the issuance of common stock from our IPO of $253.8 million, after deducting underwriting discounts and commissions. For the nine months ended September 30, 2023, net cash provided by financing activities was $80.2 million, which was primarily due to a capital contribution from BNAC in the amount of $150.0 million in exchange for 7,500,000 shares of our common stock, offset by net payments on debt of $64.0 million and other financing payments of $6.0 million.

### Working Capital

As of September 30, 2024, we had cash and cash equivalents of $31.3 million, compared to $25.4 million of cash and cash equivalents, and restricted cash of $139.7 million as of December 31, 2023. Our net working capital deficit was $13.3 million as of September 30, 2024, compared to a deficit of $100.1 million as of December 31, 2023.

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.

### Loan Agreements and Credit Facilities

#### 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 September 30, 2024, the RBL Credit Agreement had a borrowing base of $800.0 million and an elected commitment of $600.0 million. As of November 13, 2024, $180.0 million of revolving borrowings and $14.6 million of letters of credit were outstanding under the RBL Credit Agreement, leaving $405.4 million of available capacity thereunder for future borrowings and 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.

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, LLC and BKV-BPP Cotton Cove, LLC 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 the Power Joint Venture or BKV-BPP Cotton Cove, LLC to make distributions. During the nine months ended September 30, 2024 and 2023 no distributions were made by the Power Joint Venture or BKV-BPP Cotton Cove, LLC. 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 the Power Joint Venture must be approved by a majority of the Power Joint Venture's eight member board of managers, four of which are appointed by us and four of which are appointed by Banpu Power US Corporation (“BPPUS”). Similarly, any additional capital contributions to BKV-BPP Cotton Cove, LLC must receive the unanimous approval of BKV-BPP Cotton Cove, LLC's six member board of managers, four of which are appointed by us and two of which 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 September 30, 2024, our material off-balance sheet arrangements and transactions included volume commitments of $337.6 million and letters of credit of $14.6 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. There have been no material changes to our critical accounting policies and estimates as described in our Prospectus with the exception of equity-based compensation due to the 2024 Plan put in place subsequent to the IPO.

### Equity-Based Compensation

### 2024 Long Term Incentive Plan

Pursuant to the BKV Corporation 2024 Long Term Incentive Plan (the “2024 Plan”), TRSUs and PRSUs may be granted to eligible participants. On September 27, 2024, we made a Company-wide grant of restricted stock units under the 2024 Plan, for a total of 704,649 PRSUs and 469,835 TRSUs.

We recognize compensation cost related to TRSUs under the 2024 Plan on a straight-line basis based on estimated grant date fair value, as if all three tranches of the TRSUs were granted at once, rather than being granted on an annual basis over three years. We also recognize compensation costs related to the PRSUs on a straight-line basis based on the estimated grant date fair value over the applicable vesting period.

The TRSUs we are authorized to grant include service conditions and the PRSUs we are authorized to grant include service conditions, market performance conditions, and non-market performance conditions. There is no obligation to make any future grants, and any such grants would require approval by our board of directors. For accounting purposes, the grant date fair value of the TRSUs that were granted was determined based on BKV's stock price on September 27, 2024. The grant date fair value of the PRSUs was determined based on the service conditions, market performance conditions, and non-market performance conditions of the award on the grant and utilizing the fair market value of common stock on the grant date and Monte Carlo simulations, as well as probability assessments relative to the satisfaction of non-market performance conditions.

Forfeitures are estimated and recognized over the applicable service period and are re-evaluated at the end of each reporting period.

### 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 (the “Securities Act”), including as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As a result, for so long as we qualify as an emerging growth company, we are eligible to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies. We have elected to take advantage of certain of the reduced disclosure obligations in this 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, 8,926 characters.

### 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 September 30, 2024 consisted of commodity price swaps, basis differential swaps, 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 September 30, 2024 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% 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 nine months ended September 30, 2024, a hypothetical increase or decrease of $0.10 per Mcf in NYMEX would have resulted in a $7.0 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 $5.0 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, the Power Joint Venture 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. The Power Joint Venture 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 the Power Joint Venture 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. The Power Joint Venture 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. The Power Joint Venture attempts to hedge basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the quantities that it requires. The Power Joint Venture’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 the Power Joint Venture, 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 the Power Joint Venture 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 the Power Joint Venture, 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 gains, 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 September 30, 2024, the estimated fair value of our commodity derivative instruments was a net liability of $3.1 million, comprised of current and noncurrent assets and current and noncurrent liabilities. As of December 31, 2023, the estimated fair value of our commodity derivative instruments was a net asset of $102.5 million, comprised of current and noncurrent assets.

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 September 30, 2024, our primary exposure to interest rate risk resulted from our outstanding borrowings on our RBL Credit Agreement, which has a floating interest rate. As of September 30, 2024, we had $190.0 million of outstanding borrowings under the RBL Credit Agreement. The average annualized interest rate incurred on our outstanding borrowings during the nine months ended September 30, 2024 was approximately 9.4%. We estimate that a 1.0% increase in the applicable average interest rates during the nine months ended September 30, 2024 would have resulted in an increase of $4.4 million in interest expense.

## Controls and procedures

As filed, 4,021 characters.

### Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-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 the operation 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 ensure that the information required to be disclosed by us is recorded, processed, summarized, and reported within the time periods specified in the Commission's rules and forms, and that 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 the material weakness described below as of September 30, 2024, our disclosure controls and procedures were not effective.

### Material Weakness in Internal Control over Financial Reporting

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company's annual or interim financial statements will not be prevented or detected in a timely manner.

As of September 30, 2024, we had a material weakness in our internal control over financial reporting in that 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 audit adjustments to income tax benefit, income taxes payable to related party and deferred tax assets in the consolidated financial statements as of December 31, 2021 and for the year then ended, and an immaterial audit adjustment to the supplemental cash flows 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. Additionally, the deficiency 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.

### Changes in Internal Control over Financial Reporting

There were no changes in the Company's internal control over financial reporting during the quarter ended September 30, 2024 that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting.

## Risk factors

As filed, 298 characters.

The Quarterly Report on Form 10-Q should be read in conjunction with the “*Risk Factors”* disclosed in the Prospectus, 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 Prospectus.

Filed Nov 13, 2024.
Source: SEC EDGAR, the filing index for accession 0001628280-24-047546. Last ingested by Listed: Oct 26, 2026, 18:55 ET. No prices; not investment advice.