BKV Corp (BKV) FY 2024 MD&A

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included in Item 8 of Part II, Financial Statements and Supplementary Data in this Annual Report on Form 10-K. This Annual Report on Form 10-K contains certain statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Certain statements contained in the Management’s Discussion and Analysis of Financial Condition and Results of Operations are forward-looking statements that involve risks and uncertainties. The forward-looking statements are not historical facts, but rather are based on current expectations, estimates, assumptions, and projections about our industry, business, and future financial results. Our actual results could differ materially from the results contemplated by these forward-looking statements due to a number of factors, including those discussed in other sections of this Annual Report on Form 10‑K. See Item 1A of Part I, “Risk Factors” and under “Cautionary Note Regarding Forward-Looking Statements.”

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

Initial Public Offering

•Initial Public Offering. On September 27, 2024, we completed our 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, Chaffee, which owned a non-operated interest in approximately 9,800 net acres and 116.0 gross (24.2 net) wells and 122 Bcfe of proved reserves in the Marcellus Shale in the Appalachian Basin of 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, Chelsea, sold certain of its non-operated upstream assets, including its interest in approximately 6,800 net acres and 214.0 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 Liquidity and Capital Resources — Loan Agreements and Credit Facilities below) 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 entered into a reserve-based lending agreement (the “RBL Credit Agreement”), with Citibank, N.A. as administrative agent and

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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 December 31, 2024, the RBL Credit Agreement had an outstanding balance of $165.0 million, a borrowing base of $750.0 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 year ended December 31, 2024.

•Production of natural gas, NGLs, and oil was 288.4 Bcfe.

•Average realized product prices, excluding the impact of settled derivatives, were $1.93 per Mcfe.

•Production revenues were $557.6 million and midstream revenues were $12.6 million.

•Lease operating expense was $132.3 million, or $0.46 per Mcfe.

•Net income (loss) was $(142.9) million.

•Net cash provided by operating activities was $118.5 million.

•Accrued capital expenditures were $117.6 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, 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.

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Production Volumes.

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

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 7 - Derivative Instruments in Item 8 of Part II, “Financial Statements and Supplementary Data.” The following is a comparison of average pricing excluding and including the effects of derivatives:

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(1)Impact of derivatives prices excludes $13.3 million and $46.7 million of gains on derivative contract terminations for the years ended December 31, 2024 and 2023, respectively, and $158.4 million of losses on derivative contract terminations for the year ended December 31, 2022.

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Results of Operations

Comparison of the Year Ended December 31, 2024 and 2023

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 and on the sales of our business and assets, marketing revenues, related party revenues, and other income from operations. The following table provides information on our revenues and other operating income for the periods presented:

Natural Gas Revenues

Our natural gas revenues decreased by approximately $124.4 million, or 24%, to $385.5 million for the year ended December 31, 2024, from $509.8 million for the year ended December 31, 2023. The impact of commodity price decreases, excluding the effect of derivative settlements, provided a $81.4 million decrease in year-over-year revenues (calculated as the change in the year-over-year average price times current year's production volumes). The decrease was also due to lower production volumes during the year ended December 31, 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 $43.0 million decrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price).

NGL Revenues

Our NGL revenues decreased by approximately $22.4 million, or 12%, to $165.5 million for the year ended December 31, 2024, from $187.9 million for the year ended December 31, 2023. The decrease was due to lower production volumes during the year ended December 31, 2024, which accounted for a $12.4 million decrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price). The decrease was also due to the impact of commodity price decreases, excluding the effect of derivative settlements, which accounted for a $10.0 million decrease in year-over-year revenues (calculated as the change in the year-over-year average price times current year's production volumes).

Oil Revenues

Our oil revenues decreased by approximately $1.8 million, or 22%, to $6.6 million for the year ended December 31, 2024, from $8.4 million for the year ended December 31, 2023. The decrease was due to lower production volumes during the year ended December 31, 2024, which accounted for a $1.6 million decrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year's average price). The decrease was also due to the impact of commodity price decreases, excluding the impact of derivative settlements, which account for a $0.2 million decrease in the year-over-year revenues (calculated as the change in the year-over-year average price times current year's production volumes).

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Midstream Revenues

Our midstream revenues decreased by approximately $3.6 million, or 22%, to $12.6 million for the year ended December 31, 2024, from $16.2 million for the year ended December 31, 2023. This decrease was primarily due to the divestiture of Chaffee of $2.6 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 (Losses), Net

For the year ended December 31, 2024, we had net realized and unrealized losses on derivative contracts of $34.2 million compared to net realized and unrealized gains on derivative contracts of $238.7 million for the year ended December 31, 2023. The decreased losses for the year ended December 31, 2024 was primarily attributable to the significant asset positions as of December 31, 2023 reversing due to settlement during 2024, resulting in unrealized losses of $146.7 million, which included the sale of call options in January 2024 limiting our 2026/2027 pricing upside, and is currently in a long term liability position. The year ended December 31, 2023 resulted in unrealized gains of $148.6 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 year ended December 31, 2024 compared to the year ended December 31, 2023 of $22.3 million due to slightly lower natural gas prices.

Marketing Revenues

Our marketing revenues increased by approximately $2.0 million to $10.7 million for the year ended December 31, 2024 from $8.7 million for the year ended December 31, 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 year ended December 31, 2024 was primarily due to colder than normal weather in NEPA for the month of January 2024.

Gain on Sale of Business

For the year ended December 31, 2024, we sold our wholly-owned subsidiary, Chaffee, for $104.4 million, net of third party transaction costs. The assets sold had an approximate carrying value of $97.3 million, which resulted in a gain on the sale of Chaffee of $7.1 million.

Gains on Sales of Assets

For the year ended December 31, 2024, we sold other properties for $5.0 million in proceeds, which resulted in a gain on the sale of these properties of $3.6 million. For the year ended December 31, 2023, we sold land and our solar assets for $6.7 million in proceeds, which resulted in a gain on sale of assets of $2.2 million.

Related Party Revenues

We generate a portion of our revenues from a management fee from BKV-BPP Power, the sale of third-party natural gas, and CCUS revenues generated from Section 45Q tax credits. Our related party revenues were $17.1 million for the year ended December 31, 2024 compared to $4.3 million for the year ended December 31, 2023. Related party revenues increased during the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily due to an increase in Section 45Q tax credits of $13.3 million from the injection of CO2 waste in our Barnett Zero well, which started in the fourth quarter of 2023. This was offset by a decrease in operating fee income with BKV-BPP Power of $0.5 million due to contracted rate decreases.

Other Revenue

We generate a portion of our revenues from the sale of third-party natural gas. Other revenues was $6.6 million for the year ended December 31, 2024 compared to $4.0 million for the year ended December 31, 2023. The increase year-over-year was primarily due to an increase in third party gas sales of $2.7 million.

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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:

Lease Operating and Workover

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

Lease operating and workover expenses were $137.0 million, or $0.47 per Mcfe, for the year ended December 31, 2024, which was a decrease of approximately $13.7 million, or 9%, from $150.6 million, or $0.48 per Mcfe, for the year ended December 31, 2023. The decrease in lease operating and workover expenses during the year ended December 31, 2024 compared to the same period in 2023 was due to decreases in compression and water expenses of $5.6 million, materials and labor of $3.6 million, and repairs and maintenance of $2.7 million, all of which were due to cost savings initiatives that began during the second half of 2023 and the divestiture of Chaffee and certain non-operating upstream assets in Chelsea. In addition, during the year ended December 31, 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 $35.0 million, or $0.12 per Mcfe, for the year ended December 31, 2024, which was a decrease of approximately $37.3 million, or 52%, from $72.3 million, or $0.23 per Mcfe, for the year ended December 31, 2023. The decrease in taxes other than income during the year ended December 31, 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 $27.8 million and $9.2 million, respectively. Certain ad valorem and production taxes are not applicable to our NEPA properties.

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Gathering and Transportation

Gathering and transportation expenses were $222.4 million, or $0.77 per Mcfe, for the year ended December 31, 2024, which was a decrease of approximately $26.6 million, or 11%, from $249.0 million, or $0.79 per Mcfe, for the year ended December 31, 2023. This decrease was driven by decreased production in the Barnett and natural gas rate decreases of $15.7 million and $12.2 million, respectively. This was offset by new contracts we entered into during 2024 where we started outsourcing gathering costs with our midstream business of $1.3 million.

Depreciation, Depletion, Amortization, and Accretion

Depreciation, depletion, amortization, and accretion was $217.5 million, or $0.75 per Mcfe, for the year ended December 31, 2024, which was a decrease of approximately $5.8 million, or 3%, from $223.4 million, or $0.71 per Mcfe, for the year ended December 31, 2023. The decrease in depreciation, depletion, amortization, and accretion during the year ended December 31, 2024 compared to the year ended December 31, 2023 was due to lower production during the year ended December 31, 2024 compared to the same period in the prior year, offset by lower estimated proved reserves resulting from lower natural gas prices used in the determination of proved reserves and from the divestiture of Chaffee and certain non-operated upstream assets in Chelsea in June 2024.

General and Administrative

General and administrative expenses were $104.5 million, or $0.36 per Mcfe, for the year ended December 31, 2024, which was a decrease of approximately $10.2 million, or 9%, from $114.7 million, or $0.37 per Mcfe, for the year ended December 31, 2023. The decrease was driven by a $22.2 million reduction in equity-based compensation related to the expiration of performance-based restricted stock units (“PRSU”) on December 31, 2023, and an $8.0 million decrease in management fees following the termination of the Verde CO2 contract in November 2023. These cost savings were partially offset by a $12.6 million acceleration of time-based restricted stock units (“TRSU”) recognized upon the IPO (including $2.5 million in payroll taxes), $3.5 million in stock compensation expense under the 2024 Plan, and $3.7 million in higher payroll costs due to increased headcount in 2024.

Other Operating Expenses

Other operating expenses were $19.4 million, or $0.07 per Mcfe, for the year ended December 31, 2024, which was an increase of approximately $6.8 million, or 54%, from $12.6 million, or 0.04 per Mcfe, for the year ended December 31, 2023. The increase in other operating expenses during the year ended December 31, 2024 compared to the same period in 2023 was primarily driven by the following factors: $5.3 million in CCUS operating expenses for CO2 purchases and fuel and increased legal contingencies, $3.4 million in higher emissions monitoring costs, $2.1 million in well clean up costs and expenses related to a potential CCUS equity raise and investments, and $1.0 million in costs from the newly enacted EPA fees under the Inflation Reduction Act. These increases were offset by $3.6 million of inventory restocking and rig termination fees, $2.0 million of prior year inventory restocking fees and write-offs, and $0.7 million of lower midstream operating expenses and gas purchases.

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 $9.7 million, for the year ended December 31, 2024, which was a decrease of approximately $28.7 million from the $38.4 million gain for the year ended December 31, 2023. The $9.7 million gain compared to the $38.4 million gain was primarily attributable to the prior period’s gain on contingent consideration liabilities with the Devon Barnett Acquisition of $25.0 million compared to the current period's gain of $7.5 million, as well as the prior period's gain on contingent consideration liabilities with the Exxon Barnett Acquisition of $13.4 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 year ended December 31, 2023 compared to slight decreases during the year ended December 31, 2024.

Earnings (losses) from equity affiliate. Earnings from our equity affiliate was $10.4 million for the year ended December 31, 2024, which was a decrease of $6.4 million, from $16.9 million compared to the year ended December 31, 2023. Earnings from our equity affiliate is related to our investment in, and our proportionate share in the income or losses of the BKV-BPP Power Joint Venture.

Loss on early extinguishment of debt. Loss on early extinguishment of debt was $13.9 million for the year ended December 31, 2024 in connection with the early termination of our Term Loan Credit Facility and Revolving Credit Agreement that took place in June 2024.

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Interest expense. Interest expense was $45.6 million for the year ended December 31, 2024, which was a decrease of $24.4 million, from $69.9 million for the year ended December 31, 2023. The decrease in interest expense during the year ended December 31, 2024 was primarily due to lower interest rates on our RBL Credit Facility, which we entered into on June 11, 2024, and the subsequent pay down on 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 year ended December 31, 2024, which was a decrease of $1.9 million, from $7.1 million for the year ended December 31, 2023. The decrease was due to the pay down of $75.0 million of related party borrowings with BNAC during the year ended December 31, 2024, slightly offset by the increase in interest rates year-over-year.

Income tax benefit (expense). For the year ended December 31, 2024, we had an income tax benefit of $43.6 million, which was a change of $71.8 million, from an income tax expense of $28.2 million for the year ended December 31, 2023. The year-over-year change was primarily due to a pre-tax loss for the year ended December 31, 2024 compared to a pre-tax income for the year ended December 31, 2023. During the year ended December 31, 2024, we also recognized additional income tax expense due to executive compensation disallowance, which was offset by a tax benefit from the monetization of Section 45Q tax credits associated with the injection of CO2 waste in the Barnett Zero Project, Code 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 Year Ended December 31, 2023 and 2022

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 and on the sale of assets, marketing revenues, and other income from operations. The following table provides information on our revenues and other operating income for the periods presented:

Natural Gas Revenues

Our natural gas revenues decreased by approximately $800.5 million to $509.8 million for the year ended December 31, 2023, from $1.3 billion for the year ended December 31, 2022. The impact of commodity price decreases, excluding the effect of derivative settlements, resulted in a $994.3 million decrease in year-over-year revenues (calculated as the change in the year-over-year average price times current year production volumes). This was offset by higher production volumes, primarily from the 2022 Barnett Assets, during the year ended December 31, 2023, which accounted for a $193.8 million increase in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year average price).

NGL Revenues

Our NGL revenues decreased by approximately $123.7 million to $187.9 million for the year ended December 31, 2023, from $311.5 million for the year ended December 31, 2022. The impact of commodity price decreases, excluding the effect of derivative settlements, provided a $134.9 million decrease in year-over-year revenues (calculated as the change in

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the year-over-year average price times current period production volumes). This was offset by higher production volumes, primarily from the 2022 Barnett Assets, during the year ended December 31, 2023, which accounted for a $11.2 million increase in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year average price).

Oil Revenues

Our oil revenues decreased by approximately $3.4 million to $8.4 million for the year ended December 31, 2023 from $11.9 million for the year ended December 31, 2022. The decrease was driven by lower production volumes during the year ended December 31, 2023, which accounted for a $1.8 million decrease in year-over-year revenues (calculated as the change in year-over-year volumes times the prior year average price). The decrease was also due to the impact of commodity price decreases, excluding the effect of derivative settlements, which resulted in a $1.6 million decrease in year-over-year revenues (calculated as the change in the year-over-year average price times current period production volumes).

Midstream Revenues

Our midstream revenues increased by approximately $3.5 million to $16.2 million for the year ended December 31, 2023 from $12.7 million for the year ended December 31, 2022. This increase was primarily due to the midstream assets acquired in the Exxon Barnett Acquisition, slightly offset by decreases in the associated production of natural gas properties that our legacy midstream assets support.

Derivative Gains (Losses), Net

For the year ended December 31, 2023, we had net realized and unrealized gains on derivative contracts of $238.7 million compared to net realized and unrealized losses on derivative contracts of $629.7 million for the year ended December 31, 2022. The increased gains for the year ended December 31, 2023 was attributable to decreases in underlying commodity prices and volatility in energy markets, which resulted in higher realized and unrealized gains on derivative contracts.

Marketing Revenues

Our marketing revenues decreased by approximately $2.3 million to $8.7 million for the year ended December 31, 2023 from $11.0 million for the year ended December 31, 2022. 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 decrease in marketing revenues was primarily due to lower natural gas prices during the year ended December 31, 2023 compared to the year ended December 31, 2022.

Related Party Revenues

We generate a portion of our revenues from a management fee from the BKV-BPP Power Joint Venture. Our related party revenues were $4.3 million for the year ended December 31, 2023, as compared to $2.7 million for the year ended December 31, 2022. Related party revenues increased during the year ended December 31, 2023 compared to the year ended December 31, 2023 primarily due to an increase in operating fee income with BKV-BPP Power of $0.9 million due to contracted rate increases and Section 45Q tax credits of $0.7 million from the injection of CO2 waste in our Barnett Zero well, which started in the fourth quarter of 2023.

Other Revenue

Other revenues were $4.0 million for the year ended December 31, 2023, as compared to $0.1 million for the year ended December 31, 2022. Other revenues increased during the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to our decision to start selling third party natural gas in 2023, in connection with which we recognized sales of $3.8 million for the year ended December 31, 2023.

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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:

Lease Operating and Workover

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

Lease operating and workover expenses were $150.6 million or $0.48 per Mcfe, for the year ended December 31, 2023, which was an increase of $19.1 million, or 15%, from $131.5 million, or $0.47 per Mcfe, for the year ended December 31, 2022. The increase in lease operating and workover expenses during the year ended December 31, 2023 compared to the same period in 2022 was primarily due to the Exxon Barnett Acquisition, which closed on June 30, 2022. The acquired operations drove $23.2 million of incremental lease operating and workover expenses during the year ended December 31, 2023. The remaining $4.1 million of decreased lease operating and workover expenses was driven by a $6.5 million decrease in professional services production and equipment, which was offset in part by $2.4 million of individually immaterial net increases in other direct production costs incurred in connection with our operations.

Taxes Other Than Income

Taxes other than income were $72.3 million, or $0.23 per Mcfe, for the year ended December 31, 2023, which was a decrease of $42.4 million, or 37%, from $114.7 million, or $0.41 per Mcfe, for the year ended December 31, 2022. The decrease in taxes other than income during the year ended December 31, 2023 compared to 2022 was primarily due to decreases in natural gas and NGL production taxes associated with our operations from the 2020 Barnett Assets and the 2022 Barnett Assets of $59.0 million and decreases in property taxes related to our NEPA natural gas properties of $1.7 million, in each case due to lower natural gas prices during the year ended December 31, 2023 compared to the year ended

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December 31, 2022. This was offset by an increase in ad valorem and property taxes on our 2020 Barnett Assets and 2022 Barnett Assets of $18.5 million. Certain ad valorem and production taxes are not applicable to our NEPA natural gas properties.

Gathering and Transportation

Gathering and transportation expenses were $249.0 million, or $0.79 per Mcfe, for the year ended December 31, 2023, which was an increase of $40.2 million, or 19%, from $208.8 million, or $0.75 per Mcfe, for the year ended December 31, 2022. Approximately $30.5 million of the increase was driven by the Exxon Barnett Acquisition. The remainder of the increase in gathering and transportation expenses of $9.7 million during the year ended December 31, 2023 compared to the same period in 2022 was due to an increase in cost and production volumes from the development of the 2020 Barnett Assets.

Depreciation, Depletion, Amortization, and Accretion

Depreciation, depletion, amortization, and accretion was $223.4 million, or $0.71 per Mcfe, for the year ended December 31, 2023, which was an increase of $104.5 million, or 88%, from $118.9 million, or $0.43 per Mcfe, for the year ended December 31, 2022. The increase in depreciation, depletion, amortization, and accretion during the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to the Exxon Barnett Acquisition, which accounted for an additional $64.9 million of depreciation, depletion, amortization, and accretion expense during the year ended December 31, 2023. The remaining increase of $39.6 million was primarily due to increased production from the development of our natural gas properties in NEPA and the Barnett during 2022.

General and Administrative

General and administrative expenses were $114.7 million, or $0.37 per Mcfe, for the year ended December 31, 2023, which was a decrease of $33.9 million, or 23%, from $148.6 million, or $0.53 per Mcfe, for the year ended December 31, 2022. The decrease in general and administrative expenses during the year ended December 31, 2023 compared to the year ended December 31, 2022 was due to a decrease in direct transaction costs from the Exxon Barnett Acquisition of $18.3 million, a decrease of $5.5 million in equity-based compensation, employee wages and contract labor and fees, and a decrease of $5.5 million in consulting and other general and administrative expenses. The decrease was also due to $8.0 million of BKVerde management fees incurred during 2023, compared to $13.0 million in 2022.

Other Operating Expenses

Other operating expenses were $12.6 million, or $0.04 per Mcfe, for the year ended December 31, 2023, which was an increase of $9.0 million from $3.6 million, or $0.01 per Mcfe, for the year ended December 31, 2022. The increase in other operating expenses during the year ended December 31, 2023 was primarily attributable to $3.6 million of inventory restocking and rig termination fees and $3.6 million of expenses incurred as a result of our decision to start selling third party gas. The remaining increase of $1.7 million was made up of individually immaterial increases.

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 $38.4 million for the year ended December 31, 2023, which was an increase of $31.7 million from the $6.6 million gain for the year ended December 31, 2022. The $38.4 million gain compared to the $6.6 million gain was primarily attributable to a gain on contingent consideration liabilities from the Devon Barnett Acquisition of $25.0 million. Higher decreases in forward curve commodity pricing for natural gas (NYMEX) and oil (WTI) assumptions used in the Monte Carlo simulations during the year ended December 31, 2023, compared to moderate decreases during the year ended December 31, 2022 further decreased the fair market value of the liability by $19.9 million. The remaining $11.8 million of the current period gain on contingent consideration liabilities was attributed to the 2022 Exxon Barnett Acquisition, which was also driven by decreases in forward curve commodity pricing compared to the year ended December 31, 2022.

Earnings from equity affiliate. Earnings from our equity affiliate was $16.9 million for the year ended December 31, 2023 which was a change of $8.4 million from $8.5 million compared to the same period in 2022. Earnings from our equity affiliate is related to our investment in, and our proportionate share in the income or losses of, the BKV-BPP Power Joint Venture. On July 10, 2023, the BKV-BPP Power Joint Venture acquired CXA Temple 2, LLC, the owner of 100% of the interests in Temple II, a combined cycle gas turbine and steam turbine power plant located on the same site as Temple I in the Electric Reliability Council of Texas North Zone in Temple, Texas, for an aggregate purchase price of $460.0 million. The Temple Plants deliver power to customers on the ERCOT power network in Texas.

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Interest expense. Interest expense was $69.9 million for the year ended December 31, 2023, which was an increase of $43.6 million from $26.3 million for the year ended December 31, 2022. The increase in interest expense during the year ended December 31, 2023 was primarily driven by the term loans borrowed under our Term Loan Credit Agreement on June 30, 2022 and increased balances under our Revolving Credit Agreement and SCB Credit Facility.

Interest expense, related party. Interest expense from related parties was $7.1 million for the year ended December 31, 2023, which was a decrease of $3.7 million from $10.8 million for the year ended December 31, 2022. The decrease was primarily due to the payment in full of the loan under the $116 Million Loan Agreement (as defined herein) in 2022, which provided nine months of interest compared to none in 2023. This was slightly offset by an increase in the interest on the loan under the related party loan with BNAC, which provided for seven months of interest in 2022 compared to a full year in 2023.

Other income. Other income was $6.2 million for the year ended December 31, 2023, which was an increase of $4.8 million from $1.4 million for the year ended December 31, 2022. The increase was due to the release of a service fee of $3.4 million originating from the Exxon Barnett Acquisition and the sale of surface rights of $1.1 million during the year ended December 31, 2023.

Income tax expense. Income tax expense was $28.2 million for the year ended December 31, 2023, which was a decrease of $34.4 million from $62.7 million for the year ended December 31, 2022. The year-over-year change was due primarily to the lower pre-tax income during the year ended December 31, 2023 compared to the year ended December 31, 2022.

Liquidity and Capital Resources

Capital Commitments

Our primary needs for cash are to fund our upstream development, midstream, power, and CCUS activities, fund operations and capital expenditures, acquisitions and asset retirement obligations, cover any debt interest or minimum volume commitment obligations, pay down debt, and return capital to stockholders. Our primary uses of cash during the years ended December 31, 2024 and 2023 were to pay down debt and fund the development of our natural gas properties, and during the year ended December 31, 2022, our primary use of cash was to fund our Exxon Barnett Acquisition.

During the years ended December 31, 2024, 2023, and 2022, cash paid for capital expenditures was $100.9 million, $187.7 million, and $248.1 million, respectively. Our current estimated budget for total 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 of 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. We are currently in non-binding exclusive discussions concerning a potential joint venture with a third-party investor with the expectation to close in the first half of 2025. 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.

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The following table summarizes our cash flows for the years ended December 31, 2024, 2023, and 2022 (in thousands):

Cash flows provided by operating activities. Net cash provided by operating activities was $118.5 million for the year ended December 31, 2024, compared to $123.1 million for the year ended December 31, 2023. Net cash provided by operating activities decreased during the year ended December 31, 2024 compared to the year ended December 31, 2023 due to a $41.5 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 $17.3 million decrease in working capital, $10.0 million in distributions from the BKV-BPP Power Joint Venture made in 2023, and $3.9 million of transaction costs associated with the sale of Chaffee and certain non-operated upstream assets in Chelsea. These decreases were offset by reduced settlements of contingent liabilities of $45.0 million and cash received from the sale of call options of $23.5 million.

Net cash provided by operating activities was $123.1 million for the year ended December 31, 2023, compared to $349.2 million for the year ended December 31, 2022. Net cash provided by operating activities decreased during the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily due to a $150.2 million decrease in income from operations (excluding net unrealized gains (losses), depreciation, depletion, amortization, and accretion, and equity-based compensation) resulting from lower natural gas prices compared to 2022, a $36.4 million decrease due to higher cash paid for interest, which was driven by the term loans borrowed under our Term Loan Credit Agreement on June 30, 2022 and increased balances under our Revolving Credit Agreement and Revolving Credit Facilities, a decrease in contingent consideration as prior year’s $19.7 million was recognized in net cash provided by (used in) financing activities, and cash received on the settlement litigation in 2022 of $16.9 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 $36.1 million for the year ended December 31, 2024, compared to net cash used in investing activities of $177.8 million for the year ended December 31, 2023. Contributing to the cash inflow during the year ended December 31, 2024 were the total proceeds from the sale of Chaffee and certain non-operated upstream assets held by Chelsea of $132.6 million. The change was also due to the decrease of $49.0 million of capital expenditures (excluding CCUS activities), a $37.8 million reduction of CCUS-related expenditures, and a $4.9 million decrease in cash used for acquisition of natural gas properties for the year ended December 31, 2024 compared to the prior year. This was offset by a reduction of $10.4 million of cash proceeds from other investing activities for the year ended December 31, 2024 compared to the prior year.

Net cash used in investing activities decreased from $865.6 million for the year ended December 31, 2022 to $177.8 million for the year ended December 31, 2023. The primary driver of the decrease was the $619.4 million used in connection with the Exxon Barnett Acquisition, which closed on June 30, 2022. Expenditures in development of natural gas properties also decreased by $101.0 million, which was offset by an increase of $50.0 million used in connection with the development of CCUS projects during the year ended December 31, 2023 compared to the year ended December 31, 2022.

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The following table presents our capital expenditures (excluding leasehold costs and acquisitions) on an accrual basis for the years ended December 31, 2024, 2023, and 2022 and reconciles to cash flows used for capital expenditures in the consolidated statements of cash flows.

Cash flows provided by (used in) financing activities. Net cash used in financing activities was $304.8 million for the year ended December 31, 2024, which consisted of net payments on debt of $493.0 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 $265.7 million, after deducting underwriting discounts and commissions.

Net cash provided by financing activities decreased from $534.8 million for the year ended December 31, 2022 to $66.7 million for the year ended December 31, 2023. The drivers of the current period inflow were the $258.5 million and $117.0 million of advances received from the Revolving Credit Facilities and Revolving Credit Agreement, respectively. In addition, we received a capital contribution from BNAC in the amount of $150.0 million in exchange for 7,500,000 shares of our common stock. This was offset by cash outflows of $114.0 million, $272.5 million and $66.0 million for repayments made on our Term Loan Credit Agreement, Revolving Credit Facilities and Revolving Credit Agreement, respectively.

The $534.8 million cash inflow for the year ended December 31, 2022 was due to proceeds of $570.0 million in connection with the Term Loan Credit Agreement and proceeds of $75.0 million in connection with the related party note payable with BNAC, offset by repayments of $166.0 million to the related party, $190.0 million of advances received in connection with our Overseas Chinese Banking Corporation Credit Facility, offset by repayments of $100.0 million on said facility and the financing portion of the settlement of contingent consideration of $19.7 million. The remainder of the fluctuation consisted of deferred offering cost payments, debt issuance costs and net share settlements.

Working Capital

As of December 31, 2024, we had cash and cash equivalents of $14.9 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 $71.6 million as of December 31, 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

Term Loan Credit Agreement

On June 16, 2022, we entered into the Term Loan Credit Agreement with a syndicate of banks and Bangkok Bank Public Company Limited (New York Branch), as the administrative agent. The Term Loan Credit Agreement included $600.0 million of commitments for term loans used solely to fund a portion of the purchase price for the Exxon Barnett Acquisition. On June 30, 2022, we borrowed $570.0 million of term loans under the Term Loan Credit Agreement to partially fund the Exxon Barnett Acquisition. As discussed below, such term loans required annual principal payments of $114.0 million. We made the first annual principal payment of $114.0 million on June 23, 2023. Following such payment, $456.0 million of aggregate principal amount remained outstanding under the Term Loan Credit Agreement.

On June 11, 2024, we paid off the amounts outstanding under the Term Loan Credit Agreement with proceeds from the loans under the RBL Credit Agreement and cash on hand. We terminated the Term Loan Credit Agreement concurrently with the repayment of such outstanding borrowings.

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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 December 31, 2024, the RBL Credit Agreement had a borrowing base of $750.0 million and an elected commitment of $600.0 million. As of March 31, 2025, $200.0 million of revolving borrowings and $14.1 million of letters of credit were outstanding under the RBL Credit Agreement, leaving $385.9 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.

Revolving Credit Agreements

On June 11, 2024, using the funds from the RBL Credit Agreement, we repaid the outstanding debt balances under (i) the Term Loan Credit Agreement, (ii) the Revolving Credit Agreement, and (iii) our loan agreement previously entered into in March 2022 with Standard Charter Bank (the “SCB Credit Facility”), in each case with proceeds from the loans under the RBL Credit Agreement 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.

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 year ended December 31, 2024, no distributions were made by BKV-BPP Power or BKV-BPP Cotton Cove. During the year ended December 31, 2023, BKV-BPP Power made a distribution of $10.0 million to BKV Corporation, and during the year

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ended December 31, 2022, 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. For more information about our joint ventures with BPPUS, see “Risk Factors - Risks Related to Our Power Generation Business - We operate our power generation business through a joint venture which we do not control” and “Risk Factors -  Risks Related to Our CCUS Business -  We operate the Cotton Cove Project through a joint venture that requires the consent of BPPUS for certain material actions.”

Internal Controls and Procedures

As an emerging growth company, we are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act, and therefore are not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act until the year following our first annual report required to be filed with the SEC. We may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls over financial reporting until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act.

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 December 31, 2024, our material off-balance sheet arrangements and transactions included volume commitments of $320.6 million and letters of credit of $14.1 million against the RBL Credit Agreement. For further information regarding these arrangements, see Note 16 - Commitments and Contingencies to our 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 Item 8 of Part II, Financial Statements and Supplementary Data, Note 2 - Summary of Significant Accounting Policies.

Accounting for Natural Gas and NGL Reserves Quantities and Standardized Measure of Future Cash Flows

We use the successful efforts method of accounting for natural gas producing activities. Under this method, the costs to acquire mineral interests in natural gas properties, to drill and equip exploratory leases that find proved reserves, and to drill and equip development leases and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized, or suspended, pending determination of whether the wells have proved reserves. If we determine the wells do not have proved reserves, the costs are charged to expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if sufficient reserves have been found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. We reassess the operational viability of our exploratory wells on at least a quarterly basis, which may involve use of significant judgment. If we determine that future appraisal drilling or development activities are unlikely to occur, the associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year.

The processes we use to estimate quantities of proved and unproved developed natural gas, NGL, and oil reserves and their values, future production rates, and future development costs are highly complex and requires significant subjectivity and estimation in the evaluation of available geological, engineering, and economic data. The accuracy of any reserves estimate is a function of the quality of data available and of engineering and geological interpretation. The data used in developing reserves estimates may change significantly over time as a result of numerous factors, including, but not limited to, evolving production history, additional development activity, and continual reassessment of the viability of production under varying economic conditions. Although we take every reasonable effort to ensure our reserves estimates are

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representative of our actual reserves — for example, by involving independent reserves engineers in the assessment of the estimates — the subjective decisions and variances in the data available could give rise to revisions that could materially impact the accompanying historical consolidated financial statements.

Impairment of Natural Gas Properties

The evaluation of impairment of proved and unproved natural gas properties is considered a critical accounting policy due to the significant judgment and estimation involved in ascertaining the probability of future events, such as future market values of natural gas, NGLs, and oil, future production costs, and future production volumes, as well as fair valuation of the properties in question. Changes in the judgments and estimates used in our evaluation of impairment, including, but not limited to, the expected future cash flows from natural gas reserves on our properties, could result in the cost of our proved and unproved properties not being recoverable and give rise to the need to record an impairment loss. Similarly, in the instance we determine the property is not recoverable, changes in the estimates and assumptions underlying the model used to derive the fair value of the properties in question may impact the output of the model, which could give rise to significant changes in the amount of impairment loss to record.

Litigation and Environmental Contingencies

In the ordinary course of business, we may at times be subject to claims and legal actions. Management does not believe the impact of such matters will have a material adverse effect on our financial position or results of operations.

We are subject to extensive federal, state, and local environmental laws and regulations, which may materially affect our operations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.

In our acquisition of existing assets, we may not be aware of what environmental safeguards were taken during the time such assets were operated, and it is possible we may acquire certain environmental liabilities along with such assets.

We maintain comprehensive insurance coverage that we believe is adequate to mitigate the risk of any adverse financial effects associated with these risks. However, should it be determined that a liability exists with respect to any environmental cleanup or restoration, the liability to cure such a violation could still fall upon us. No claim has been made, nor are we aware of any liability which we may have, as it relates to any material environmental cleanup, restoration, or the violation of any rules or regulations relating thereto.

Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed as incurred. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the cost can be reasonably estimated.

Recent Accounting Pronouncements

See Note 2 - Summary of Significant Accounting Policies to our consolidated financial statements included in this Annual Report on Form 10-K for more information about recent accounting pronouncements, the timing of their adoption, and our assessment, to the extent we have made one, of their potential impact on our financial condition and our results of operations.

Emerging Growth Company Status

We are an “emerging growth company” as defined under 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 Annual Report on Form 10-K 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

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$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.