May 7, 2026 - 10-Q: Quarterly report [Sections 13 or 15(d)]

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________

FORM 10-Q

_________________________

(Mark One)


x			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2026


o			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-42282

_________________________

BKV CORPORATION

(Exact name of registrant as specified in its charter)

_________________________


Delaware						85-0886382
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

1200 17th Street, Suite 2100 Denver, Colorado						80202
(Address of Principal Executive Offices)						(Zip Code)

(720) 375-9680

Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.01 Par Value	BKV	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o No x

As of April 30, 2026, 109,386,611 shares of the registrant's common stock were outstanding.

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Glossary of Commonly Used Terms

Cautionary Note Regarding Forward-Looking Statements

PART I FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

Condensed Consolidated Balance Sheets			11

Condensed Consolidated Statements of Operations			13

Condensed Consolidated Statements of Cash Flows			14

Condensed Consolidated Statements of Stockholders' Equity and Mezzanine Equity			16

Notes to the Condensed Consolidated Financial Statements			17

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			42

Item 3. Quantitative and Qualitative Disclosures About Market Risk			57

Item 4. Controls and Procedures			59

PART II OTHER INFORMATION

Item 1. Legal Proceedings			60

Item 1A. Risk Factors			60

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			60

Item 3. Defaults Upon Senior Securities			60

Item 4. Mine Safety Disclosures			60

Item 5. Other Information			60

Item 6. Exhibits			61

Signatures			63

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Glossary of Commonly Used Terms

“2025 Equity Offering” refers to the underwritten public offering of 6,900,000 shares of our common stock completed on December 3, 2025 for net proceeds of $170.1 million.

“2026 Equity Offering” refers to the underwritten public offering of 7,003,813 shares of our common stock offered by the Company and 4,142,089 shares of our common stock offered by Bedrock as the selling stockholder completed on March 12, 2026 for net proceeds to the Company of $186.2 million.

“2030 Senior Notes” refers to the $500.0 million aggregate principal amount of 7.50% senior unsecured notes due 2030 issued by BKV Upstream Midstream.

“ABR” refers to the alternative borrowing rate.

“Banpu” refers to our sponsor, Banpu Public Company Limited, a public company listed on the Stock Exchange of Thailand and the ultimate parent company of BKV Corporation, BNAC, Banpu Power, and BPPUS.

“Banpu Power” refers to Banpu Power Public Company Limited, a public company listed on the Stock Exchange of Thailand. Banpu owns approximately 91.1% of Banpu Power as of March 31, 2026.

“Barnett” refers to the Barnett Shale in the Fort Worth Basin of Texas.

“Barnett Zero Project” refers to BKV dCarbon Barnett Zero, LLC, a Delaware limited liability company and, as of May 8, 2025, a wholly-owned subsidiary of the BKV-CIP Joint Venture.

“Bbl” refers to one stock tank barrel, of 42 U.S. gallons liquid volume, used in this Quarterly Report on Form 10-Q in reference to crude oil or other liquid hydrocarbons.

“Bcf” refers to one billion cubic feet of natural gas or CO2.

“Bcfe” refers to one billion cubic feet of natural gas equivalent.

“Bedrock” refers to Bedrock Energy Partners, LLC.

“Bedrock Acquisition” refers to the acquisition by BKV Upstream Midstream of 100% of the equity interests of BKV Barnett II (formerly known as Bedrock Production, LLC) from Bedrock, which closed on September 29, 2025.

“Bedrock Purchase Agreement” refers to that certain Membership Interest Purchase Agreement entered into on August 7, 2025, with an economic effectiveness date of July 1, 2025 by and among BKV Upstream Midstream and Bedrock and, solely for certain limited purposes set forth therein, the Company and certain subsidiaries of Bedrock.

“BKV Barnett II” refers to BKV Barnett II, LLC (formerly known as Bedrock Production, LLC), a Texas limited liability company and, following its acquisition on September 29, 2025, a wholly-owned subsidiary of BKV Upstream Midstream. BKV Barnett II and its subsidiaries own certain oil and gas producing properties and midstream assets in the Barnett Shale, including approximately 96,000 net acres, 1,121 operated wells, and related natural gas upstream, midstream, and other assets.

“BKV-BPP Cotton Cove” or “BKV-BPP Cotton Cove Joint Venture” refers to BKV-BPP Cotton Cove, LLC, a Delaware limited liability company and the joint venture between BKV dCarbon Ventures and BPPUS, in which we currently own a 51% interest.

“BKV-BPP Power” or “BKV-BPP Power Joint Venture” refers to BKV-BPP Power LLC, a Delaware limited liability company and the joint venture between BKV Corporation and BPPUS, in which we owned a 50% interest as of December 31, 2025. Following the closing of the BKV-BPP Power Joint Venture Transaction on January 30, 2026, the BKV-BPP Power Joint Venture is owned 75% by BKV and 25% by BPPUS.

“BKV-BPP Power Joint Venture Transaction” refers to BKV’s acquisition of an additional 25% interest in the BKV-BPP Power Joint Venture from BPPUS, which closed on January 30, 2026.

“BKV-BPP Power Purchase Agreement” refers to that certain Membership Interest Purchase Agreement, dated as of October 29, 2025, by and between the Company and BPPUS.

“BKV-BPP Retail” refers to BKV-BPP Retail, LLC, a Delaware limited liability company and wholly-owned subsidiary of the BKV-BPP Power Joint Venture.

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“BKV-CIP Joint Venture” refers to BKV dCarbon Project, LLC, a Delaware limited liability company and the joint venture between BKV dCarbon Ventures and C Squared Solutions, Inc., in which we currently own a 51% interest.

“BKV-CIP JV Agreement” refers to the Limited Liability Company Agreement of BKV dCarbon Project, LLC, entered into on May 8, 2025, by BKV dCarbon Ventures, C Squared Solutions, Inc. and, for the limited purposes specified therein, BKV Corporation.

“BKV dCarbon Ventures” refers to BKV dCarbon Ventures, LLC, a Delaware limited liability company, a wholly-owned subsidiary, and the CCUS business of BKV Corporation.

“BKV Upstream Midstream” refers to BKV Upstream Midstream, LLC, a Delaware limited liability company and wholly-owned subsidiary of BKV Corporation.

“BNAC” refers to Banpu North America Corporation, a subsidiary of Banpu, our sponsor, and the majority stockholder of BKV Corporation.

“BPPUS” refers to Banpu Power US Corporation, a wholly-owned subsidiary of Banpu Power and the owner of a 50% interest in the BKV-BPP Power Joint Venture and a 49% interest in the BKV-BPP Cotton Cove Joint Venture as of December 31, 2025. Following the closing of the BKV-BPP Power Joint Venture Transaction on January 30, 2026, BPPUS owns a 25% interest in the BKV-BPP Power Joint Venture.

“Btu” refers to British thermal unit, which is the heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit.

“Carbon Sequestered Gas” refers to a Scope 1, 2, and 3 carbon neutral natural gas product.

“CCUS” refers to carbon capture, utilization, and sequestration.

“Class B Member” refers to C Squared Solutions, Inc, a subsidiary of the Energy Transition Fund managed by Copenhagen Infrastructure Partners (CIP).

“CO2” refers to carbon dioxide.

“CO2e” refers to carbon dioxide equivalent.

“Code” means the Internal Revenue Code of 1986, as amended.

“Corporate and Other” refers to the Company’s operating segment, which is an "All Other" category that includes the CCUS business line.

“developed reserves” are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Devon Barnett Acquisition” refers to our acquisition of more than 289,000 net acres, 3,850 producing operated wells and related upstream assets in the Barnett from Devon Energy Corporation, which closed in October 2020.

“ERCOT” refers to the Electric Reliability Council of Texas.

“ESG” refers to environmental, social, and governance.

“ESPP” refers to the Company’s Employee Stock Purchase Plan.

“GAAP” refers to generally accepted accounting principles in the United States.

“GHG” refers to greenhouse gases.

“GWh” refers to gigawatt hour.

“HRCO” refers to a heat rate call option, which is a contract 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.

“LNG” refers to liquefied natural gas.

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“MBbls” refers to one thousand barrels of crude oil or other liquid hydrocarbons.

“Mcf” refers to one thousand cubic feet.

“Mcf/d” refers to one thousand cubic feet per day.

“Mcfe” refers to one thousand cubic feet of natural gas equivalent.

“MMBtu” refers to one million British thermal units, which is the heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit.

“MMcf” refers to one million cubic feet.

“MMcf/d” refers to one million cubic feet per day.

“MMcfe” refers to one million cubic feet of natural gas equivalent, calculated by converting barrels of crude oil or other liquid hydrocarbons to natural gas at a ratio of one Bbl to six Mcf of natural gas. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

“MMcfe/d” refers to one million cubic feet of natural gas equivalent per day.

“MW” refers to megawatt.

“MWh” refers to megawatt hour.

“NEPA” refers to the Marcellus Shale in the Appalachian Basin of Northeast Pennsylvania.

“net acres” refers to the percentage of total acres an owner has out of a particular number of acres, or a specified tract. For example, an owner who has 50% interest in 100 acres owns 50 net acres.

“net zero” refers to the full elimination and/or offset of Scope 1, Scope 2, and/or Scope 3 emissions, as applicable, from our owned and operated upstream businesses.

“NGL” refers to natural gas liquids.

“NYMEX” refers to the New York Mercantile Exchange.

“OPEC” refers to the Organization of the Petroleum Exporting Countries.

“OPIS” refers to a Dow Jones Company that surveys and collects price information and publishes benchmarks for various energy commodities.

“Pad of the Future” refers to our program of converting natural gas-powered instrument pneumatics to compressed air or electric power instruments on existing pads, combined with emission and leak surveys.

“Power segment” refers to the Company’s reportable segment that includes the power generation business line.

“proved developed producing reserves” or “PDP reserves” refers to quantities of proved developed reserves expected to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

“proved reserves” refers to quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and

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reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (a) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (b) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“RBL Credit Agreement” refers to that certain reserve-based lending agreement dated as of June 11, 2024, as amended from time to time, among BKV Corporation, BKV Upstream Midstream, Citibank, N.A., as administrative agent, and the financial institutions party thereto.

“Scope 1 emissions” refers to direct GHG emissions that occur from sources that are controlled or owned by an organization.

“Scope 2 emissions” refers to indirect GHG emissions associated with the purchase of electricity, steam, heat or cooling.

“Scope 3 emissions” refers to GHG emissions that result from the end use of an organization’s products, as estimated per Category 11 (Use of Sold Product), as well as emissions from other business activities from assets not owned or controlled by the organization but that the organization indirectly impacts in its value chain.

“Section 45I tax credits” refers to tax credits provided under Section 45I of the Code.

“Section 45Q tax credits” refers to tax credits provided under Section 45Q of the Code.

“SOFR” refers to the secured overnight financing rate.

“Temple Credit Facilities” refers to, collectively, the Temple Revolving Facility and Temple Term Loan Facility.

“Temple Generation I” refers to Temple Generation I, LLC, a subsidiary of Temple Intermediate II.

“Temple Generation II” refers to Temple Generation II, LLC, a subsidiary of Temple Intermediate II.

“Temple Generation SF” refers to Temple Generation SF LLC, an indirect subsidiary of BKV-BPP Power in which Temple Generation I and Temple Generation II each own a 50% interest.

“Temple I” refers to the first combined gas turbine and steam turbine power plant located in Temple, Texas and owned by the BKV-BPP Power Joint Venture.

“Temple I Loan Agreements” refers to, collectively, the $141 Million Banpu Loan Agreement and $141 Million BPPUS Loan Agreement, each as defined herein.

“Temple II” refers to a second combined gas turbine and steam turbine power plant located in Temple, Texas, which power plant sits on the same site as Temple I and is owned by the BKV-BPP Power Joint Venture.

“Temple Intermediate II” refers to Temple Generation Intermediate Holdings II, LLC, an indirect subsidiary of BKV-BPP Power.

“Temple Plants” refers to Temple I and Temple II, collectively.

“Temple Revolving Facility” refers to the senior secured revolving credit facility associated with the Beal Credit Agreement with a maximum aggregate principal amount of $60.0 million.

“Temple Term Loan Facility” refers to the senior secured term loan facility associated with the Beal Credit Agreement with an aggregate principal amount of $500.0 million.

“undeveloped reserves” refers to reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted

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indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

“Upstream/Midstream segment” refers to the Company’s reportable segment that includes its natural gas production and natural gas midstream business lines.

“working interest” refers to the right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

“WTI” refers to West Texas Intermediate light sweet crude oil.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact contained in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenue and losses, projected costs, prospects, plans and objectives of management and dividend policy, are forward-looking statements. When used in this Quarterly Report on Form 10-Q, words such as “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “seek,” “envision,” “forecast,” “target,” “predict,” “may,” “should,” “would,” “could,” “will,” the negative of these terms and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such forward-looking statements include, but are not limited to, the anticipated benefits, opportunities and results with respect to the BKV-BPP Power Joint Venture Transaction, including any expected value creation from the BKV-BPP Power Joint Venture Transaction, and any anticipated efficiencies, power plant reliability, and strategic growth and power purchase agreement opportunities relating to the BKV-BPP Power Joint Venture and the BKV-BPP Power Joint Venture Transaction, as well as guidance, projected or forecasted financial and operating results, future liquidity, leverage, results in certain basins, objectives, project timing, utility of reporting segment changes, expectations and intentions, regulatory and governmental actions, and other statements that are not historical facts. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

Forward-looking statements contained in this Quarterly Report on Form 10-Q include, but are not limited to, statements about:

•our business strategy;

•our reserves;

•our financial strategy, liquidity, and capital required for our development programs;

•our relationship with our sponsor, Banpu and its affiliates, including future agreements with Banpu;

•actual and potential conflicts of interest relating to Banpu, its affiliates, and other entities in which members of our officers and directors are or may become involved;

•volatility in natural gas, NGL, and oil prices;

•our dividend policy;

•our drilling plans and the timing and amount of future production of natural gas, NGL, and oil;

•our hedging strategy and results;

•competition and government regulation;

•changes in trade regulation, including tariffs and other market factors;

•legal, regulatory, or environmental matters;

•marketing of natural gas, NGL, and oil;

•business or leasehold acquisitions and integration of acquired businesses, including the Bedrock Acquisition, with our business;

•our ability to develop existing prospects;

•costs of developing our properties and of conducting our operations;

•our plans to establish midstream contracts that allow us to supply our own natural gas directly to the Temple Plants;

•our plan to continue to build out our power generation business and to expand into retail power;

•our ability to develop, produce, and sell Carbon Sequestered Gas;

•our ability to effectively operate and grow our CCUS business;

•our ability to forecast annual CO2 sequestration rates for our CCUS projects;

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•our ability to reach final investment decision and execute and complete any of our pipeline of identified CCUS projects;

•our ability to identify and complete additional CCUS projects as we expand our upstream operations;

•our ability to effectively operate and grow our retail power business;

•our anticipated Scope 1, 2, and 3 emissions from our owned and operated upstream and natural gas midstream businesses and our sustainability plans and goals, including our plans to offset our Scope 1, 2, and 3 emissions from our owned and operated upstream and natural gas midstream businesses;

•our ESG strategy and initiatives, including those relating to the generation and marketing of environmental attributes or new products seeking to benefit from ESG-related activities, and the continuation of government tax incentives applicable thereto;

•general economic conditions;

•cost inflation;

•credit markets;

•our ability to service our indebtedness;

•our ability to expand our business, including through the recruitment and retention of skilled personnel;

•our future operating results;

•the remediation of our material weakness;

•the Bedrock Acquisition and the anticipated benefits thereof;

•BKV-BPP Power Joint Venture Transaction and the anticipated benefits thereof;

•the impact of the One Big Beautiful Bill Act of 2025 (the “OBBBA”); and

•our plans, objectives, expectations, and intentions.

When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2025 (“2025 Annual Report on Form 10-K”). These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statements made in this Quarterly Report on Form 10-Q to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q or to reflect new information or the occurrence of unanticipated events, except as required by law.

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PART I FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

BKV Corporation

Condensed Consolidated Balance Sheets
(in thousands, except par value)

(Unaudited)

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	March 31, 2026		December 31, 2025 (1)
Assets
Current assets
Cash and cash equivalents	$	288,536	$	248,427
Restricted cash	15,974		15,846
Accounts receivable, net	141,722		129,077
Accounts receivable, related parties	11,282		11,196

Prepaid expenses	13,258		14,720
Inventory	18,761		20,039
Commodity derivative assets, current	72,216		63,900



Other current assets	6,245		8,150
Total current assets	567,994		511,355
Natural gas properties and equipment
Developed properties	3,016,204		2,965,638
Undeveloped properties	13,416		13,182
Midstream assets	278,340		277,974
Accumulated depreciation, depletion, and amortization	(884,546)		(849,464)
Total natural gas properties, net	2,423,414		2,407,330
Other property and equipment, net	1,057,960		944,412
Deposits	48,402		14,247


Goodwill	18,417		18,417



Commodity derivative assets	36,422		26,432
Other noncurrent assets	18,923		17,064
Total assets	$	4,171,532	$	3,939,257

Liabilities, mezzanine equity, and equity
Current liabilities
Accounts payable and accrued liabilities	$	217,441	$	229,487




Commodity derivative liabilities, current	17,526		8,469
Income taxes payable to related party	978		810
Payable to BPPUS for the BKV-BPP Power Joint Venture Transaction	—		115,136
Current portion of Temple I Loan Agreements	176,000		191,000
Current portion of long-term debt, net	9,387		9,387
Other current liabilities	11,248		10,302
Total current liabilities	432,580		564,591
Asset retirement obligations	197,014		230,372

Commodity derivative liabilities	1,160		5,767


Deferred tax liability, net	140,139		128,839
Long-term debt, net	1,080,913		937,724
Other noncurrent liabilities	8,638		5,223
Total liabilities	1,860,444		1,872,516
Commitments and contingencies (Note 11)
Mezzanine equity
Noncontrolling interest	18,622		12,951
Stockholders' equity
Common stock, $0.01 par value; 500,000 authorized shares; 109,385 and 96,872 shares issued and outstanding as of March 31, 2026 and December 31, 2025, respectively	1,760		1,635
Treasury stock, shares at cost; 214 shares as of March 31, 2026 and December 31, 2025	(6,663)		(6,663)
Additional paid-in capital	1,864,963		1,676,785
Retained earnings	352,385		309,051
Total stockholders' equity	2,212,445		1,980,808
Noncontrolling interest	80,021		72,982


The accompanying notes are an integral part of these condensed consolidated financial statements.			11


Total equity	2,292,466		2,053,790
Total liabilities, mezzanine equity, and equity	$	4,171,532	$	3,939,257

_______________________________________

(1) The financial information presented in this Quarterly Report on Form 10-Q has been retrospectively adjusted for the BKV-BPP Power Joint Venture Transaction, which was accounted for as a transaction between entities under common control, with prior periods recast as if the transaction had occurred at the beginning of the earliest period presented. See Note 2 - Acquisition for further information.


The accompanying notes are an integral part of these condensed consolidated financial statements.			12

BKV Corporation

Condensed Consolidated Statements of Operations
(in thousands, except per share amounts)

(Unaudited)

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	Three Months Ended March 31,
		2026		2025 (1)
Revenues and other operating income
Natural gas, NGL, and oil sales		$	287,675	$	216,126
Midstream revenues		2,296		2,771
Derivative gains (losses), net		53,109		(98,383)
Marketing revenues		17,585		9,686



Section 45Q tax credits		3,060		3,307

Power revenues		68,990		43,864

Other		132		(1,305)
Total revenues and other operating income		432,847		176,066
Operating expenses
Lease operating and workover		45,075		35,055
Fuel commodity costs		57,121		46,363
Purchased power		27,355		18,667
Taxes other than income		20,202		14,790
Gathering and transportation		67,802		55,793
Depreciation, depletion, amortization, and accretion		52,941		49,597
Power operating and maintenance		19,679		20,213
General and administrative		42,130		29,069
Other operating expenses		14,516		6,616
Total operating expenses		346,821		276,163
Income (loss) from operations		86,026		(100,097)
Other income (expense)
Interest expense		(22,830)		(16,049)
Interest expense, related party		(4,269)		(5,076)
Interest income		1,498		749
Other income		2,888		3,034
Income (loss) before income taxes		63,313		(117,439)
Income tax benefit (expense)		(11,469)		30,668
Net income (loss)		51,844		(86,771)
Less: net income (loss) attributable to noncontrolling interest		7,769		(4,792)
Net income (loss) attributable to BKV		$	44,075	$	(81,979)

Net income (loss) per common share attributable to BKV:
Basic		$	0.42	$	(0.97)
Diluted		$	0.42	$	(0.97)

Weighted average number of common shares outstanding:
Basic		102,018		84,706
Diluted		102,304		84,706

___________________________________________________


The accompanying notes are an integral part of these condensed consolidated financial statements.			13

BKV Corporation

Condensed Consolidated Statements of Cash Flows
(in thousands)

(Unaudited)

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	Three Months Ended March 31,
	2026		2025 (1)
Cash flows from operating activities:
Net income (loss)	$	51,844	$	(86,771)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	54,165		49,711
Equity-based compensation expense	3,907		2,067
Deferred income tax expense (benefit)	11,300		(31,098)
Unrealized (gains) losses on derivatives, net	(13,856)		147,035
Impairment of asset held for sale	—		2,446
Settlement of contingent consideration	—		(20,000)
Payments for the purchase of put options	—		(16,206)
Other, net	1,905		2,850
Changes in operating assets and liabilities:
Accounts receivable, net	(13,443)		(12,805)
Accounts receivable, related party	(86)		(262)





Accounts payable and accrued liabilities	(23,470)		(26,036)




Other changes in operating assets and liabilities	(277)		5,522
Net cash provided by operating activities	71,989		16,453
Cash flows from investing activities:
Asset acquisition	(93,414)		—
Deposits on fixed asset purchases	(33,050)		—
Capital expenditures	(106,527)		(57,612)
Proceeds from sales of assets	171		1,109
Other investing activities, net	—		257
Net cash used in investing activities	(232,820)		(56,246)
Cash flows from financing activities:
Proceeds from issuance of common stock, net of underwriting discounts and commissions	186,174		—
Acquisition of affiliate (common control)	(115,136)		—
Payment of debt issuance costs	(892)		—
Payments on Temple Term Loan Facility	(2,500)		(2,500)
Proceeds from Promissory Note	46,000		—
Payments on Temple I Loan Agreements	(15,000)		—
Proceeds under RBL Credit Agreement	330,000		170,000
Payments on RBL Credit Agreement	(230,000)		(135,000)




Net share settlements, equity-based compensation	(2,055)		(1,181)
Cash contributions from noncontrolling interest	4,200		—
Common stock issued from employee purchase plan	277		—
Net cash provided by financing activities	201,068		31,319
Net increase (decrease) in cash, cash equivalents, and restricted cash	40,237		(8,474)
Cash, cash equivalents, and restricted cash, beginning of period	264,273		96,998
Cash, cash equivalents, and restricted cash, end of period	$	304,510	$	88,524

___________________________________________________


The accompanying notes are an integral part of these condensed consolidated financial statements.			14

BKV Corporation

Condensed Consolidated Statements of Cash Flows
(in thousands)

(Unaudited)

Table of Contents


	Three Months Ended March 31,
Supplemental cash flow information:	2026		2025 (1)
Cash payments for:
Interest	$	11,406	$	15,331

Non-cash investing and financing activities:



Increase in accrued capital expenditures	$	11,440	$	487
Additions to asset retirement obligations	$	40	$	35
Lease liabilities arising from obtaining right-of-use assets	$	5,040	$	—
Modification of lease contracts	$	(853)	$	—
Revision of asset retirement obligations	$	(35,172)	$	—


Issuance of common stock to BPPUS	$	53	$	—
Accretion of Class B Units to redemption value	$	741	$	—

___________________________________________________


The accompanying notes are an integral part of these condensed consolidated financial statements.			15

BKV Corporation

Condensed Consolidated Statements of Equity and Mezzanine Equity
(in thousands)

(Unaudited)

Table of Contents


	Equity														Mezzanine Equity
	Common Stock			Treasury			Additional Paid-In Capital		Retained Earnings		Noncontrolling Interest		Total Equity		Noncontrolling Interest
	Shares	Amount		Shares	Amount
Balance, December 31, 2025 (1)	96,872	$	1,635	214	$	(6,663)	$	1,676,785	$	309,051	$	72,982	$	2,053,790	$	12,951
Net income	—	—		—	—		—		44,075		7,039		51,114		730
Contributions from noncontrolling interest	—	—		—	—		—		—		—		—		4,200
Accretion of Class B Units to redemption value	—	—		—	—		—		(741)		—		(741)		741
Issuance of common stock, net	7,004	70		—	—		186,104		—		—		186,174		—
Issuance of common stock to BPPUS	5,315	53		—	—		(53)		—		—				—
Issuance of common stock under equity incentive plans, net	16	—		—	—		277		—		—		277		—
Common stock issued upon vesting of restricted stock units, net of shares withheld for income taxes	178	2		—	—		(2,057)		—		—		(2,055)		—
Equity-based compensation	—	—		—	—		3,907		—		—		3,907		—
Balance, March 31, 2026	109,385	$	1,760	214	$	(6,663)	$	1,864,963	$	352,385	$	80,021	$	2,292,466	$	18,622


	Equity														Mezzanine Equity
	Common Stock			Treasury			Additional Paid-In Capital		Retained Earnings		Noncontrolling Interest		Total Equity (1)		Noncontrolling Interest
	Shares	Amount		Shares	Amount
Balance, December 31, 2024	84,600	$	1,512	214	$	(6,663)	$	1,369,526	$	131,316	$	56,829	$	1,552,520	$	—
Net loss	—	—		—	—		—		(81,979)		(4,792)		(86,771)		—
Common stock issued upon vesting of restricted stock units, net of shares withheld for income taxes	108	1		—	—		(1,182)		—		—		(1,181)		—
Equity-based compensation	—	—		—	—		2,067		—		—		2,067		—
Balance, March 31, 2025	84,708	$	1,513	214	$	(6,663)	$	1,370,411	$	49,337	$	52,037	$	1,466,635	$	—

___________________________________________________


The accompanying notes are an integral part of these condensed consolidated financial statements.			16

Table of Contents

BKV Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

Note 1 - Business and Basis of Presentation

General

BKV Corporation (“BKV Corp”) was formed on May 1, 2020 and is a corporation registered with the State of Delaware. BKV Corp is a growth-driven energy company focused on creating value for its shareholders through organic development of its properties, as well as accretive acquisitions. BKV Corp’s core business is to produce natural gas from its owned and operated upstream businesses.

The majority shareholder of BKV Corp is BNAC. BKV Corp’s ultimate parent company is Banpu Public Company Limited ("Banpu"), a public company listed in the Stock Exchange of Thailand. As of April 30, 2026, Banpu, the ultimate parent company of BNAC and BPPUS, indirectly owned an aggregate 62.8% of BKV Corp's shares. The remaining 37.2% of shares of common stock of BKV Corp were owned by non-controlling members of management, members of the board of directors, and employee and non-employee shareholders.

Basis of Presentation of the Unaudited Condensed Consolidated Financial Statements and Principles of Consolidation

These condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts for BKV Corp’s wholly-owned subsidiaries and majority-owned subsidiaries in which BKV Corp has a controlling interest. The condensed consolidated financial statements are unaudited and should be read in conjunction with the Company’s 2025 Annual Report on Form 10-K, as certain disclosures and information required by GAAP for complete consolidated financial statements have been condensed or omitted. The condensed consolidated financial statements, in the opinion of management, reflect all adjustments, which include normal and recurring adjustments, necessary to fairly state the Company’s financial position, results of operations, and cash flows for the periods presented herein. The interim results are not necessarily indicative of results to be expected for the year ending December 31, 2026 or for any other future annual or interim period. The December 31, 2025 condensed consolidated balance sheet was derived from the Company's 2025 Annual Report on Form 10-K; however, it has been retrospectively recast to reflect the historical results of BKV-BPP Power LLC, a Delaware limited liability company (“BKV-BPP Power” or the “BKV-BPP Power Joint Venture”), as described below. Accordingly, amounts as of December 31, 2025 and for the three months ended March 31, 2025 differ from those previously reported.

In addition, as discussed further in Note 14 - Reportable Segments, certain prior period amounts have been recast to reflect the Company's change in reportable segments from one reportable segment and one operating segment to two reportable segments consisting of Upstream/Midstream and Power, and one operating segment consisting of Corporate and Other.

Together, BKV Corp, its wholly-owned subsidiaries, and its majority-owned subsidiaries where BKV Corp has a controlling interest and is the primary beneficiary, are referred to collectively as “BKV” or the “Company.” All intercompany balances and transactions between these entities have been eliminated within the condensed consolidated financial statements. Current and deferred income taxes and related tax expense have been determined based on the stand-alone results of BKV by applying the separate return method to BKV’s operations as if it were a separate taxpayer.

Common Control Transaction

On January 30, 2026, the Company completed the previously announced acquisition of an additional 25% interest in the BKV-BPP Power Joint Venture (the "BKV-BPP Power Joint Venture Transaction"), pursuant to that certain membership interest purchase agreement, dated as of October 29, 2025, by and between the Company and BPPUS, an affiliate under common control (the "BKV-BPP Power Purchase Agreement"). In connection with such closing, the Company and BPPUS entered into an Amended and Restated Limited Liability Company Agreement (the "BKV-BPP Power LLC Agreement"), which governs BKV-BPP Power. Banpu indirectly holds the controlling financial interests in both the Company and BPPUS, and as such, the BKV-BPP Power Joint Venture Transaction was accounted for as a transfer of assets between entities under common control in accordance with Accounting Standards Codification ("ASC") 805-50, Business Combinations - Related Issues. Transfers of net assets between entities under common control are accounted for at the historical carrying values of the transferring entity as of the date of transfer, and no gain or loss is recognized. The Company recognized the difference between the consideration transferred and the historical carrying value of the net assets received as an adjustment to equity. Because the BKV-BPP Power Joint Venture


			17

Table of Contents

Transaction represents a common-control transfer, the Company retrospectively recast its condensed consolidated financial statements to include the historical results of BKV-BPP Power Joint Venture for all periods during which the Company and BKV-BPP Power were under common control. As a result of the BKV-BPP Power Joint Venture Transaction, the Company is considered the primary beneficiary of BKV-BPP Power and consolidated BKV-BPP Power’s financial results in accordance with ASC 810, Consolidation. See Note 2 - Acquisition and Note 10 - Investments for further information.

Reclassification

Certain prior period amounts have been reclassified in order to conform to the current period presentation. These reclassifications had no impact on previously reported balance sheets, net income (loss), net cash flows, or stockholders’ equity. In addition, the Company recast its prior period condensed consolidated financial statements as further described in Note 2 - Acquisition and Note 10 - Investments. The recast impacted previously reported financial statement line items.

2026 Equity Offering

On March 12, 2026, the Company completed the 2026 Equity Offering (as defined below). See Note 9 - Stockholders' Equity for further detail.

Liquidity

As of March 31, 2026, the Company held $288.5 million of cash and cash equivalents. The Company’s working capital as of March 31, 2026, was $135.4 million, and for the three months ended March 31, 2026, cash flows provided by operating activities was $72.0 million. The Company intends to make the payments related to its debt and investments in capital expenditures with cash flows from operations.

Restricted Cash

As of March 31, 2026, restricted cash included amounts to fund the debt service reserve account, or the quarterly portion due on the Temple Term Loan Facility (as defined below) plus accrued interest and cash collateral held in connection with certain retail customers.


(in thousands)	March 31, 2026		December 31, 2025
Cash and cash equivalents	$	288,536	$	248,427
Restricted cash	15,974		15,846
Cash, cash equivalents, and restricted cash	$	304,510	$	264,273

Significant Judgments and Accounting Estimates

The preparation of these condensed consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and the accompanying notes. In connection with the consolidation of the BKV-BPP Power Joint Venture during the period, management has made significant judgments and estimates related to (i) the valuation of commodity derivative instrument and (ii) estimates of revenues earned and not yet billed and costs incurred and not yet billed. Actual results could differ from these estimates, and such differences may be material to the Company's financial position and results of operations.

Other than the items described above, there have been no significant changes to the Company's accounting estimates from those disclosed in the Company's 2025 Annual Report on Form 10-K.

Significant Accounting Policies

The Company's significant accounting policies are described in the notes to the consolidated financial statements for the year ended December 31, 2025, which are disclosed in the 2025 Annual Report on Form 10-K. There have been no significant changes in accounting policies during the three months ended March 31, 2026 and 2025.

In connection with the consolidation of the BKV-BPP Power Joint Venture during the period, the Company evaluated BKV-BPP Power's accounting policies and determined they are consistent with the Company's accounting policies as disclosed in the Company's 2025 Annual Report on Form 10-K. Accordingly, no adjustments to conform accounting policies were required upon consolidation.


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Table of Contents

Common Shares Issued and Outstanding

As of March 31, 2026 and December 31, 2025, the Company had common shares issued and outstanding of 109,385,430 and 96,871,868, respectively.

Accounting Pronouncements Not Yet Adopted

In November 2024, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2024-03, Disaggregation of Income Statement Expenses. This standard requires that entities (i) disclose amounts of purchases of inventory, employee compensation, and depreciation, depletion, and amortization, including those recognized as part of oil and gas-producing activities (or other amounts of depletion expense) included in each relevant expense caption, (ii) include certain amounts that are already required to be disclosed under current GAAP in the same disclosure as the other disaggregation requirements, (iii) disclose a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively, and (iv) disclose the total amount of selling expenses and, in annual reporting periods, an entity’s definition of selling expenses. This standard is effective January 1, 2027, with early adoption permitted. Management is currently evaluating the impact this standard will have on the Company’s disclosures.

In September 2025, the FASB issued ASU 2025-06, Targeted Improvements to the Accounting for Internal-Use Software. Under the new standard, companies may capitalize eligible costs when (i) management has authorized and committed to funding the software project, and (ii) it is probable that the project will be completed and the software will be used to perform the function intended. The standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2027, with early adoption permitted as of the beginning of a fiscal year. The standard may be applied prospectively, retrospectively or using a modified transition approach. The Company is currently evaluating the impact that this standard will have on the Company’s consolidated operating results, cash flows, financial condition, and related disclosures.

Note 2 - Acquisition

BKV-BPP Power Joint Venture Transaction

On January 30, 2026, pursuant to the BKV-BPP Power Purchase Agreement, the Company completed the BKV-BPP Power Joint Venture Transaction for an aggregate consideration of $394.6 million, which consisted of $115.1 million in cash and 5,315,390 shares of Company common stock, which shares are subject to a 180-day lock-up. The aggregate purchase price was equal to (x) $376.0 million, less (y) 25% of BKV-BPP Power's net indebtedness at closing, payable 50% in cash and 50% in shares of the Company's common stock. BKV-BPP Power's net indebtedness was $582.9 million as of the closing date and the number of shares issued was determined by dividing the 50% of the aggregate purchase price by $21.6609, which represents the volume-weighted average price of the Company's common stock during the 20 consecutive trading day period ended October 28, 2025. The Company funded the cash consideration for the transaction with a combination of cash on hand and the net proceeds from the 2025 Equity Offering. Following the closing of the transaction, the Company and BPPUS own 75% and 25% of the BKV-BPP Power Joint Venture, respectively.

The Company's condensed consolidated financial statements include $13.0 million of costs associated with the BKV-BPP Power Joint Venture Transaction, $9.3 million related to the 2025 Equity Offering, which was included in additional paid-in capital on the condensed consolidated balance sheets and $3.7 million was expensed and included in other operating expenses on the condensed consolidated statement of operations.

The BKV-BPP Power Joint Venture Transaction was accounted for as an acquisition of a business under common control (see Note 1 - Business and Basis of Presentation for further information). Accordingly, the consolidated financial statements prior to the acquisition date were retrospectively recast to include the BKV-BPP Power Joint Venture's historical results. The Company previously accounted for BKV-BPP Power as an equity method investment and recognized 50% of its earnings. As a result of the consolidation of BKV-BPP Power, the Company determined that the manner in which its Chief Executive Officer, identified as the Chief Operating Decision Maker ("CODM"), evaluates operating performance and allocates resources has changed. Accordingly, BKV-BPP Power, the Company's power generation business, meets the criteria to be presented as a reportable segment. See Note 14 - Reportable Segments.

The following table represents a summary of the retrospective adjustments to the statements of operations for the three months ended March 31, 2025 to conform to the current presentation due to the BKV-BPP Power Joint Venture Transaction.


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Table of Contents


(in thousands)	Three Months Ended March 31, 2025
Increase (decrease) to net loss
Loss from operations	$	(6,394)
Net loss	(8,105)
Less: net loss attributable to noncontrolling interest	(4,792)
Net loss attributable to BKV	$	(3,313)

Net loss per common share attributable to BKV:
Basic	$	(0.04)
Diluted	$	(0.04)

Weighted average number of common shares outstanding:
Basic	84,706
Diluted	84,706

Asset Acquisition

On July 1, 2025, the Company entered into an agreement to acquire approximately 6,200 acres of land and related assets in the state of Texas for a total consideration of $94.3 million, with a deposit of $0.9 million paid in July 2025. The acquisition closed on February 26, 2026. The assets acquired were accounted for as an asset acquisition as the fair value of substantially all the assets acquired were concentrated in a group of similar assets. The Company evaluated the related assets, including structures, easements, and mineral rights, and determined that they were not material, individually or in the aggregate to the total purchase price. Accordingly, the total consideration, including transaction costs was allocated to land. No goodwill was recognized. The Company partially funded the acquisition with $46.0 million in proceeds from the Advance (as defined below), with the remainder funded through the Company's cash from operations. See Note 3 - Debt for further information on the Advance.

Bedrock Acquisition

On September 29, 2025, BKV Upstream Midstream acquired 100% of the equity interests of Bedrock Production, LLC (now known as BKV Barnett II, LLC (“BKV Barnett II”)), a Texas limited liability company (such transaction, the “Bedrock Acquisition”) from Bedrock pursuant to a membership interest purchase agreement (the “Bedrock Purchase Agreement”). The Bedrock Acquisition was accounted for as an asset acquisition. The purchase price allocation was finalized on December 31, 2025. See Note 3 - Acquisitions and Dispositions on the Company's 2025 Annual Report on Form 10-K for additional information, including the allocation of consideration to the assets acquired and liabilities assumed.

During the three months ended March 31, 2026, half of the $37.0 million purchase price holdback was released in accordance with the terms of the Bedrock Purchase Agreement. As of March 31, 2026, the remaining half of holdback balance continues to be held in escrow for potential indemnification claims. In accordance with the terms of the Bedrock Purchase Agreement, the balance remaining in escrow is expected to be released upon the expiration of the 14-month indemnification period following the closing date of September 29, 2025, subject to the resolution of any outstanding claims.

Note 3 - Debt

The following table summarizes the debt balances (refer to the Company's 2025 Annual Report on Form 10-K for definitions and further description of the Company's debt instruments):


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	March 31, 2026		December 31, 2025
(in thousands)	Principal Value		Carrying Value		Principal Value		Carrying Value
Current portion of Temple I Loan Agreements	$	176,000	$	176,000	$	191,000	$	191,000
Current portion of Temple Term Loan Facility	10,000		9,387		10,000		9,387
Total current portion of long-term debt, net	186,000		185,387		201,000		200,387
RBL Credit Agreement	100,000		100,000		—		—
2030 Senior Notes (7.50%)	500,000		486,313		500,000		486,777
Promissory Note	46,000		46,000		—		—
Temple Term Loan Facility	389,383		388,600		391,883		390,947
Temple Revolving Facility	60,000		60,000		60,000		60,000
Total debt, net	1,281,383		1,266,300		1,152,883		1,138,111
Less: current portion of long-term debt	(186,000)		(185,387)		(201,000)		(200,387)
Total long-term debt, net	$	1,095,383	$	1,080,913	$	951,883	$	937,724

RBL Credit Agreement

On June 11, 2024, BKV Corporation, as a guarantor, and BKV Upstream Midstream, as borrower, entered into the RBL Credit Agreement with Citibank, N.A., as the administrative agent, and the financial institutions party thereto. The RBL Credit Agreement includes a maximum credit commitment of $1.5 billion. As of March 31, 2026, the RBL Credit Agreement had a borrowing base of $1.0 billion, an elected commitment of $800.0 million, and the ability to issue up to $40.0 million in letters of credit.

The loans under the RBL Credit Agreement may be borrowed, repaid, and reborrowed during the term of the RBL Credit Agreement. The RBL Credit Agreement will mature on June 12, 2028. The obligations under the RBL Credit Agreement are secured and guaranteed on a senior secured basis by BKV Upstream Midstream and all of BKV Upstream Midstream’s current and future material restricted subsidiaries. BKV Upstream Midstream is obligated to pay certain fees to the lenders and administrative agent under the RBL Credit Agreement, including commitment fees on the average daily amount of the undrawn portion of the commitments. During the three months ended March 31, 2026 and 2025, BKV Upstream Midstream recognized $0.9 million and $0.5 million, respectively, of commitment fees, which are included in interest expense on the condensed consolidated statements of operations.

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

The RBL Credit Agreement requires BKV Upstream Midstream and its restricted subsidiaries to always hedge not less than 50% of reasonably anticipated projected production from their proved developed producing reserves for the subsequent 24 calendar month period immediately following the date financial statements are required to be delivered under the RBL Credit Agreement for each fiscal quarter.

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

• on a quarterly basis, a minimum Current Ratio (as defined in the RBL Credit Agreement) of no less than 1.00 to 1.00; and

• on a quarterly basis, a Net Leverage Ratio (as defined in the RBL Credit Agreement) of no greater than 3.25 to 1.00.

The RBL Credit Agreement includes customary equity cure rights that will enable BKV Upstream Midstream to cure certain breaches of the minimum current ratio covenant or the maximum net leverage ratio covenant (subject to certain limitations in the RBL Credit Agreement). As of March 31, 2026, BKV Upstream Midstream was in compliance with such covenants in the RBL Credit Agreement.


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Financing costs related to the RBL Credit Agreement are deferred and capitalized as debt issuance costs and are included within other assets on the condensed consolidated balance sheets. As of March 31, 2026 and December 31, 2025, $6.3 million and $6.9 million, respectively, of unamortized debt issuance costs remained outstanding.

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

Promissory Note

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

Pursuant to the Promissory Note, the principal amount of the Advance bears interest at a fixed rate of 5.0% per annum and will mature on the earliest of (i) the occurrence of specified credit events, (ii) certain repayment events, and (iii) February 25, 2036. Upon the occurrence of a credit event, including the closing of the underlying property acquisition or the execution of a power purchase agreement, the outstanding principal (or an applicable portion thereof) of the Advance shall be applied as a credit against the purchase payable by the counterparty to the real estate option agreement, or the counterparty's obligations under an executed power purchase agreement, as applicable. The Advance may be prepaid, in whole or in part, without penalty beginning on the third anniversary of the effective date of the real estate option agreement, subject to 30 days' notice. The Promissory Note contains customary covenants and events of default, upon which the lender may accelerate repayment.

BKV-BPP Power Loan Agreements and Credit Facilities

Temple I Loan Agreements

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

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

BKV-BPP Power’s payment obligations under the Temple I Loan Agreements are senior unsecured indebtedness. The Temple I Loan Agreements bear interest at 6-month SOFR plus 5.25% per annum. Interest on the loans is payable on a semi-annual basis, and the loans will mature on November 1, 2026. BKV-BPP Power is permitted to prepay the loans at any time, with no prepayment premium. The Temple I Loan Agreements include covenants that, among other things, prohibit BKV-BPP from merging, incurring liens or incurring any additional indebtedness or guarantees. The Temple I Loan Agreements include financial covenants that require BKV-BPP Power to maintain a minimum net worth (as defined in the Temple I Loan Agreements, but generally meaning total assets minus total liabilities). In the $141 Million Banpu Loan Agreement, the minimum net worth requirement is $120.0 million and in the $141 Million BPPUS Loan Agreement, the minimum net worth requirement is $40.0 million. Under the Temple I Loan Agreements, BNAC and BPPUS have no recourse to BKV Corporation with respect to any amounts owed to them thereunder and BKV Corporation is not liable in any manner (and is not required to provide security) for any obligations owed to BNAC or BPPUS thereunder. As of March 31, 2026 and December 31, 2025, the outstanding principal balance of the Temple I Loan Agreements for each affiliate was $88.0 million and $95.5 million, respectively.

Temple Credit Facilities


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Bank USA and the other lenders from time to time party thereto that provides the following credit facilities (collectively, the “Temple Credit Facilities”): (i) a senior secured term loan facility with an aggregate principal amount of $500.0 million (the “Temple Term Loan Facility”), which was fully drawn in an amount equal to $500.0 million on the closing date, and (ii) a senior secured revolving credit facility in the aggregate principal amount not to exceed $60.0 million (the “Temple Revolving Facility”), which was fully drawn in an amount equal to $60.0 million on the closing date. The interest is payable annually for the Temple Credit Facilities at a rate equal to SOFR plus an interest rate margin of 4.60%.

The Temple Term Loan Facility requires a quarterly repayment at a minimum of $2.5 million per quarter, beginning on September 30, 2023. The final aggregate principal installment for the Temple Term Loan Facility is due and payable on July 10, 2028 (subject to extension by up to two additional one-year periods), and the Temple Revolving Facility terminates five business days prior to the Temple Term Loan Facility maturity date. On the closing date, Temple Intermediate II applied the proceeds of the Temple Term Loan Facility to fund a portion of the Temple II acquisition and applied the proceeds of the Temple Revolving Loan Facility for general corporate purposes, including working capital and operating expenses. Any prepayment of the Temple Term Loan Facility prior to the third anniversary of the closing date thereof is subject to a prepayment penalty. Amounts repaid by Temple Intermediate II with respect to the Temple Term Loan Facility may not be reborrowed. Amounts repaid by Temple Intermediate II with respect to the Temple Revolving Facility may be reborrowed upon satisfaction of customary conditions.

The obligations under the Temple Credit Facilities are secured by (i) all of the assets of Temple Intermediate II, Temple Generation I, Temple Generation II and Temple Generation SF, including the Temple Plants and all other personal property and real property of such entities and (ii) 100.0% of the equity interests in each of Temple Generation I, Temple Generation II, Temple Generation SF, and Temple Intermediate II. This collateral will remain pledged to Beal Bank until all secured obligations under the Temple Loan Facilities have been satisfied in full. Upon the occurrence and continuation of an event of default under either of the Temple Credit Facilities, Beal Bank has customary secured creditor remedies, including the right to foreclose upon the pledged collateral.

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

Note 4 - Natural Gas Properties & Other Property and Equipment

As of March 31, 2026 and December 31, 2025, accumulated depreciation, depletion, and amortization for developed natural gas properties was $859.1 million and $825.7 million, respectively. Depreciation, depletion, and amortization expense for developed natural gas properties was $33.5 million and $31.8 million for the three months ended March 31, 2026 and 2025, respectively.

As of March 31, 2026 and December 31, 2025, accumulated depreciation for midstream assets was $25.4 million and $23.8 million, respectively. Depreciation expense on midstream assets was $1.6 million for each of the three months ended March 31, 2026 and 2025.


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Other property and equipment consisted of the following:


(in thousands)	March 31, 2026		December 31, 2025
Plant facility	$	928,956	$	926,092
Carbon capture, utilization, and sequestration	125,224		114,261
Buildings	6,746		6,746
Furniture, fixtures, equipment, and vehicles	25,221		27,643
Computer software	8,461		8,461
Leasehold improvements	1,685		1,685
Land	102,434		8,090
Construction in process	26,857		6,350
Total	1,225,584		1,099,328
Accumulated depreciation	(167,624)		(154,916)
Other property and equipment, net	$	1,057,960	$	944,412

For the three months ended March 31, 2026 and 2025, depreciation expense for other property and equipment was $13.2 million and $11.0 million, respectively. During the three months ended March 31, 2026 and 2025, the Company received proceeds on the sale of other properties of $0.2 million and $1.1 million, respectively, and recognized a gain on sale of these properties of $0.2 million and $1.1 million, respectively. The gain on sale of other property and equipment is included in other in the condensed consolidated statements of operations.

Impairment of Asset Held for Sale

As of March 31, 2025, the Company approved the plan to sell its field office in Bridgeport, Texas and has classified this asset as held for sale. During the three months ended March 31, 2025, the Company recognized an impairment of $2.4 million based on an estimated selling price of $5.5 million, which was included in other within total revenues and other operating income in the condensed consolidated statements of operations. The Company completed the sale of the field office in the third quarter of 2025 for proceeds of $5.5 million, resulting in no further gain or loss.

Asset Retirement Obligations

The following table summarizes the activities of the Company's asset retirement obligations:


	Three Months Ended March 31,
(in thousands)	2026		2025
Balance, beginning of period	$	233,339	$	201,158

Liabilities incurred	40		35
Liabilities settled	(448)		(623)

Revisions of estimates(1)	(35,172)		—
Accretion of discount	4,015		3,616
Balance, end of period	201,774		204,186
Less current portion	(4,760)		(3,506)
Asset retirement obligations, long-term	$	197,014	$	200,680

___________________________________________________

(1) Revisions of estimates are due to reductions of expected plugging & abandonment cost per well for all Barnett operated properties.

Note 5 - Fair Value Measurements

As the Company uses the market approach to determine the fair value of its derivative instruments, these fair values are also compared to the values given by counterparties for reasonableness. Since natural gas and NGL swaps, fixed-price power sales, and fixed price power purchases are based on measurements derived indirectly from observable inputs or from quoted prices from markets that are less liquid, they are classified as Level 2 within the fair value hierarchy. The heat rate call options are classified


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as Level 3 within the fair value hierarchy because their valuation relies on significant unobservable inputs. These inputs include correlation between the underlying power and natural gas commodities and volatility assumptions for non-liquid delivery periods, which require management judgment and are not directly observable in the market.

The Company factors its own non-performance risk into the valuation of derivatives using current published credit default swap rates. As of March 31, 2026 and December 31, 2025, the impact of the non-performance risk adjustment to the Company's fair value of commodity derivative liabilities was $1.4 million and $1.6 million, respectively.

The following tables set forth by level within the fair value hierarchy, the financial assets and liabilities that were accounted for at fair value on a recurring basis:


	March 31, 2026
	Fair Value Measurements Using:
(in thousands)	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Financial assets
Derivative instruments
Natural gas derivatives	$	58,302	$	—	$	58,302
NGL derivatives	420		—		420
Natural gas basis swaps	15,372		—		15,372
Power derivatives	8,717		25,827		34,544
Financial liabilities
Derivative instruments
Natural gas derivatives	9,813		—		9,813
NGL derivatives	1,788		—		1,788

Power derivatives	7,085		—		7,085


	December 31, 2025
	Fair Value Measurements Using:
(in thousands)	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Financial assets
Derivative instruments
Natural gas derivatives	$	57,135	$	—	$	57,135
NGL derivatives	13,807		—		13,807
Natural gas basis swaps	17,272		—		17,272
Power derivatives	1,347		771		2,118
Financial liabilities
Derivative instruments
Natural gas derivatives	6,572		—		6,572
NGL derivatives	407		—		407
Natural gas basis swaps	1,328		—		1,328
Power derivatives	3,514		2,415		5,929

The following table is the quantitative information regarding significant unobservable inputs used in the measurement of Level 3 positions:


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March 31, 2026
Valuation Technique	Significant Unobservable Input	Range				Weighted Average		Description
Kirk Spread Option Model	Power and natural gas price correlation	92.7	%			92.7	%	Estimated correlation between underlying commodities
Kirk Spread Option Model	Power volatility (non-liquid hours)	49.3	%	60.3	%	54.8	%	Extrapolated from observable 5x16 implied volatilities and shaped for delivery periods (2x16 and 7x8)


December 31, 2025
Valuation Technique	Significant Unobservable Input	Range				Weighted Average		Description
Kirk Spread Option Model	Power and natural gas price correlation	92.7	%			92.7	%	Estimated correlation between underlying commodities
Kirk Spread Option Model	Power volatility (non-liquid hours)	42.9	%	52.4	%	47.7	%	Extrapolated from observable 5x16 implied volatilities and shaped for delivery periods (2x16 and 7x8)

The tables below sets forth the changes in the Company's Level 3 fair value measurements:


	Three Months Ended March 31,
(in thousands)	2026		2025
Balance, beginning of period	$	(1,644)	$	(3,595)
Settlements	(50,527)		(15,291)
Total realized gains	50,527		15,291
Total unrealized gains (losses)	27,471		(17,083)


Balance, end of period	$	25,827	$	(20,678)

Other Fair Value Measurements

The carrying value of cash and cash equivalents, restricted cash, accounts receivable, net, and accounts payable and accrued liabilities approximate their fair values due to the short-term maturities of these instruments. Long-term debt obligations under the RBL Credit Agreement, the Temple I Loan Agreements, and the Temple Credit Facilities also approximate fair value because the variable rates of interest are market-based. The fair value of the 2030 Senior Notes as of March 31, 2026, was approximately $505.8 million based on quoted market prices from banks and are classified Level 2 in the fair value hierarchy. The 2030 Senior Notes are carried on the condensed consolidated balance sheets at their original issuance value, as adjusted over time to accrete that value to par.

Note 6 - Derivative Instruments

The Company may utilize derivative contracts in connection with its natural gas, NGL and power operations to provide an economic hedge of the Company’s exposure to commodity price risk associated with anticipated future natural gas and NGL production, as well as to manage the Company's exposure to delivery risk, optimize physical and contractual assets in the Company's portfolio, and manage working capital requirements.

The derivative contracts outstanding as of March 31, 2026 consisted of commodity swaps, basis swaps, put and call options, producer collar agreements, fixed-price natural gas forwards, fixed-price power forwards, and HRCOs, subject to master netting agreements with each individual counterparty. The following table presents gross commodity derivative balances prior to applying netting adjustments recorded in the condensed consolidated balance sheets:


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		March 31, 2026
(in thousands)	Balance Sheet Location	Gross Amounts of Assets and Liabilities		Offset Adjustments		Net Amounts of Assets and Liabilities
Current derivative assets	Commodity derivative assets, current	$	110,731	$	(38,515)	$	72,216
Noncurrent derivative assets	Commodity derivative assets	51,822		(15,400)		36,422
Current derivative liabilities	Commodity derivative liabilities, current	56,041		(38,515)		17,526
Noncurrent derivative liabilities	Commodity derivative liabilities	16,560		(15,400)		1,160


		December 31, 2025
(in thousands)	Balance Sheet Location	Gross Amounts		Offset Adjustments		Net Amounts of Assets and Liabilities
Current derivative assets	Commodity derivative assets, current	$	66,787	$	(2,887)	$	63,900
Noncurrent derivative assets	Commodity derivative assets	34,116		(7,684)		26,432
Current derivative liabilities	Commodity derivative liabilities, current	11,356		(2,887)		8,469
Noncurrent derivative liabilities	Commodity derivative liabilities	13,451		(7,684)		5,767

Derivative Contracts

Collar, Commodity Swap, and Basis Swap Contracts

A commodity collar provides for a price floor and a price ceiling. The floating price for the collar contract is traded for a fixed price when the floating price is not between the floor and ceiling. If the floating price is between these contracted prices, no trade occurs. A commodity swap agreement is an agreement whereby a floating price based on the underlying commodity is traded for a fixed price over a specified period. Basis swaps provide a guaranteed price differential for natural gas from two different specified delivery points over a specified period. The fair value of open collar, commodity swap, and basis swap contracts reported in the condensed consolidated balance sheets may differ from that which would be realized in the event the Company terminated its position in the respective contract.

Fixed-Price Power Forwards and HRCOs

For the power generated out of the Temple Plants, the Company held fixed-price power sales contracts in which energy is delivered to the ERCOT north hub at a fixed-price per MWh. The contracts contain an agreed upon quantity of total MW and total MWh. The Company also held fixed-price power purchase contracts to hedge BKV-BPP Retail power purchases for its retail customers.

As of March 31, 2026 and December 31, 2025, the Company had outstanding four HRCO contracts with two counterparties, where the Company supplied 200 MW and 400 MW of energy to these counterparties upon demand at ERCOT North 345KV Hub, respectively, as defined by ERCOT. Under the agreements, the Company receives a monthly premium for capacity; electricity revenue for a strike price per MWh is delivered based on Platt’s Gas Daily for Houston Ship Channel and variable costs. The Company also receives a reimbursement for a maximum of two starts per calculation period. If, due to external factors, it is more advantageous to purchase power on the day-ahead market to satisfy the HRCO obligation, then this will occur instead of producing the agreed upon power for physical delivery. HRCOs contains various commodities, natural gas, and energy, and has various corresponding prices and unit of measures that correlate to the fair value recognized by the Company.

The following tables set forth the derivative gains (losses), net on the condensed consolidated statements of operations:


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		Three Months Ended March 31,
(in thousands)	Income Statement Location	2026		2025
Realized losses on derivatives (natural gas)	Derivative gains (losses), net	$	(26,910)	$	(10,373)
Realized gains (losses) on derivatives (NGL)	Derivative gains (losses), net	22		(5,097)
Realized gains on derivatives (power sales)	Derivative gains (losses), net	62,569		67,098
Realized losses on derivatives (purchased power)	Purchased power	(9,456)		(7,418)
Total realized gains on derivatives, net		$	26,225	$	44,210


		Three Months Ended March 31,
(in thousands)	Income Statement Location	2026		2025
Unrealized gains (losses) on derivatives (natural gas)	Derivative gains (losses), net	$	23,920	$	(110,395)
Unrealized losses on derivatives (NGL)	Derivative gains (losses), net	(41,333)		(8,060)
Unrealized gains (losses) on derivatives (power sales)	Derivative gains (losses), net	34,841		(31,556)
Unrealized gains (losses) on derivatives (purchased power)	Purchased power	(3,572)		2,976
Total unrealized gains (losses) on derivatives, net		$	13,856	$	(147,035)

During the first quarter in 2025, the Company entered into agreements to buy put options and subsequently paid a net premium of $16.2 million for contracts that settle in 2026 and 2027. The put options have an established floor of $3.00 per MMBtu. If at the time of settlement the contracted settlement price falls below the floor, the counterparties pay the Company an amount equal to the difference between the contracted settlement price and the floor multiplied by the contract volumes. The premium paid was recorded as an asset and is subsequently adjusted to the current fair value of the option written. During the fourth quarter of 2025, the Company terminated a portion of the put option contracts scheduled to settle in 2026 in exchange for natural gas fixed-price swap contracts that will settle in 2026. No realized gain or loss was recognized on this transaction.

Derivative Contract Volumes and Fair Values

The following tables summarize the Company’s outstanding derivative positions as of March 31, 2026 by commodity and contract type, including volume, pricing indices, or reference points, and associated fair values.

The following table summarizes the Company's power derivatives:


Instrument	Units	Quantity	Pricing Index	Fair Value as of March 31, 2026 (in thousands)
2026
Swap	MMBtu	6,132,000	HSC Gas Daily	$	(3,821)
Power forwards - sales	MWh	876,000	ERCOT North	$	8,717
Heat rate call option	MMBtu	5,256,000	Various	$	25,827
Power forwards - purchases	MWh	(573,011)	Various	$	(7,085)

The following table summarizes the Company's natural gas commodity derivatives indexed to NYMEX Henry Hub pricing:


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Instrument	MMBtu	Weighted Average Price (USD)		Weighted Average Price Floor		Weighted Average Price Ceiling		Fair Value as of March 31, 2026 (in thousands)
2026
Swap	121,458,622	$	3.86					$	56,026
2027
Swap	98,958,854	$	3.99					$	20,643
Collars	37,662,319			$	3.57	$	4.00	$	(257)
Call options	36,500,000					$	5.00	$	(11,750)
Put options	36,500,000			$	3.00			$	10,295
2028
Swap	94,085,323	$	3.79					$	4,073



2029
Swap	34,675,000	$	3.60					$	(157)

The following table summarizes the Company's natural gas basis derivatives by reference price:


Instrument	Basis Reference Price	MMBtu	Weighted Average Basis Differential		Fair Value as of March 31, 2026 (in thousands)
2026
Swap	Transco Leidy Basis	39,713,234	$	(0.79)	$	1,541
Swap	HSC Basis	41,250,000	$	(0.32)	$	5,209
Swap	Transco St 85 (Z4) Basis	27,500,000	$	0.62	$	3,220
Swap	NGPL TXOK Basis	35,794,014	$	(0.37)	$	3,134
2027
Swap	Transco Leidy Basis	10,950,000	$	(0.76)	$	(1,313)
Swap	HSC Basis	7,300,000	$	(0.25)	$	1,303
Swap	NGPL TXOK Basis	16,965,270	$	(0.31)	$	1,559
2028
Swap	NGPL TXOK Basis	7,320,000	$	(0.76)	$	(568)
Swap	HSC Basis	10,980,000	$	(0.17)	$	1,288

The following table summarizes the Company's natural gas liquids derivatives position by product and reference price:


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Instrument	Commodity Reference Price	Gallons	Weighted Average Price (USD)		Fair Value as of March 31, 2026 (in thousands)
2026
Swap	OPIS Purity Ethane Mont Belvieu	102,240,321	$	0.25	$	432
Swap	OPIS IsoButane Mont Belvieu Non-TET	10,677,157	$	0.86	$	(2,087)
Swap	OPIS Normal Butane Mont Belvieu Non-TET	17,555,154	$	0.82	$	(3,738)
Swap	OPIS Propane Mont Belvieu Non-TET	61,367,542	$	0.69	$	(5,274)
Swap	OPIS Natural Gasoline Mont Belvieu Non-TET	27,359,457	$	1.38	$	(12,071)
2027
Swap	OPIS Purity Ethane Mont Belvieu	79,965,970	$	0.28	$	2,908
Swap	OPIS IsoButane Mont Belvieu Non-TET	8,864,077	$	0.82	$	(860)
Swap	OPIS Normal Butane Mont Belvieu Non-TET	14,071,274	$	0.78	$	(1,452)
Swap	OPIS Propane Mont Belvieu Non-TET	49,204,884	$	0.66	$	(2,739)
Swap	OPIS Natural Gasoline Mont Belvieu Non-TET	22,107,531	$	1.28	$	(3,051)

Note 7 - Revenue from Contracts with Customers

All of the Company's revenues from contracts with customers are generated in the states of Pennsylvania and Texas. Revenues consist of the following:


	Three Months Ended March 31, 2026
(in thousands)	Pennsylvania		Texas		Total
Natural gas	$	30,908	$	209,243	$	240,151
NGLs	—		44,760		44,760
Oil	—		2,764		2,764
Total natural gas, NGL, and oil sales	30,908		256,767		287,675

Merchant energy sales and other	—		94,831		94,831
Energy retail sales	—		29,801		29,801
Solar revenue	—		92		92
Physical power purchased	—		(55,734)		(55,734)
Revenue from contracts with customers - power	—		68,990		68,990

Marketing revenues	—		17,585		17,585
Midstream revenues	—		2,296		2,296


Total	$	30,908	$	345,638	$	376,546


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	Three Months Ended March 31, 2025
(in thousands)	Pennsylvania		Texas		Total
Natural gas	$	24,572	$	143,411	$	167,983
NGLs	—		44,683		44,683
Oil	—		3,460		3,460
Total natural gas, NGL, and oil sales	24,572		191,554		216,126

Merchant energy sales and other	—		59,531		59,531
Energy retail sales	—		29,660		29,660
Solar revenue	—		86		86
Physical power purchased	—		(45,413)		(45,413)
Revenue from contracts with customers - power	—		43,864		43,864

Marketing revenues	—		9,686		9,686
Midstream revenues	—		2,771		2,771

Other(1)	—		51		51
Total	$	24,572	$	247,926	$	272,498

_____________________________________________

(1) Excludes gains (losses) on sales of assets.

Accounts Receivable and Revenue from Contracts with Customers

Substantially all of the Company’s accounts receivable, net result from the sale of natural gas, joint interest billings, and power sales. The Company sells the substantial majority of its natural gas, NGLs, and oil to fewer than five customers and bills working interest owners for costs related to development of the Company’s natural gas properties. The Company sells power to retail and wholesale customers on the ERCOT power grid. As of March 31, 2026 and December 31, 2025, the Company’s accounts receivable, net consisted of the following:


(in thousands)	March 31, 2026		December 31, 2025
Accounts receivable - contracts with customers(1)	$	74,026	$	97,308
Accounts receivable - derivative instruments	40,957		11,383
Accounts receivable - other	28,115		21,656
Allowance for credit losses	(1,376)		(1,270)
Total accounts receivable, net	$	141,722	$	129,077

_________________________________________________

(1)As of March 31, 2026 and December 31, 2025, one customer accounted for 65% and 62%, respectively, of accounts receivable - contracts with customers. For the three months ended March 31, 2026, two customers each accounted for approximately 63% and 25% of the Company's revenue from contracts with customers, totaling $238.0 million and $94.8 million, respectively. For the three months ended March 31, 2025, the same two customers accounted for 61% and 22% of revenue, totaling $166.5 million and $59.5 million, respectively. Also during the three months ended March 31, 2025, an additional customer accounted for approximately 15% of revenue, totaling $40.8 million of the Company's revenue from contracts with customers.

Note 8 - Accounts Payable and Accrued Liabilities


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Accounts payable and accrued liabilities included in current liabilities consist of the following:


(in thousands)	March 31, 2026		December 31, 2025
Accounts payable	$	119,957	$	100,432
Revenues payable	40,060		36,310
Interest payable	19,713		10,104
Accrued payroll	13,417		31,069
Oil, gas, and power production and other taxes payable	8,795		21,604
Commodity derivative settlements payable	2,431		24,705
Other accrued liabilities	13,068		5,263
Total	$	217,441	$	229,487

Note 9 - Stockholders' Equity

2026 Equity Offering

On March 12, 2026, the Company completed its underwritten public offering of 7,003,813 shares of common stock offered by the Company and 4,142,089 shares offered by Bedrock as the selling stockholder (the "2026 Equity Offering"), and the Company received net proceeds of $186.2 million. The proceeds from the 2026 Equity Offering were used for general corporate purposes, including working capital, operating expenses and capital expenditures.

Equity-Based Compensation

2024 Equity and Incentive Compensation Plan

The Company's 2024 Equity and Incentive Compensation Plan (the “2024 Plan”) became effective immediately prior to the consummation of the Company's IPO in September 2024, and in December 2025, the Company's board of directors approved an amendment and restatement of the 2024 Plan to increase the number of shares of common stock available for grant and issuance under the 2024 Plan by 2,500,000 shares, effective March 5, 2026 (the 2024 Plan, as so amended and restated, the “A&R 2024 Plan”). As of March 31, 2026, 4,212,364 shares were available for future grants under the A&R 2024 Plan. See Note 12 - Equity-Based Compensation in the Company's 2025 Annual Report on Form 10-K for further discussion on the A&R 2024 Plan.

Performance-Based Restricted Stock Units

The table below summarizes the activity of the performance-based restricted stock units ("PRSUs") for the three months ended March 31, 2026:






(in thousands, except per share amounts)	Shares	Weighted Average Grant Date Fair Value
Unvested PRSUs as of January 1, 2026	1,185	$	16.06
Granted	585	$	30.73
Vested	(6)	$	16.90
Forfeited	(16)	$	18.65
Unvested PRSUs as of March 31, 2026	1,748	$	20.94

As of March 31, 2026, there was $29.4 million of unrecognized compensation expense related to the PRSU awards, which will be amortized over a weighted average period of 1.8 years.

Equity-based compensation related to PRSUs was $2.3 million and $1.2 million for the three months ended March 31, 2026 and 2025, respectively. Equity compensation related to PRSUs is included in general and administrative expenses in the condensed consolidated statements of operations.

Time-Based Restricted Stock Units


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The table below summarizes the activity of the time-based restricted stock units ("TRSUs") for the three months ended March 31, 2026:






(in thousands, except per share amounts)	Shares	Weighted Average Grant Date Fair Value
Unvested TRSUs as of January 1, 2026	689	$	19.39
Granted	390	$	28.94
Vested	(241)	$	18.70
Forfeited	(8)	$	20.50
Unvested TRSUs as of March 31, 2026	830	$	24.07

As of March 31, 2026, there was $18.2 million of unrecognized compensation expense related to the A&R 2024 Plan TRSU awards, which will be amortized over a weighted average period of 2.2 years.

Equity-based compensation related to the TRSUs was $1.6 million and $0.9 million for the three months ended March 31, 2026 and 2025, respectively, which is included in general and administrative expenses in the condensed consolidated statements of operations.

Employee Stock Purchase Plan

For the three months ended March 31, 2026, the Company recognized equity-based compensation expense related to the ESPP of $0.1 million, which is included in general and administrative expenses in the condensed consolidated statements of operations. There was no equity-based compensation related to the ESPP for the three months ended March 31, 2025.

Note 10 - Investments

Joint Ventures

BKV-BPP Power Joint Venture

In 2021, the BKV-BPP Power Joint Venture was formed to own and operate combined-cycle natural gas-fired power generation facilities and a retail electricity marketing business in Temple, Texas. BKV-BPP Power generates revenues primarily through the sale of electricity and related products in the ERCOT market and through retail customer contracts, which allows the Company to integrate its upstream natural gas production with downstream power generation and marketing activities.

BKV-CIP Joint Venture

On May 8, 2025, BKV dCarbon Ventures, together with C Squared Solutions, Inc. (the “Class B Member”), a subsidiary of the Energy Transition Fund managed by Copenhagen Infrastructure Partners (CIP), and for the limited purposes specified therein, BKV Corporation, entered into the BKV-CIP JV Agreement forming BKV dCarbon Project, LLC (the “BKV-CIP Joint Venture”) for the purpose of developing CCUS projects. On May 8, 2025, BKV dCarbon Ventures contributed to the BKV-CIP Joint Venture $40.3 million of CCUS assets that included the BKV dCarbon Barnett Zero, LLC and BKV dCarbon Las Tiendas, LLC and related assets (including the Barnett Zero and Eagle Ford CCUS projects), and $4.1 million of Section 45Q accrued receivables at carrying value, and committed to future contributions of certain CCUS projects, related assets, and/or cash in exchange for an interest in the BKV-CIP Joint Venture and 4,796,421 Class A Units at $10.00 per share. The Class B Member committed up to an initial $500.0 million in cash for use by the BKV-CIP Joint Venture in construction and operating new CCUS projects across the United States in exchange for no more than a 49% interest in the BKV-CIP Joint Venture. Through March 31, 2026, the Class B Member contributed $22.1 million, and during the three months ended March 31, 2026, contributed $4.2 million. In exchange for the Class B Member's contribution to the BKV-CIP Joint Venture, the Class B Member has received a total of 2,211,155 of the BKV-CIP Joint Venture's Class B Units at $10.00 per share.

Net income (loss) is allocated to each member pursuant to the BKV-CIP JV Agreement's liquidation provisions. For the three months ended March 31, 2026, BKV dCarbon Ventures and the Class B Member's allocation in BKV-CIP Joint Venture's net income (loss) was 52% and 48%, respectively.

BKV-BPP Cotton Cove Joint Venture

On June 26, 2025, BKV dCarbon Ventures and BPPUS amended and restated the BKV-BPP Cotton Cove, LLC Agreement whereby on July 9, 2025, BKV dCarbon Ventures contributed $3.3 million to BKV-BPP Cotton Cove, net of $0.1 million of


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expenditures paid by BKV dCarbon Ventures on behalf of BKV-BPP Cotton Cove, and on July 10, 2025, BPPUS received $5.4 million of its initial capital contribution of $8.6 million from BKV-BPP Cotton Cove. On July 31, 2025, BKV dCarbon Ventures and BPPUS contributed an additional $3.8 million and $3.6 million, respectively. As a result of these transactions, BKV dCarbon Ventures owns a 51% controlling interest in BKV-BPP Cotton Cove, with BPPUS retaining a 49% interest.

Both the BKV-CIP Joint Venture and BKV-BPP Cotton Cove Joint Venture were formed to advance the Company’s CCUS strategy and do not represent a material business combination under ASC 805, Business Combination, as the assets acquired and liabilities assumed were not significant to the Company’s condensed consolidated financial statements, and no goodwill or a bargain purchase gain was recognized.

Variable Interest Entities

The Company considers the BKV-BPP Power Joint Venture, the BKV-CIP Joint Venture, and the BKV-BPP Cotton Cove Joint Venture to each be a variable interest entity (“VIE”) in accordance with ASC 810, Consolidation as the Company is deemed to be the primary beneficiary of these joint ventures. Generally, a VIE is an entity with at least one of the following conditions: (i) the total equity investment at risk is insufficient to allow the entity to finance its activities without additional subordinated financial support, or (ii) the holders of the equity investment at risk, as a group, lack the characteristics of having a controlling financial interest. The primary beneficiary of a VIE is an entity that has a variable interest or a combination of variable interests that provide such entity with a controlling financial interest in the VIE. An entity is deemed to have a controlling financial interest in a VIE if it has both of the following characteristics: (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, and (ii) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

The Company’s control over BKV-BPP Power is derived from its governance rights and its role in directing the day-to-day operational activities through its participation on a 12-member board of managers (the "BKV-BPP Power Board"), nine of whom are appointed by the Company and three of whom are appointed by BPPUS. The BKV-BPP Power Board has overall management and oversight of BKV-BPP Power, including approval of budgets, business plans, and key commercial and financing decisions. The Company directs plant operations, commercial optimization, fuel procurement, and marketing and risk management activities, through its operational role and participation in the governance of BKV-BPP Power. The Company’s economic exposure is primarily based on its 75% ownership interest, which entitles it to a majority of distributions and results of operations and exposes it to a majority of potential losses. In addition, the Company is generally required to fund its proportionate share of capital contributions in accordance with the BKV-BPP Power LLC Agreement.

The assets of BKV-BPP Power may only be used to settle its obligations, and the liabilities of BKV-BPP Power do not have recourse to the general credit of the Company, except to the extent of the Company’s investment and any contractual commitments. In addition, distributions from BKV-BPP Power may be subject to restrictions under its debt agreements or other contractual arrangements.

The Company's control over the BKV-CIP Joint Venture is derived from its ability to direct the development and execution of CCUS projects that most significantly impact the economic performance of this joint venture, including project development, capital deployment, and operational execution of CCUS projects through its management and oversight of these activities. The Company's economic exposure is based on its ownership interest and its obligation to absorb losses, or the right to receive benefits from the BKV-CIP Joint Venture.

The Company's control over BKV-BPP Cotton Cove is derived from its majority ownership interest and governance rights, which provide the Company with the ability to direct the activities that most significantly impact the joint venture's economic and operational performance, including the development and operation of CCUS-related assets. The Company's economic exposure is based on its ownership interest, including its potential earnings and losses, including funding its proportionate share of capital contributions in accordance with the respective agreements.

The assets and liabilities of these consolidated VIEs are included within the respective line items of the Company’s condensed consolidated balance sheets. The assets of the consolidated VIEs may only be used to settle obligations of the respective VIEs, and the liabilities of the consolidated VIEs do not have recourse to the general credit of the Company, except to the extent of the Company’s investment and any contractual commitments. The BKV-BPP Power Joint Venture, the BKV-CIP Joint Venture, and BKV-BPP Cotton Cove are exposed to similar operational risks as the Company, and are each monitored and evaluated on a similar basis by management. The carrying amounts and classification of the consolidated VIE assets and liabilities included in the condensed consolidated balance sheets are as follows (excluding intercompany balances):


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	March 31, 2026
(in thousands)	BKV-BPP Power		BKV-CIP Joint Venture		BKV-BPP Cotton Cove
Assets
Current assets
Cash and cash equivalents	$	56,000	$	2,170	$	2,632
Restricted cash	15,974		—		—
Accounts receivable, net	25,853		14,794		14
Other current assets	90,862		311		—
Total current assets	188,689		17,275		2,646
Other property, plant, and equipment, net	906,076		57,230		17,606
Other assets	11,470		—		—
Total assets	$	1,106,235	$	74,505	$	20,252

Liabilities
Current liabilities
Accounts payable and accrued liabilities	$	30,021	$	4,623	$	1,342
Other current liabilities	23,051		—		—
Total current liabilities	53,072		4,623		1,342
Other liabilities	624,600		—		—
Total liabilities	$	677,672	$	4,623	$	1,342


	As of December 31, 2025
(in thousands)	BKV-BPP Power		BKV-CIP Joint Venture		BKV-BPP Cotton Cove
Assets
Current assets
Cash and cash equivalents	$	49,015	$	1,331	$	3,744
Accounts receivable, net	28,618		11,749		568
Other current assets	46,206		654		—
Total current assets	123,839		13,734		4,312
Other property, plant, and equipment, net	806,673		55,452		16,606
Other assets	9,469		—		—
Total assets	$	939,981	$	69,186	$	20,918

Liabilities
Current liabilities
Accounts payable and accrued liabilities	$	22,553	$	4,880	$	2,269
Other current liabilities	18,374		—		—
Total current liabilities	40,927		4,880		2,269
Other liabilities	641,947		—		—
Total liabilities	$	682,874	$	4,880	$	2,269


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Noncontrolling Interests

Noncontrolling interests held by BPPUS of 25% and 49% in BKV-BPP Power and BKV-BPP Cotton Cove, respectively, are presented as noncontrolling interest within equity on the condensed consolidated balance sheets.

Pursuant to the BKV-CIP JV Agreement, the Class B Units are not mandatorily redeemable or currently redeemable, but become exercisable by the Class B Member with the passage of time beginning on May 8, 2027. The Company determined that there is an embedded put option in the Class B Units, which contains redemption features that are not solely within the control of the Company. Therefore, the shares of the BKV-CIP Joint Venture's Class B Units have been classified as noncontrolling interest within mezzanine equity on the Company's condensed consolidated balance sheets. The redemption value of the Class B Units is based on a 1.65x multiple of invested capital, reduced by cumulative distributions made to the Class B Member. The contributions from the Class B Member are accreted to the redemption value over a period from issuance to the earliest redemption date (using the effective interest method) with the accretion accounted for as a dividend paid to the Class B Member. As of March 31, 2026, the carrying value of the Class B Units was $18.6 million, compared to an estimated redemption value of approximately $35.3 million.

As of March 31, 2026, distributions payable to Class B Member was $6.9 million, which represents 49% of the Section 45Q tax credits generated by BKV dCarbon Ventures in 2024. The distributions payable is included in accounts payable and accrued liabilities on the condensed consolidated balance sheets.

Note 11 - Commitments and Contingencies

The Company may be subject to various claims, title matters, and legal proceedings arising in the ordinary course of business, including environmental contamination claims, personal injury and property damage claims, claims related to joint interest billings and other matters under natural gas operating agreements, and other contractual disputes. The Company maintains general liability and other insurance to cover some of these potential liabilities. All known liabilities are fully accrued based on the Company's best estimate of the potential loss. As of March 31, 2026, the Company has recorded an aggregate accrual of approximately $1.6 million, which is included in other current liabilities in the condensed consolidated balance sheets.

While the outcome and impact on the Company cannot be predicted with certainty, results may change in future periods. For the periods presented in the condensed consolidated financial statements, the Company believes that its ultimate liability, with respect to any such matters, will not have a significant impact or material adverse effect on its financial positions, results of operations, or cash flows. Results of operations and cash flows, however, could be significantly impacted in the reporting periods in which such matters are resolved.

As a part of the consideration paid for the Devon Barnett Acquisition, additional cash consideration was paid by the Company when certain thresholds were met for average Henry Hub natural gas and WTI crude oil prices for each of the calendar years during the period beginning January 2021 through December 31, 2024. As of December 31, 2024, the final portion of the arrangement was considered to be settled, resulting in a settlement of $20.0 million, which was paid on January 8, 2025.

The Company has volume commitments in the form of gathering, processing, and transportation agreements with various third parties that require delivery of 835,763,676 dekatherms of natural gas. The significant majority of the agreements terminate by 2029, with one agreement extending through 2036. As of March 31, 2026, the aggregate undiscounted future payments required under these contracts total $242.3 million.

BKV-BPP Power has commitment agreements to support the operation, fuel supply, and commercialization of its power generation assets. These agreements include energy management, fuel transportation and storage, operations and maintenance, and administrative service arrangements with terms expiring through 2028.

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

On March 25, 2026, the Company entered into an equipment supply contract related to a planned power generation project. Under the agreement, the Company is committed to pay up to an aggregate of $124.1 million in purchase payments, scheduled in phases from 2026 through 2027, to secure the manufacture of modular power generation equipment. During the three months


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ended March 31, 2026, the Company paid $2.5 million of the purchase payments, and on April 1, 2026, the Company paid an additional $33.5 million. If the Company terminates the contract before manufacturing of the equipment begins, the Company would be required to pay 60% of the contract price, and if the Company terminates the contract after manufacturing of the equipment begins, the Company would be required to pay 100% of the contract price. The Company has an option to exercise a contract with similar terms, pricing, payment, and equipment manufacture and delivery lead times.

A summary of the Company's commitments, excluding contingent consideration, as of March 31, 2026, is provided in the following table:


(in thousands)	2026		2027		2028		2029		2030		Thereafter		Total
RBL Credit Agreement	$	—	$	—	$	100,000	$	—	$	—	$	—	$	100,000
Temple Term Loan Facility	10,000		10,000		379,383		—		—		—		399,383
Temple Revolving Facility	—		—		60,000		—		—		—		60,000
Interest payable	19,713		—		—		—		—		—		19,713
BKV-BPP Power commitment agreements	4,218		4,891		401		—		—		—		9,510
Temple I Loan Agreements	176,000		—		—		—		—		—		176,000
Interest payable on Temple I Loan Agreements	7,238		—		—		—		—		—		7,238
Manufacturing reservation agreement	50,000		—		—		—		—		—		50,000
Equipment supply contract	83,147		38,453		—		—		—		—		121,600
Operating lease payments	4,859		1,474		1,269		1,303		1,345		5,628		15,878
Transportation commitments	52,924		62,224		53,909		34,257		5,913		33,032		242,259
Total	$	408,099	$	117,042	$	594,962	$	35,560	$	7,258	$	38,660	$	1,201,581

Note 12 - Income Taxes

For the three months ended March 31, 2026 and 2025, the Company calculated its provision for income taxes using the estimated annual effective income tax rate applied to year-to-date ordinary income (loss) before income taxes. The provision for income taxes also includes the tax effects of discrete items recognized in the period in which they occur.

The Company's effective tax rates for the three months ended March 31, 2026 and 2025 were 18.1% and 26.1%, respectively. For the three months ended March 31, 2026, the effective tax rate differed from the U.S. federal statutory rate of 21.0% due to the benefit of Section 45Q tax credits from the injection of captured CO2 waste for secure geologic storage, the noncontrolling interests related to the Company's investment in joint venture partnerships, and Section 45I tax credits from marginal production. These tax benefits were partially offset by tax expense associated with the limitation on deductible executive compensation. For the three months ended March 31, 2025, the effective tax rate differed from the U.S. federal statutory rate of 21.0% primarily driven by the discrete impact of unrealized hedging losses, partially offset by the benefit of Section 45I tax credits from marginal production, and Section 45Q tax credits from the injection of captured CO2 waste for secure geologic storage.

Note 13 - Earnings Per Share

Basic net income (loss) per common share attributable to BKV for each period is calculated by dividing net income (loss) attributable to BKV, adjusted for accretion to redemption value of the Class B Units, by the basic weighted average number of common shares outstanding during the period. Diluted net income (loss) per common share attributable to BKV is calculated by dividing net income (loss) attributable to BKV, adjusted for accretion to redemption value of the Class B Units, by the diluted weighted average number of common shares outstanding for the respective period. Any remeasurement of the accretion to redemption value of the Class B Units subject to possible redemption was considered to be dividends paid to the Class B Member. Accordingly, accretion is deducted from net income (loss) in the calculation of earnings per share. Diluted weighted average number of common shares outstanding and the dilutive effect of potential common shares is calculated using the treasury method. The Company includes potential shares of common stock for PRSUs and TRSUs in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the reporting period was also the


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end of the performance period. During periods in which the Company incurred a net loss, diluted weighted average common shares outstanding were equal to basic weighted average of common shares outstanding because the effects of all potential common shares was anti-dilutive.

The following is the calculation of basic and diluted net income (loss) per common share attributable to BKV three months ended March 31, 2026 and 2025:


	Three Months Ended March 31,
(in thousands, except per share amounts)	2026		2025
Net income (loss) attributable to BKV	$	44,075	$	(81,979)
Accretion of Class B Units to redemption value	(741)		—
Net income (loss) including accretion of Class B Units to redemption value	$	43,334	$	(81,979)

Basic weighted average common shares outstanding	102,018		84,706
Add: dilutive effect of TRSUs	153		—
Add: dilutive effect of PRSUs	133		—
Diluted weighted average of common shares outstanding	102,304		84,706
Weighted average number of outstanding securities excluded from the calculation of diluted loss per share
TRSUs	—		22
PRSUs	—		—

Net income (loss) per common share attributable to BKV:
Basic	$	0.42	$	(0.97)
Diluted	$	0.42	$	(0.97)

Note 14 - Reportable Segments

Prior to the consolidation of the BKV-BPP Power Joint Venture in the first quarter of 2026, the Company was organized, managed, and identified as one operating segment and one reportable segment. Thereafter, as a result of changes to the Company's internal reporting structure, the Company’s CODM changed the manner in which resource allocation decisions are made and performance is assessed. As such, commencing in the first quarter of 2026, the Company's natural gas production, natural gas midstream, and power generation business lines, all of which are located within the United States, are now organized into two reportable segments for financial reporting purposes: (i) Upstream/Midstream and (ii) Power. In addition, the Company has an "All Other" category, which includes its Corporate and Other operating segment. The Corporate and Other operating segment includes the Company's remaining non-reportable segment operations consisting primarily of its CCUS business line and general corporate expenses not allocated to its reportable segments. Prior period segment information has been recast to reflect the current reportable segment structure.

The CODM evaluates segment performance and allocates resources based on segment revenues and other operating income, significant segment expenses, and other segment items, as well as capital expenditures. The primary measure of segment profit or loss used by the CODM is income from operations. The CODM also evaluates the Company's segment results period-over-period and relative to budget.

The Company's Upstream/Midstream segment is engaged in the acquisition, operation, exploration, development, and production of natural gas, NGLs, and oil in the Barnett and NEPA, and the commercial and midstream services such as gathering and transportation, marketing services, and commodity risk management activities.

The Company's Power segment is engaged in electricity generation, wholesale energy sales and purchases, and retail marketing operations. These activities are conducted through the BKV-BPP Power Joint Venture in which the Company holds a 75% ownership interest. Subsidiaries of the BKV-BPP Power Joint Venture own the Temple Plants, which are modern combined cycle gas and steam turbine power plants located in the ERCOT North Zone in Temple, Texas, and operate a retail marketing business throughout the deregulated portions of Texas.


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The Company's Corporate and Other operating segment includes BKV Corp, shared services, and the results of the Company's carbon capture and sequestration business, which focuses on reducing GHG emissions by capturing CO2 from Company-owned and third-party operations, as well as other energy and industrial sources. Intercompany eliminations are included within the Corporate and Other segment for purposes of segment reporting.

The following tables present the Company's segment revenues and other operating income, significant segment operating expenses, and segment income (loss) from operations:


	Three Months Ended March 31, 2026
(in thousands)	Upstream/Midstream		Power		Total Reportable Segments		Corporate and Other		Total
Revenues and other operating income
Natural gas, NGL, and oil sales	$	287,675	$	—	$	287,675	$	—	$	287,675
Power revenues	—		68,990		68,990		—		68,990
Midstream revenues	2,296		—		2,296		—		2,296
Derivative gains (losses), net	(42,476)		95,585		53,109		—		53,109
Marketing revenues	17,527		—		17,527		58		17,585
Section 45Q tax credits	—		—		—		3,060		3,060

Other	132		—		132		—		132
Total revenues and other operating income	$	265,154	$	164,575	$	429,729	$	3,118	$	432,847
Operating expenses

Lease operating and workover	45,075		—		45,075		—		45,075
Fuel commodity costs	—		57,121		57,121		—		57,121
Purchased power	—		27,355		27,355		—		27,355
Taxes other than income	15,961		4,234		20,195		7		20,202
Gathering and transportation	67,802		—		67,802		—		67,802
Depreciation, depletion, amortization, and accretion	40,691		11,804		52,495		446		52,941
General and administrative	21,908		6,740		28,648		13,482		42,130
Power operating and maintenance	—		19,679		19,679		—		19,679
Other operating expenses	8,860		4,156		13,016		1,500		14,516
Total operating expenses	200,297		131,089		331,386		15,435		346,821
Income (loss) from operations	$	64,857	$	33,486	$	98,343	$	(12,317)	$	86,026








Capital expenditures	$	78,970	$	16,850	$	95,820	$	10,707	$	106,527


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	Three Months Ended March 31, 2025
(in thousands)	Upstream/Midstream		Power		Total Reportable Segments		Corporate and Other		Total
Revenues and other operating income
Natural gas, NGL, and oil sales	$	216,126	$	—	$	216,126	$	—	$	216,126
BKV-BPP Power revenues	—		43,864		43,864		—		43,864
Midstream revenues	2,771		—		2,771		—		2,771
Derivative gains (losses), net	(152,191)		53,808		(98,383)		—		(98,383)
Marketing revenues	9,686		—		9,686		—		9,686
Section 45Q tax credits	—		—		—		3,307		3,307

Other	(1,305)		—		(1,305)		—		(1,305)
Total revenues and other operating income	$	75,087	$	97,672	$	172,759	$	3,307	$	176,066
Operating expenses

Lease operating and workover	35,055		—		35,055		—		35,055
Fuel commodity costs	—		46,363		46,363		—		46,363
Purchased power	—		18,667		18,667		—		18,667
Taxes other than income	10,221		4,569		14,790		—		14,790
Gathering and transportation	55,793		—		55,793		—		55,793
Depreciation, depletion, amortization, and accretion	39,491		9,627		49,118		479		49,597
General and administrative	10,174		5,232		15,406		13,663		29,069
Power operating and maintenance	—		20,213		20,213		—		20,213
Other operating expenses	4,038		390		4,428		2,188		6,616
Total operating expenses	154,772		105,061		259,833		16,330		276,163
Loss from operations	$	(79,685)	$	(7,389)	$	(87,074)	$	(13,023)	$	(100,097)








Capital expenditures	$	54,264	$	238	$	54,502	$	3,110	$	57,612

The following table reconciles total segment income (loss) from operations to consolidated income before income taxes


	Three Months Ended March 31,
(in thousands)		2026		2025
Total segment operating income (loss)		$	98,343	$	(87,074)
Unallocated amounts:
Corporate and other revenues and other operating income		3,118		3,307
Corporate and other taxes other than income		(7)		—
Corporate and other depreciation, depletion, amortization, and accretion		(446)		(479)
Corporate and other general and administrative		(13,482)		(13,663)
Corporate and other, other operating expenses		(1,500)		(2,188)
Interest expense, net		(25,601)		(20,376)
Other income		2,888		3,034
Income (loss) before income taxes		$	63,313	$	(117,439)

The following table presents total assets by reportable segment reconciled to total consolidated assets:


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	March 31,
(in thousands)	2026		2025
Upstream/Midstream	$	2,699,776	$	2,037,244
Power	1,106,235		979,070
Total reportable segments	3,806,011		3,016,314
Corporate and Other	365,521		107,632
Total consolidated assets	$	4,171,532	$	3,123,946


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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

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

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

Recent Developments

•BKV-BPP Power Joint Venture Transaction. On January 30, 2026, we completed the previously announced acquisition of an additional 25% interest in the BKV-BPP Power Joint Venture for aggregate consideration consisting of $115.1 million in cash and 5,315,390 shares of our common stock. We funded the cash consideration with a combination of cash on hand and the net proceeds from the 2025 Equity Offering. Following the closing of the transaction, the BKV-BPP Power Joint Venture is owned 75% by BKV Corp and 25% by BPPUS, and the financial results of BKV-BPP Power have been consolidated into our financial statements for all periods presented. For additional information, see Note 2 - Acquisition and Note 14 - Reportable Segments.

•2026 Equity Offering. On March 12, 2026, we completed the 2026 Equity Offering for net proceeds to the Company of $186.2 million, which were used for general corporate purposes, including working capital, operating expenses and capital expenditures. For additional information, see Note 9 - Stockholders' Equity.

Operational and Financial Highlights

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

•Production of natural gas, NGLs, and oil was 83.3 Bcfe, or 925.0 MMcfe/d, respectively.

•Average realized product prices, excluding the impact of settled derivatives, was $3.46 per Mcfe.

•Power generation of 1,981 GWh from the Temple Plants and capacity factor of 62.4%.

•Upstream/Midstream production revenues were $287.7 million, and Power revenues were $69.0 million.

•Net income attributable to BKV was $44.1 million.

•Net cash provided by operating activities for the three months ended March 31, 2026 was $72.0 million.

•Accrued capital expenditures for the three months ended March 31, 2026 were $118.6 million.

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

Our business depends on many factors, including, but not limited to: (i) commodity prices, (ii) market supply and demand for natural gas, NGLs, and power, and (iii) upstream and power capital and operating costs. We continually monitor domestic and global factors which may cause our actual results of operations to differ from historical results or expected outlook.

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

Supply, Demand, Market Risk, and the Impact on Natural Gas, NGLs, and Power Prices. Natural gas, NGL, and power prices are subject to large fluctuations in response to relatively minor changes in the demand for natural gas, NGLs, and power. Natural gas and NGL prices are affected by current and expected supply and demand dynamics, including the level of drilling,


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

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

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

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

•success in drilling new wells;

•the availability of attractive acquisition opportunities and our ability to execute them;

•the amount of capital we invest in the leasing and development of our properties;

•facility or equipment availability and unexpected downtime; and

•delays imposed by or resulting from compliance with regulatory requirements.

Production Volumes and Power Data

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


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

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

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

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

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

Sources of Revenues

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

Realized Commodity Prices

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


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


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Business Segment Results of Operations

The following sections present our results of operations for our two reportable segments, which include Upstream/Midstream and Power. Management believes this information is useful to investors in understanding the Company's financial condition, results of operations, and trends and uncertainties. See Note 14 - Reportable Segments to our condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q.

Upstream/Midstream Segment

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


	Three Months Ended March 31,
(in thousands, other than percentages)	2026		2025		$ Change		% Change
Production volume
Total production volumes (MMcfe)	83,253		68,503		14,750		22	%
Average daily production (MMcfe/d)	925.0		761.1		163.9		22	%
Average realized price (excluding derivatives)	$	3.46	$	3.15	$	0.31	10	%
Average realized price (including derivatives)	$	3.14	$	2.89	$	0.25	9	%

Revenues and other operating income
Natural gas revenues	$	240,151	$	167,983	$	72,168	43	%
NGL revenues	44,760		44,683		77		—	%
Oil revenues	2,764		3,460		(696)		(20)	%
Midstream revenues	2,296		2,771		(475)		(17)	%
Derivative losses, net	(42,476)		(152,191)		109,715		*
Marketing revenues	17,527		9,686		7,841		81	%
Other	132		(1,305)		1,437		*
Total revenues and other operating income	265,154		75,087		190,067
Operating expenses
Lease operating and workover	45,075		35,055		10,020		29	%
Taxes other than income	15,961		10,221		5,740		56	%
Gathering and transportation	67,802		55,793		12,009		22	%
Depreciation, depletion, amortization, and accretion	40,691		39,491		1,200		3	%
General and administrative	21,908		10,174		11,734		*
Other operating expenses	8,860		4,038		4,822		*
Total operating expenses	200,297		154,772		45,525
Income (loss) from operations	$	64,857	$	(79,685)	$	144,542

Per unit costs
Lease operating and workover	$	0.54	$	0.51	$	0.03	6	%
Taxes other than income	$	0.19	$	0.15	$	0.04	27	%
Gathering and transportation	$	0.81	$	0.81	$	—	—	%
Depreciation, depletion, amortization, and accretion	$	0.49	$	0.58	$	(0.09)	(16)	%
General and administrative	$	0.26	$	0.15	$	0.11	73	%
Other operating expenses	$	0.11	$	0.06	$	0.05	83	%
Total	$	2.40	$	2.26	$	0.14
*Percentage not meaningful


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Natural Gas Revenues

Our natural gas revenues increased by approximately $72.2 million, or 43%, to $240.2 million for the three months ended March 31, 2026, from $168.0 million for the three months ended March 31, 2025. The increase was due to higher production volumes during the three months ended March 31, 2026, which accounted for a $43.4 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price). The impact was also due to commodity price increases, excluding the effect of derivative settlements, which provided a $28.8 million increase in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes).

NGL Revenues

Our NGL revenues were $44.8 million for the three months ended March 31, 2026 and $44.7 million for the three months ended March 31, 2025, remaining relatively consistent period-over-period. Higher production volumes during the three months ended March 31, 2026 increased NGL revenues by $2.8 million (calculated as the change in period-to-period volumes times the prior period average price), which was largely offset by a $2.7 million decrease attributable to lower commodity prices, excluding the effect of derivative settlements (calculated as the change in the period-to-period average price times current period production volumes).

Oil Revenues

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

Midstream Revenues

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

Derivative Gains (Losses), Net

For the three months ended March 31, 2026, our Upstream/Midstream segment had net realized and unrealized losses on derivative contracts of $42.5 million, compared to net realized and unrealized losses of $152.2 million for the same period in 2025. The decrease in losses for the three months ended March 31, 2026, was primarily attributable to our open derivative positions, which were in an unrealized loss position of $16.1 million, compared to an unrealized loss position of $134.0 million for the same period in 2025. The current period primarily reflects slight increases in the forward curve of natural gas prices relative to December 31, 2025, whereas the prior year period reflected higher increases in future natural gas prices compared to December 31, 2024. In addition, we purchased put options of $16.2 million in the first quarter of 2025, limiting our 2026/2027 pricing downside. Increasing the derivative losses for the three months ended March 31, 2026 were realized losses of $26.3 million, compared to realized losses of $18.2 million for the three months ended March 31, 2025, which were due to slightly higher natural gas prices settled in the current period compared to the same period in the prior year.

Marketing Revenues

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

Other Revenues

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


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Lease Operating and Workover

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


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

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

Taxes Other Than Income

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

Gathering and Transportation

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

Depreciation, Depletion, Amortization, and Accretion

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

General and Administrative

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

Other Operating Expenses

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

Power Segment


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


	Three Months Ended March 31,
(in thousands, other than percentages)	2026			2025			$ Change			% Change
Temple I capacity factor	64.5		%	45.4		%	19.1		%	42	%
Temple II capacity factor	60.3		%	54.2		%	6.1		%	11	%
Total power generation (GWh)	1,981			1,588			393			25	%
Fuel consumption (MMBtu)	14,016			11,232			2,784			25	%
Average generation price (excluding derivatives)	$	19.73		$	8.89		$	10.84		*
Average generation price (including derivatives)	$	51.04		$	52.87		$	(1.83)		(3)	%
Average natural gas cost	$	4.08		$	4.13		$	(0.05)		(1)	%
Average spark spread	$	22.21		$	23.67		$	(1.46)		(6)	%

Revenues and other operating income
Power revenues	$	68,990		$	43,864		$	25,126		57	%
Derivative gains, net	95,585			53,808			41,777			78	%
Total revenues and other operating income	164,575			97,672			66,903
Operating expenses
Fuel commodity costs	57,121			46,363			10,758			23	%
Purchased power	27,355			18,667			8,688			47	%
Taxes other than income	4,234			4,569			(335)			(7)	%
Depreciation, depletion, amortization, and accretion	11,804			9,627			2,177			23	%
Power operating and maintenance	19,679			20,213			(534)			(3)	%
General and administrative	6,740			5,232			1,508			29	%
Other operating expenses	4,156			390			3,766			*
Total operating expenses	131,089			105,061			26,028
Income (loss) from operations	$	33,486		$	(7,389)		$	40,875










*Percentage not meaningful

Power Revenues

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

Derivative Gains (Losses), Net

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

Fuel Commodity Costs


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Fuel commodity costs were $57.1 million for the three months ended March 31, 2026, which was an increase of $10.8 million, or 23%, from $46.4 million for the three months ended March 31, 2025. The increase was due to higher fuel consumption compared to the same period in 2025.

Purchased Power

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

Taxes Other Than Income

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

Depreciation, Depletion, Amortization, and Accretion

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

Power Operating and Maintenance

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

General and Administrative

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

Other Operating Expenses

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

Other Income Statement Line Items

Section 45Q Tax Credits

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

Other Income (Expense)

Interest expense. Interest expense was $22.8 million for the three months ended March 31, 2026, which was an increase of $6.8 million, from $16.0 million for the three months ended March 31, 2025. The increase in interest expense during the three months ended March 31, 2026 was primarily due to $9.4 million of interest on the 2030 Senior Notes, $0.6 million of interest on the Promissory Note, and $0.5 million of higher debt amortization expense. These increases were partially offset by $2.4 million


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and $1.3 million of lower interest expense on the RBL Credit Agreement and the Temple Term Loan Facility, respectively, compared to the same period in 2025.

Interest expense, related party. Interest expense, related party was $4.3 million for the three months ended March 31, 2026, which was a decrease of $0.8 million, from $5.1 million for the three months ended March 31, 2025. The decrease was primarily due to a lower outstanding balance on the Temple I Loan Agreements period-over-period.

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

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

Liquidity and Capital Resources

Capital Commitments

Our primary needs for cash are to fund our upstream development, midstream, power, and CCUS activities, fund operations and capital expenditures, acquisitions, and asset retirement obligations, cover any debt interest or minimum volume commitment obligations, pay down debt, and return capital to stockholders. Our primary uses of cash during the three months ended March 31, 2026 included funding the BKV-BPP Power Joint Venture transaction, development of our natural gas properties, land acquisitions, deposits for modular power generation equipment and associated reservation fees. Our primary use of cash during the three months ended March 31, 2025, included funding the development of our natural gas properties.

During the three months ended March 31, 2026 and 2025, cash paid for capital expenditures was $106.5 million and $57.6 million, respectively. Our current estimated budget for total accrued capital expenditures in 2026 is approximately $570 million to $740 million on a Company-wide basis. To help fund these capital expenditures, we expect to receive approximately $85 million to $105 million of capital contributions from our joint venture partners in our CCUS and power businesses. Expected contributions from our joint venture partners would bring our 2026 net capital expenditure range to $485 million to $635 million. Capital expenditures for our operated properties are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for natural gas and NGLs, the availability of equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs, and the level of participation by other interest owners. In addition, the development of our power business is capital intensive, requiring ongoing investments in land, modular equipment, and turbine generators. We will continue to monitor commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.

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

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

Capital Resources

Historically, our primary sources of capital and liquidity have consisted of internally generated cash flows from operations, together with loans, capital contributions from our majority stockholder, BNAC, and issuances of equity or debt. We also enter


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

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


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

Cash flows provided by operating activities. Net cash provided by operating activities was $72.0 million for the three months ended March 31, 2026, compared to $16.5 million for the three months ended March 31, 2025. Net cash provided by operating activities increased during the three months ended March 31, 2026, compared to the three months ended March 31, 2025 due to a $28.0 million increase in income from operations (excluding noncash items), resulting from higher natural gas and production volumes, and higher power prices, power generation, and capacity at the Temple Plants. Cash from operations also increased period-over-period due to the absence of $20.0 million and $16.2 million of cash paid in 2025 for the settlement of contingent liabilities and the purchase of put options, respectively, and a $3.9 million decrease in cash paid for interest. These increases were partially offset by a $12.4 million unfavorable change in working capital period-over-period.

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

Cash flows used in investing activities. Net cash used in investing activities was $232.8 million for the three months ended March 31, 2026, compared to $56.2 million for the three months ended March 31, 2025. The increase was driven by $93.4 million of cash paid for land, and $33.1 million of cash deposits on equipment supply and manufacturing reservations. The increase was also attributable to higher capital expenditures, including a $24.7 million increase in Upstream/Midstream segment capital expenditures, a $16.6 million increase in Power segment capital expenditures, a $6.6 million increase in CCUS capital expenditures, and a $1.0 million increase in corporate and other capital expenditures, as well as a $0.9 million decrease in proceeds from the sales of assets.

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


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

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


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

Working Capital

As of March 31, 2026, we had cash and cash equivalents of $288.5 million and restricted cash of $16.0 million, compared to $248.4 million of cash and cash equivalents and restricted cash of $15.8 million as of December 31, 2025. Our net working capital surplus was $135.4 million as of March 31, 2026, compared to a net working capital deficit of $53.2 million as of December 31, 2025.

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

2030 Senior Notes

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

Interest on the 2030 Senior Notes is payable semi-annually on April 15 and October 15 of each year, commencing on April 15, 2026. The 2030 Senior Notes are guaranteed on a senior unsecured basis by us and all of BKV Upstream Midstream's existing restricted subsidiaries and certain future subsidiaries. These guarantees are full, unconditional, joint, and several among the guarantors of the 2030 Senior Notes, subject to certain customary release provisions. The indenture governing the 2030 Senior Notes contains customary events of default, as well as cross-default provisions with other indebtedness of BKV Upstream Midstream and its restricted subsidiaries.

On or after October 15, 2027, BKV Upstream Midstream may, on any one or more occasions, redeem some or all of its 2030 Senior Notes prior to their maturity at redemption prices plus accrued and unpaid interest as described in the indenture governing the 2030 Senior Notes. BKV Upstream Midstream may redeem up to 40% of the aggregate principal amount of the 2030 Senior Notes before October 15, 2027, with an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price described in the indenture governing the 2030 Senior Notes plus accrued and unpaid interest to, but excluding, the redemption date. In addition, prior to October 15, 2027, BKV Upstream Midstream may redeem some or all of the 2030 Senior Notes at a price equal to 100% of the principal amount thereof, plus a make-whole premium as described in the indenture governing the 2030 Senior Notes, plus accrued and unpaid interest.

Loan Agreements and Credit Facilities

RBL Credit Agreement


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

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

The RBL Credit Agreement 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 generally includes customary events of default for a reserve-based credit facility, some of which allow for an opportunity to cure. If an event of default relating to bankruptcy or other insolvency events occurs, the revolving loans will immediately become due and payable; if any other event of default exists, the administrative agent or the requisite lenders will be permitted to accelerate the maturity of the revolving loans. The RBL Credit Agreement is secured by substantially all of BKV Upstream Midstream's assets and those of the guarantors, and upon an event of default the agent under the RBL Credit Agreement could commence foreclosure proceedings.

Promissory Note

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

BKV-BPP Power Loan Agreements and Credit Facilities


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Temple I Loan Agreements

Temple Credit Facilities

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

The obligations under the Temple Credit Facilities are secured by (i) all of the assets of Temple Intermediate II, Temple Generation I, Temple Generation II, and Temple Generation SF, including the Temple Plants and all other personal property and real property of such entities and (ii) 100.0% of the equity interests in each of Temple Generation I, Temple Generation II, Temple Generation SF, and Temple Intermediate II. This collateral will remain pledged to Beal Bank until all secured obligations under the Temple Loan Facilities have been satisfied in full. Upon the occurrence and continuation of an event of default under either of the Temple Credit Facilities, Beal Bank has customary secured creditor remedies, including the right to foreclose upon the pledged collateral.


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

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

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

Off-Balance Sheet Arrangements

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

Critical Accounting Policies and Estimates

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

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

Tariffs and Trading Relationships

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

Emerging Growth Company Status

We are an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act of 1933, as amended, including as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As a result, for so long as we qualify as an


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

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk and Hedging Activities

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

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

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

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

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

Additionally, to reduce our exposure to fluctuations in the market price of power and natural gas, we enter into financially settled HRCOs, which are contracts for the financial purchase and sale of power based on a floating price of natural gas at a predetermined location using a predetermined conversion factor, or heat rate, required to convert natural gas into power. We are exposed to basis risk in our operations when our derivative contracts are financially settled while physical power is delivered at


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

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

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

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

Counterparty Credit Risk

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

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

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

Interest Rate Risks


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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

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

Changes in Internal Control over Financial Reporting

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


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PART II OTHER INFORMATION

Item 1. Legal Proceedings

This information is set forth in Part I, Item 1 in Note 11 - Commitments and Contingencies to the condensed consolidated financial statements incorporated herein.

Item 1A. Risk Factors

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

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None

Item 3. Defaults Upon Senior Securities

None

Item 4. Mine Safety Disclosures

None

Item 5. Other Information

Securities Trading Plans of Directors and Executive Officers

During the three months ended March 31, 2026, no director or officer of the Company (as defined in Rule 16a-1(f) of the Exchange Act), adopted, modified, or terminated a “Rule 10b5-1 trading arrangement” or a “non-Rule 10b5-1 trading agreement” (each as defined in Item 408(a) of Regulation S-K).


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Item 6. Exhibits

Incorporated by Reference

Exhibit Number

Description

Form

SEC File Number

Exhibit

Filing Date

Filed or Furnished Herewith

2.1+‡

Membership Interest Purchase Agreement, dated as of August 7, 2025, by and among BKV Upstream Midstream, LLC, Bedrock Energy Partners, LLC, certain of its subsidiaries and, solely for certain limited purposes set forth herein, BKV Corporation.

10-Q

001-42282

2.1

11/10/25

2.2+

Membership Interest Purchase Agreement, dated as of October 29, 2025, by and between BKV Corporation and Banpu Power US Corporation.

10-Q

001-42282

2.2

11/10/25

3.1

Second Amended and Restated Certificate of Incorporation of BKV Corporation.

8-K

001-42282

3.1

9/27/24

3.2

Second Amended and Restated Bylaws of BKV Corporation.

8-K

001-42282

3.2

9/27/24

4.1

Second Supplemental Indenture, dated as of April 15, 2026, by and among BKV Upstream Midstream, LLC, BKV Marketing, LLC, the guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee.

10.1

Registration Rights Agreement, dated as of January 30, 2026, by and between BKV Corporation and Banpu Power US Corporation.

8-K

001-42282

10.1

1/30/26

10.2 +

Amended and Restated Limited Liability Company Agreement of BKV-BPP Power LLC, dated as of January 30, 2026.

8-K

001-42282

10.2

1/30/26

10.3 †

Amended and Restated BKV Corporation 2024 Equity and Incentive Compensation Plan (the “Amended 2024 Plan”).

10-K

001-42282

10.29

3/6/26

10.4 †

Time Restricted Stock Unit Award Notice and Award Agreement under the Amended 2024 Plan (CEO).

10.5 †

Performance-Based Restricted Stock Unit Award Notice and Award Agreement under the Amended 2024 Plan (CEO).

10.6 †

Time Restricted Stock Unit Award Notice and Award Agreement under the Amended 2024 Plan (Non-CEO Employee).

10.7 †

Performance-Based Restricted Stock Unit Award Notice and Award Agreement under the Amended 2024 Plan (Non-CEO Employee).

10.8+

Fifth Amendment to Credit Agreement, dated as of March 30, 2026, among BKV Corporation, as guarantor, BKV Upstream Midstream, LLC, as borrower, certain subsidiaries of BKV Upstream Midstream, LLC, as guarantors, Citibank, N.A., as administrative agent, and the lenders party thereto.

10.9 +

Credit Agreement, dated as of July 10, 2023, among Temple Generation Intermediate Holdings II, LLC, as borrower, the guarantors party thereto, the lenders party thereto, Beal Bank USA, as letter of credit issuing bank, and CLMG Corp., as administrative agent and collateral agent.

31.1

Certification of Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


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32.2

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

Inline XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

104

Cover Page Interactive Data File (embedded within the inline XBRL document).

+ Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The registrant undertakes to furnish supplemental copies of any of the omitted schedules upon request by the SEC.

‡ Certain portions of this exhibit have been redacted pursuant to Item 601(b)(2)(ii) or Item 601(b)(10)(iv), as applicable, of Regulation S-K. The registrant agrees to furnish supplementally an unredacted copy of this exhibit to the SEC upon request.

† Compensatory plan or arrangement.


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Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	BKV Corporation


May 7, 2026	By:	/s/ David R. Tameron
		David R. Tameron
		Chief Financial Officer


	BKV Corporation


May 7, 2026	By:	/s/ Barry S. Turcotte
		Barry S. Turcotte
		Chief Accounting Officer


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Form: 10-Q

Documents