As filed with the Securities and Exchange Commission on October 6, 2023

Registration No. 333-268469​

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

AMENDMENT NO. 8
TO

FORM S-1

REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

BKV CORPORATION

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization) 1311
(Primary Standard Industrial
Classification Code Number) 85-0886382
(I.R.S. Employer
Identification Number)

1200 17th Street, Suite 2100
Denver, Colorado 80202
(720) 375-9680

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Christopher P. Kalnin
Chief Executive Officer
BKV Corporation
1200 17th Street, Suite 2100
Denver, Colorado 80202
(720) 375-9680

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Samantha H. Crispin
M. Preston Bernhisel
Adorys Velazquez
Baker Botts L.L.P.
2001 Ross Avenue, Suite 900
Dallas, Texas 75201
(214) 953-6500 Michael Chambers
Monica E. White
Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, Texas 77002
(713) 546-5400

Approximate date of commencement of proposed sale to the public:
As soon as practicable after the effective date of this registration statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐

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 7(a)(2)(B) of the Securities Act. ☒

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED     , 2023

PRELIMINARY PROSPECTUS

    Shares

BKV Corporation

Common Stock

This is the initial public offering of common stock of BKV Corporation, a Delaware corporation. Prior to this offering, there has been no public market for our common stock. We anticipate that the initial public offering price will be between $      and $      per share. We have applied to list our common stock on the New York Stock Exchange (“NYSE”) under the symbol “BKV.”

We have granted the underwriters a 30-day option to purchase up to     additional shares from us at the initial public offering price, less the underwriting discounts and commissions.

We are an “emerging growth company” as the term is used in the Jumpstart Our Business Startups Act of 2012 and, as such, have elected to comply with certain reduced public company reporting requirements. See “Prospectus Summary—Implications of Being an Emerging Growth Company.”

Upon completion of this offering, affiliates of Banpu Public Company Limited will beneficially own approximately     % of the voting power of the outstanding shares of our common stock. As a result, we will be a “controlled company” within the meaning of the NYSE rules. See “Management—Controlled Company.”

Investing in our common stock involves risks, including those described under “Risk Factors” beginning on page 43 of this prospectus.

​	Price to Public			Underwriting Discounts and Commissions(1)			Proceeds to BKV Corporation
Per Share	​	$		​	$		​	$
Total	​	$		​	$	​	​	$	​

(1)

The underwriters will also be reimbursed for certain expenses incurred in this offering. See “Underwriting” for additional information regarding underwriting compensation.

Neither the Securities and Exchange Commission nor any securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares of our common stock on or about            , 2023.

Joint Book-Running Managers

BofA Securities Barclays Citigroup

Evercore ISI Jefferies Wells Fargo Securities

Co-Managers

TPH&Co. Susquehanna Financial Group, LLLP Capital One
Securities

The date of this prospectus is               , 2023.

TABLE OF CONTENTS

​	Page
PROSPECTUS SUMMARY	​	1
RISK FACTORS	​	43
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	​	98
USE OF PROCEEDS	​	100
DIVIDEND POLICY	​	101
CAPITALIZATION	​	102
DILUTION	​	104
UNAUDITED PRO FORMA COMBINED CONSOLIDATED FINANCIAL STATEMENTS	​	106
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	​	113
INDUSTRY	​	157
BUSINESS	​	160
MANAGEMENT	​	223
EXECUTIVE COMPENSATION	​	233
PRINCIPAL STOCKHOLDERS	​	249
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	​	251
DESCRIPTION OF CAPITAL STOCK	​	259
SHARES ELIGIBLE FOR FUTURE SALE	​	267
CERTAIN ERISA CONSIDERATIONS	​	270
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS OF OUR COMMON STOCK	​	272
UNDERWRITING	​	276
LEGAL MATTERS	​	283
EXPERTS	​	283
WHERE YOU CAN FIND MORE INFORMATION	​	284
INDEX TO FINANCIAL STATEMENTS	​	F-1

Dealer Prospectus Delivery Obligation

Through and including             , 2023 (the 25th day after the date of this prospectus), all dealers that effect transactions in our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This delivery requirement is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

You should rely only on the information contained in this prospectus or in any free writing prospectus that we authorize to be distributed to you. We and the underwriters have not authorized anyone to provide you with any information other than that contained in this prospectus or in any free writing prospectus prepared by or on behalf of us or to which we have referred you, and neither we, nor the underwriters take responsibility for any other information others may give you. We are offering to sell, and seeking offers to buy, shares of our common stock only in jurisdictions where such offers and sales are permitted. The information in this prospectus or any free writing prospectus is accurate only as of its date, regardless of its time of delivery or the time of any sale of shares of our common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

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Industry and Market Data

In this prospectus, we present certain market and industry data. This information is based on third-party sources which we believe to be reliable as of their respective dates. Neither we nor the underwriters have independently verified any third-party information. Some data is also based on our good faith estimates. Expectations of our and our industry’s future performance are necessarily subject to a high degree of uncertainty and risk due to a variety of factors, including those described in “Risk Factors.” These and other factors could cause future performance to differ materially from our expectations. See “Cautionary Statement Regarding Forward-Looking Statements.”

Presentation of Financial, Reserves and Operating Data

Unless indicated otherwise, the historical financial information presented in this prospectus is that of BKV Corporation and its consolidated subsidiaries as of December 31, 2022 or June 30, 2023, as applicable. The pro forma financial information presented in this prospectus presents the combination of the historical consolidated financial statements of the Company, as adjusted to give effect to the Exxon Barnett Acquisition, the related financing under the Term Loan Credit Agreement and the $75 Million Loan Agreement (each as defined herein). Please see “Unaudited Pro Forma Combined Consolidated Financial Statements” included elsewhere in this prospectus.

The historical natural gas, NGL and oil reserves data presented in this prospectus as of June 30, 2023 and December 31, 2022, 2021 and 2020 are based on the reserves reports prepared by Ryder Scott Company, L.P., independent petroleum engineers.

In addition, unless indicated otherwise, the operational data presented in this prospectus is that of BKV Corporation and its consolidated subsidiaries on a consolidated basis as of and for the periods presented.

As a result of our acquisition transactions in recent years, our historical operating, financial and reserves data may not be comparable between periods presented in this prospectus. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors that Affect Comparability of Our Results of Operations.”

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, ™ or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the rights of the applicable licensor to these trademarks, service marks and trade names.

Rounding and Percentages

The financial information and certain other information presented in this prospectus have been rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables in this prospectus. In addition, certain percentages presented in this prospectus reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers or may not sum due to rounding.

Other Considerations

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” for additional information regarding these risks.

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You should read this prospectus and any written communication prepared by us or on our behalf in connection with this offering, together with the additional information described in the section of this prospectus titled “Where You Can Find More Information.” We have not authorized anyone to provide you with information or to make any representation in connection with this offering other than those contained herein. If anyone makes any recommendation or gives any information or representation regarding this offering, you should not rely on that recommendation, information or representation as having been authorized by us, the underwriters or any other person on our behalf. The information contained in this prospectus is accurate only as of the date of which it is shown, or if no date is otherwise indicated, the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our shares of common stock. We are offering to sell, and seeking offers to buy, shares of common stock only in jurisdictions where offers and sales are permitted. Our business, financial condition, results of operations and prospects may have changed since that date. Information contained on our website is not part of this prospectus.

No action is being taken in any jurisdiction outside the United States to permit a public offering of shares of common stock or possession or distribution of this prospectus in that jurisdiction. Persons who come into possession of this prospectus in jurisdictions outside the United States are required to inform themselves about and to observe any restrictions as to this offering and the distribution of this prospectus applicable to that jurisdiction.

Glossary of Oil and Natural Gas Terms

The following are abbreviations and definitions of certain terms used in this prospectus, which are commonly used in the oil and natural gas industry:

“Bbl” refers to one stock tank barrel, of 42 U.S. gallons liquid volume, used in this prospectus 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.

“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.

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

“CO2” refers to carbon dioxide.

“CO2e” refers to carbon dioxide equivalent.

“developed acreage” refers to the number of acres that are allocated or assignable to productive wells or wells capable of production.

“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.

“dry hole” refers to a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Effective NRI” refers to our share of leasehold ownership after all burdens, such as royalty and overriding royalty interests, have been deducted from the working interest, weighted by our net acres owned in the Barnett from the assets acquired in the Devon Barnett Acquisition and the Exxon Barnett Acquisition.

“gross acres,” “gross acreage” or “gross wells” refers to the total acres, acreage or wells, as the case may be, in which a working interest is owned.

“IPIECA” refers to the International Petroleum Industry Environmental Conservation Association.

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“lean gas” refers to natural gas that contains a few or no liquefiable liquid hydrocarbons.

“LNG” refers to liquefied natural gas.

“Maintenance Reinvestment Rate” for any period refers to the maximum rate of our total cash paid for upstream capital expenditures (excluding leasehold costs and acquisitions) for such period as a percentage of Adjusted EBITDAX for the same period that is necessary to hold our production for such period flat.

“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 Btus.

“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.

“Mtpa” refers to million metric tons of LNG per year.

“Mtpy” refers to million metric tons per year.

“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 operated development well” refers to a gross operated development well that has been drilled, proportionately reduced by our working interest in such well.

“NGL” refers to natural gas liquids.

“NYMEX” refers to the New York Mercantile Exchange.

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

“possible reserves” refers to those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these

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areas are in communication with the proved reservoir. Where direct observation has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

“probable reserves” refers to those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. Where direct observation has defined an HKO elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

“proved developed non-producing reserves” refers to proved developed reserves expected to be recovered from (i) completion intervals that are open at the time of the estimate but which have not yet started producing, (ii) wells which were shut-in for market conditions or pipeline connections, (iii) wells not capable of production for mechanical reasons or (iv) zones in existing wells that will require additional completion work or future re‑completion before start of production with minor cost to access these reserves, in each case, which production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. While not a requirement for disclosure under SEC regulations, proved developed non-producing reserves have been sub-classified and calculated by Ryder Scott in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

“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. While not a requirement for disclosure under SEC regulations, PDP reserves have been sub-classified and calculated by Ryder Scott in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

“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

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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 an 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 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.

“PUD reserves” refers to proved undeveloped reserves.

“rich gas” refers to natural gas containing heavier hydrocarbons than a lean gas.

“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.

“Tcfe” refers to one trillion cubic feet of natural gas equivalent.

“undeveloped acreage” refers to acreage under lease on which wells have not been drilled or completed such that there is not production of commercial quantities of hydrocarbons.

“undeveloped reserves” are 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 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 Reinvestment Rate” for any period refers to our total cash paid for upstream capital expenditures (excluding leasehold costs and acquisitions) for such period as a percentage of Adjusted EBITDAX for the same period.

“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.

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Commonly Used Defined Terms

As used in this prospectus, unless the context indicates or otherwise requires, the terms listed below have the following meanings:

“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, Banpu, 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 78.66% of Banpu Power as of June 30, 2023.

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

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

“BKV Chaffee” refers to BKV Chaffee Corners, LLC, a Delaware limited liability company and wholly owned subsidiary of BKV Corporation.

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

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

“BKVerde” refers to BKVerde, LLC, a Delaware limited liability company and wholly owned subsidiary of BKV dCarbon Ventures.

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

“BKV O&G” refers to BKV Oil and Gas Capital Partners, L.P., a Delaware limited partnership and wholly owned subsidiary of BKV Corporation, which was dissolved on September 19, 2022, on which date all ownership interests in subsidiaries of BKV O&G were assigned to BKV Corporation.

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

“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 own an indirect 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 own a 50% interest.

“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.

“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.

“bylaws” refers to the second amended and restated bylaws of BKV Corporation to be adopted in connection with the consummation of this offering.

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

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“certificate of incorporation” refers to the second amended and restated certificate of incorporation of BKV Corporation to be adopted in connection with the consummation of this offering.

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

“Data Lake” refers to a centralized cloud, large data technology that stores all company data and enables dashboards, visualizations, and analytics from a variety of systems and inputs.

“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.

“Exxon Barnett Acquisition” refers to our acquisition of approximately 165,000 net acres, 2,100 operated wells and related natural gas upstream, midstream and other assets in the Barnett from XTO Energy, Inc. and Barnett Gathering LLC, subsidiaries of Exxon Mobil Corporation, which closed on June 30, 2022.

“FID” refers to final investment decision.

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

“GHG” refers to greenhouse gases.

“governing documents” refers to our certificate of incorporation and our bylaws.

“High West” refers to High West Sequestration, LLC, a Louisiana limited liability company and wholly owned subsidiary of BKV dCarbon Ventures.

“HRCO” refers to 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.

“Kalnin Ventures” refers to Kalnin Ventures LLC, a Colorado limited liability company and wholly owned subsidiary of BKV Corporation.

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

“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.

“NGP” refers to natural gas processing.

“Responsibly Sourced Gas” or “RSG” refers to natural gas produced from a well which has gone through Project Canary’s TrustWell environmental assessment and verification process and has a current TrustWell rating.

“Ryder Scott” refers to Ryder Scott Company, L.P., independent petroleum engineers.

“SREC” refers to Solar Renewable Energy Credit, which represents a form of environmental attribute associated with solar energy generation, which can be marketed for financial gain to improve project economics or retired to offset the SREC owners’ Scope 2 emissions. For every 1000 kilowatt-hours of electricity produced by an eligible solar facility, one renewable energy credit and one compliance premium is awarded. The combination of a renewable energy credit and a compliance premium is known as an SREC. For a solar facility to be credited with that SREC, the system must be certified and registered by state agencies.

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

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

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PROSPECTUS SUMMARY

This summary highlights certain information about us and this offering contained elsewhere in this prospectus, but it is not complete and does not contain all of the information you should consider before making an investment decision. In addition to this summary, you should read this entire prospectus carefully, including the sections titled “Risk Factors,” “— Summary Historical and Unaudited Pro Forma Financial Information,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our historical consolidated financial statements and the related notes thereto included elsewhere in this prospectus, before making an investment decision. This summary contains forward-looking statements that involve risks and uncertainties. See “Cautionary Statement Regarding Forward-Looking Statements.” References in this prospectus to “BKV,” the “Company,” “we,” “us,” “our” and like terms are to BKV Corporation, a Delaware corporation, and its wholly owned subsidiaries, unless the context otherwise requires or we otherwise state.

Our Company

Overview

We are a forward thinking, growth driven energy company focused on creating value for our stockholders through the organic development of our properties as well as accretive acquisitions. Our core business is to produce natural gas from our owned and operated upstream businesses, which we expect to achieve net zero Scope 1 and Scope 2 emissions by the end of 2025, and net zero Scope 1, 2 and 3 emissions from our owned and operated upstream business by the early 2030s. We maintain a “closed-loop” approach to our net zero emissions goal with our four business lines: natural gas production, natural gas gathering, processing and transportation (our “natural gas midstream business”), power generation, and carbon capture, utilization and sequestration (“CCUS”). We are committed to building a vertically integrated business to reduce costs and improve overall commercial optimization of the full value chain. For instance, our natural gas production in the Barnett is gathered and transported through our midstream systems, and we are pursuing CCUS projects on our assets and third-party assets, with our first two CCUS projects expected to commence sequestration activities by the end of 2023 and 2024, respectively, and a robust backlog of actionable opportunities. We also are seeking to establish arrangements to supply our natural gas production directly to the BKV-BPP Power Joint Venture. We believe that our differentiated business model, net zero emissions focus, highly experienced management team and technology-driven approach to operating our business will enable us to create stockholder value.

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We understand the impact climate change has on our community, the world and future generations, which is why addressing these impacts in how energy is produced is a top priority. In particular, it is one of our core values, “Be One BKV,” to create a unified team with a shared vision to achieve our emission reduction and energy impact goals.

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Our Operations

Natural Gas Production

We are engaged in the acquisition, operation and development of natural gas and NGL properties primarily located in the Barnett Shale in the Fort Worth Basin of Texas (the “Barnett”) and in the Marcellus Shale in the Appalachian Basin of Northeastern Pennsylvania (“NEPA”). Our upstream assets are the core of our business and provide us with substantial Adjusted Free Cash Flow, which we expect will be sufficient to fund our upstream, midstream and power capital expenditure program while maintaining a conservative balance sheet. We have a balanced portfolio of low decline producing properties and undeveloped inventory, primarily in the Barnett. Additionally, our focus on operational efficiencies, access to BKV-owned and third-party midstream systems, and proximity to natural gas demand markets along the Gulf Coast and Northeast corridor allow us to generate high margins.

As of June 30, 2023, our total acreage position was approximately 497,000 net acres, 99% of which was held by production. For the six months ended June 30, 2023, our net daily production averaged 878.2 MMcfe/d, consisting of approximately 80% natural gas and approximately 20% NGLs. As of June 30, 2023, our total proved reserves of 5,481 Bcfe had an estimated 7.9% year-over-year average base decline rate over the next 10 years. We have more than 10 years of core inventory remaining, with attractive returns, based on a 1 to 1.5 rigs per year pace, including 158 proved undeveloped, 169 probable and 180 possible horizontal locations, and 571 proved developed non-producing, 755 probable and 286 possible refracture (“refrac”) candidates. Based on current commodity prices, the capital investment required to hold production flat year-over-year is less than approximately 35% of our Adjusted EBITDAX for the 2022 fiscal year. Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP. See “— Summary Historical and Unaudited Pro Forma Financial Information — Non-GAAP Financial Measures” for a description of this measure and a reconciliation to the most directly comparable GAAP measure.

We entered the Barnett in October 2020 with our acquisition of more than 289,000 net acres and 3,850 producing operated wells and related upstream assets (the “2020 Barnett Assets”) from Devon Energy Corporation (“Devon Energy”). On June 30, 2022, we further scaled our Barnett position by acquiring approximately 165,000 net acres, 2,100 operated wells and related upstream, midstream and other assets in the Exxon Barnett Acquisition. As of June 30, 2023, our Barnett acreage position was approximately 460,000 net acres, which is approximately 99% held by production. Our average daily Barnett production of approximately 728.7 MMcfe/d for the six months ended June 30, 2023 consisted of 76% natural gas and 24% NGLs. We had an average working interest in our operated wells in the Barnett of approximately 95.4% as of June 30, 2023 and an Effective NRI in the Barnett of approximately 80.2%.

We are the largest natural gas producer by gross operated volume in the Barnett. Based on information published by the Texas Railroad Commission (“TRRC”), the chart below illustrates our gross operated production volumes in the Barnett as of April 2023, which represent approximately 36% of the total Barnett production, and more than double than that of the next largest producer in the Barnett for the month of April 2023.

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We entered NEPA in 2016 and have subsequently scaled our position through 12 acquisitions. As of June 30, 2023, our acreage position was approximately 37,000 net acres, which is approximately 97% held by production. Our average net daily production of 149.5 MMcfe/d for the six months ended June 30, 2023 consisted entirely of natural gas. We had an average working interest in our operated wells in NEPA of 89.7%, as of June 30, 2023.

Natural Gas Midstream

Through our ownership in midstream systems, we are engaged in the gathering, processing and transportation of natural gas (which we refer to as our natural gas midstream business) that supports our upstream assets and third-party producers in the Barnett and NEPA. Our midstream assets improve our overall corporate returns by enhancing our margins and lowering our break-even operating costs while allowing us to manage the timing, development and optimization of production of our upstream assets. In the Barnett, during the six months ended June 30, 2023, approximately 228 MMcf/d of our gross production (approximately 28% of our total gross Barnett production) was gathered and processed by our owned Barnett midstream system, which includes approximately 778 miles of gathering pipeline, 65 midstream compressors and one amine processing unit. Additionally, our owned Barnett midstream system has over 200 MMcf/d in unutilized pipeline and processing capacity, providing room to increase throughput (from our own production and for third-party volumes) while maintaining optimal operating pressure with limited additional capital investment required. We also believe we have ample dedicated capacity on third party midstream systems for our expected production and future development. In NEPA, as of June 30, 2023, we had an approximate 29.4% non-operated ownership interest in a midstream system, which is operated by subsidiaries of Repsol Oil & Gas (“Repsol”), with throughput of approximately 174 MMcf/d, and we separately own and operate approximately 16 miles of natural gas gathering pipelines, 14 miles of freshwater distribution pipelines and six gas compression units.

Power Generation

We have a 50% ownership interest in the BKV-BPP Power Joint Venture, which owns the Temple Plants, modern combined cycle gas and steam turbine power plants located in the Electric Reliability Council of Texas (“ERCOT”) North Zone in Temple, Texas. The remaining 50% interest is owned by BPPUS, a wholly owned subsidiary of Banpu Power and an affiliate of our sponsor, Banpu. Temple I and Temple II have annual average power generation capacities of 752 MW and 751 MW, respectively, and each power plant delivers power to customers on the ERCOT power network in Texas. Temple I and Temple II have baseload design heat rates of approximately 6,904 Btu/kWh and 6,950 Btu/kWh, respectively, which are below the ERCOT Combined Cycle Gas Turbines (“CCGT”) average. The modern technology utilized at the

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Temple Plants enables them to respond to rapidly changing market signals in real time, ensuring the highest operational readiness during the time when electricity consumption peaks (in winter and summer), making the power plants well-suited to serve the various needs of the ERCOT market. We expect our power generation assets will be synergistic with our base upstream business. In the near term, we will seek to establish midstream contracts that allow us to supply our own natural gas directly to the Temple Plants and the firm natural gas storage service at the Bammel storage facility. Supplying our own natural gas to one or both of the Temple Plants could potentially reduce gas transportation costs and create reciprocal natural hedges for both businesses via vertical integration. Additionally, we leverage our existing organization to provide marketing, engineering, finance, accounting and other administrative services to the BKV-BPP Power Joint Venture for an annual fee plus expenses.

In addition, after receiving the necessary approvals from the Public Utility Commission of Texas (the “PUCT”) and ERCOT, the BKV-BPP Power Joint Venture recently launched a retail marketing business to sell electricity to commercial, industrial, and residential retail customers in Texas through its wholly owned subsidiary, BKV-BPP Retail, LLC (“BKV-BPP Retail”), under the brand name BKV Energy. Since its official launch in February 2023, BKV Energy has built a portfolio of over 24,000 customers and is licensed to serve throughout the deregulated portions of Texas. Moreover, we intend to develop our ability to provide Carbon Sequestered Gas, a Scope 1, 2 and 3 carbon neutral natural gas product, and we believe that the expansion of our presence in the retail power space, along with the synergistic and opportunistic growth of our upstream, midstream and power generation businesses, will provide our retail energy business the opportunity to offer end consumers household energy sourced from Carbon Sequestered Gas. For more information about the risks involved in our retail power business and efforts to market Carbon Sequestered Gas, see “Risk Factors — Risks Related to Our Business Generally — Our long-term business plan involves the development of opportunities to offer end consumers household energy sourced from a Scope 1, 2 and 3 carbon neutral natural gas product.”

Carbon Capture, Utilization and Sequestration

Through our CCUS business, we aim to reduce man-made GHG emissions to the atmosphere by capturing CO2 emitted in connection with natural gas activities, whether from our own operations or third- party operations, as well as from other energy and industrial sources. Our process involves capturing CO2 before it is released into the atmosphere and then compressing the captured CO2 and transporting it via pipeline to sites where it can be injected into Underground Injection Control (“UIC”) wells for secure geologic sequestration. Additionally, we have engaged Project Canary to measure, analyze and report the environmental attributes of the sequestration projects. Although we formally launched our CCUS business in March 2022 with the establishment of BKV dCarbon Ventures, we have been evaluating project opportunities and developing our CCUS business for approximately two years. The development of our CCUS business has progressed rapidly, supported by internal engineering, business development and regulatory professionals, along with academics and CCUS-focused partnerships. We believe that with a continued and timely execution of our business plans, and the receipt of external funding in 2023, we will begin generating positive CCUS net income via tax credits and other tax benefits in 2025. We expect to fund our CCUS business with a combination of cash flows from operations and funding from a variety of external sources, which may include joint ventures, project-based equity partnerships and federal grants. The projected timeline for commercial operations and the generation of positive CCUS business revenue and positive earnings depends, in part, on our ability to secure external funding for up to 40% of the anticipated capital requirements for the potential projects that we have identified and described below.

We seek to execute CCUS projects with attractive standalone economics for high, medium and low CO2 concentration streams that will sequester emissions from both our own operations and from third-party operations. As part of our “closed-loop” approach to our net zero emissions goal, we expect to apply the CO2 emissions that are sequestered through our CCUS business to offset GHG emissions from our owned and operated upstream businesses. As a result, we expect our CCUS business to contribute to our goals to fully offset the Scope 1 and 2 emissions from our owned and operated upstream businesses by the end of 2025, and the Scope 1, 2 and 3 emissions from our owned and operated upstream businesses by the early 2030s. We estimate that our owned and operated upstream Scope 1 and 2 annual emissions were approximately 1.7 Mtpy CO2e as of December 31, 2022 and that our owned and operated upstream Scope 1, 2 and 3 annual emissions were approximately 15.32 Mtpy CO2e as of December 31, 2022. See “— Path to Net Zero

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Emissions” below for a description of how we estimate our Scope 1, 2 and 3 annual emissions and how we expect our CCUS business to contribute to the offset of those emissions.

On August 22, 2022, we entered into a development agreement with Verde CO2, an independent carbon capture and sequestration developer and operator, to identify, evaluate and develop CCUS projects throughout the United States. We believe our agreement with Verde CO2 will expand our CCUS and GHG emissions reduction efforts as we seek to decarbonize industrial point sources of various sizes through carbon capture and permanent sequestration. Pursuant to the development agreement, Verde CO2 will be responsible for the sourcing, development, performance and ongoing management of such CCUS projects and BKV dCarbon Ventures will provide funding for such projects. In connection with such responsibilities, Verde CO2 will develop and present projects to us for acceptance and assignment to BKVerde; however, we cannot guarantee that all projects currently in development by Verde CO2 will be accepted and assigned to BKVerde. Through October 6, 2023, we have paid $25.9 million to Verde CO2 under the development agreement. Including such payments, we currently expect to invest up to $250.0 million by the end of 2025 to fund efforts by BKVerde, a subsidiary of BKV dCarbon Ventures, to efficiently identify and evaluate feasible CCUS projects, and to execute on those projects. We expect to fund BKVerde through our cash flows from operations but may also obtain funding from external sources.

Currently, we are pursuing twelve potential CCUS projects that we believe are commercially viable based on economics supported by enhanced Section 45Q tax credits and can be completed by the early 2030s. We anticipate that the completion of these or a combination of other comparable projects would enable us to achieve our Scope 1, 2 and 3 emissions goals. These twelve potential CCUS projects consist of a combination of projects being developed by BKV’s internal CCUS team and projects being developed by Verde CO2, as discussed above. We have entered into contracts and letters of intent that we expect to grant us carbon storage and sequestration rights on over 100,000 acres of pore space with total reservoir storage capacity of over 1 billion metric tons of CO2e. Our projected timeline for commercial operations of these twelve projects by the early 2030s depends in part on our ability to secure external funding for up to 40% of the anticipated capital requirements for the potential projects that we have identified. Our timeline also depends on a regulatory environment that is favorable to our projects and their development. These twelve potential projects can be placed into four categories: (i) those that have reached FID, (ii) near-term NGP projects, (iii) near-term industrial projects, and (iv) projects under evaluation. Near-term projects are those that we anticipate will reach FID in either 2023 or 2024. We have achieved notable milestones with respect to several of the projects within the four categories, as more fully described below.

FID Projects

We have reached FID and entered into definitive agreements with respect to the Barnett Zero Project, and we have reached internal FID for the Cotton Cove Project. These two projects have a combined forecasted annual sequestration volume of approximately 255,000 metric tons per year of captured CO2e by the end of 2024.

Barnett Zero Project.   In June 2022, we reached FID and entered into a definitive agreement in connection with our first high concentration CCUS project in the Barnett with EnLink Midstream, LLC (“EnLink”). This CCUS project, which we refer to as the Barnett Zero Project, will separate CO2 from substantially all of our EnLink-gathered natural gas production. In the Barnett Zero Project, EnLink will transport our natural gas produced in the Barnett to its natural gas processing plant in Bridgeport, Texas, where the CO2 waste stream will be captured, compressed and then disposed of and sequestered via our nearby injection well. We estimate the total investment required by us for the Barnett Zero Project to be approximately $33.0 million. We have successfully drilled a Class II well for the Barnett Zero Project that complies with standards applicable to Class VI wells and expect the Barnett Zero Project to achieve an average sequestration rate of up to approximately 210,000 metric tons of CO2e per year, with the first injection expected by December 2023. Additionally, the United States Environmental Protection Agency (“EPA”) has approved our Monitoring, Reporting and Verification Plan as required by the Greenhouse Gas Reporting Program. Following commencement of commercial operations of our project with EnLink, we intend to use this project as a prototype for modular NGP projects that can be repeated and quickly scaled.

Cotton Cove Project.   On October 18, 2022, BKV dCarbon Ventures reached internal FID to develop our second CCUS project in the Barnett. This CCUS project, which we refer to as the Cotton Cove Project,

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will separate, dispose of, and geologically sequester CO2 generated as a byproduct of our natural gas production in the Barnett and will utilize our BKV Midstream assets to do so. We have multiple Company-owned pore space opportunities for CO2 injection, and we estimate the Cotton Cove Project will geologically sequester up to approximately 45,000 metric tons of CO2 per year. The Cotton Cove Project is held through BKV-BPP Cotton Cove LLC (“BKV-BPP Cotton Cove” or the “BKV-BPP Cotton Cove Joint Venture”), a joint venture owned 51% by BKV dCarbon Ventures and 49% by BPPUS. We currently estimate the total investment required for the Cotton Cove Project to be approximately $17.6 million, of which we will be required to contribute approximately $9.0 million. We are targeting commencement of CO2 sequestration activities by the end of 2024, subject to our ability to secure all required permits, at which point we expect this project will be the second of our current modular line of identified potential NGP projects, in addition to the Barnett Zero Project. Additionally, BKV dCarbon Ventures will manage the BKV-BPP Cotton Cove Joint Venture and leverage our existing organization to provide marketing, engineering, finance, accounting and other administrative services to the BKV-BPP Cotton Cove Joint Venture, in each case for an annual fee plus expenses. For additional information about the Cotton Cove Joint Venture, see “Certain Relationships and Related Party Transactions — BKV-BPP Cotton Cove Joint Venture — BKV-BPP Cotton Cove Limited Liability Company Agreement.”

We are also seeking to expand the Barnett Zero and Cotton Cove Projects to pilot, and then scale, post-combustion carbon capture technology that would allow us to sequester up to an additional approximately 250,000 metric tons per year of captured CO2e from low concentration emissions from within our BKV Midstream and/or EnLink’s Bridgeport processing operations. As part of this process, we intend to utilize compressor waste heat to reduce energy requirements and cost.

NGP Projects

In addition to the Barnett Zero Project and the Cotton Cove Project, we have identified three potential NGP projects to sequester third-party emissions, which we expect to reach FID in either 2023 or 2024. If approved and implemented, these three projects would provide a combined forecasted annual sequestration volume of at least approximately 970,000 metric tons per year of captured CO2e.

A significant portion of the carbon capture infrastructure necessary to execute these potential NGP projects already exists, one of which is currently being developed by Verde CO2 under our development agreement with them and for which project Verde CO2 has entered into a non-binding letter of intent for pore space leasehold. For another one of these projects, we have entered into definitive agreements for pore space leasehold that would provide approximately 45 million metric tons of CO2e sequestration capacity, and for the third of these projects, we have entered into a definitive agreement for requisite pore space leasehold. Therefore, if approved at FID, and assuming we are able to execute definitive agreements on the terms and timeline we believe are obtainable and secure sufficient external funding, we expect these projects to start sequestration operations before December 31, 2025. We expect that by the end of 2025, these three NGP projects will have initial individual annual sequestration volumes of approximately 70,000, 265,000 and 635,000 metric tons per year of captured CO2e, respectively, and a combined annual aggregate sequestration volume of approximately 970,000 metric tons per year of captured CO2e. In addition, we expect over time to submit permit applications to develop Class VI injection wells in order to expand the sequestration capacity of two of these NGP projects to gradually build up to a forecasted annual sequestration volume after 2025 for all three of these NGP projects of approximately 3.3 million metric tons per year of captured CO2e.

We expect by the end of 2025 that the combined annual forecasted sequestration volume from these NGP projects, the Barnett Zero Project and the Cotton Cove Project (collectively having an annual forecasted sequestration volume of approximately 1.23 Mtpy CO2e), would be capable of offsetting annually more GHG emissions than our remaining Scope 1 and 2 annual emissions from our owned and operated upstream businesses after taking into account the expected GHG emissions reductions from our “Pad of the Future” program, reductions attributable to emissions monitoring and leak surveys and Scope 2 emissions offsets from the retirement of SRECs generated by our planned solar farm (such remaining emissions estimated to be approximately 0.70 Mtpy CO2e). See “— Path to Net Zero Emissions.” However, we have not secured external financing, reached FID or entered into definitive agreements for any of these three additional NGP projects. We may not complete all or any of these three additional NGP projects, the Barnett Zero Project

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or the Cotton Cove Project by December 31, 2025, in which case, we may consider alternatives to offset our Scope 1 and Scope 2 owned and operated upstream emissions (including the purchase of verified offset credits). Ultimately, we may not be able to achieve our goals of net zero Scope 1 and 2 emissions from our owned and operated upstream businesses by the end of 2025 and Scope 1, 2 and 3 emissions from our owned and operated upstream businesses by the early 2030s.

Industrial Projects

We are currently evaluating three potential medium to higher concentration industrial projects to sequester third-party emissions, which we anticipate will reach FID in either 2023 or 2024. If approved and implemented, these three projects would provide a combined forecasted annual sequestration volume of approximately 16.7 million metric tons per year of captured CO2e.

Two of the three projects are being developed by Verde CO2 under our development agreement with them. Pore space leaseholds have been secured for all three of these projects, including one covering approximately 21,000 acres of state-owned land in Louisiana, which project we refer to as the High West Project and expect to reach FID by the end of 2024. For more information about the High West Project, see “— Recent Developments — Projects and Acquisitions — Carbon Sequestration Agreement with the State of Louisiana.” We also anticipate that Class VI permit applications for each of these projects will be submitted during 2023. If each of these projects is approved at FID and we are able to secure sufficient external financing, and assuming definitive agreements are timely executed containing terms we believe are obtainable, we expect to initiate sequestration operations between 2025 and 2029.

Additional Projects

We are currently evaluating and have begun commercial discussions with respect to four additional CCUS projects that we anticipate may reach FID after 2024. If approved and implemented, these four projects would provide a combined forecasted annual sequestration volume of approximately 9.8 million metric tons per year of captured CO2e.

If each of these projects is approved at FID and assuming we are able to execute definitive agreements on the terms and timeline we believe are obtainable and secure sufficient external funding, we expect to begin sequestration operations between 2026 and 2029.

Our CCUS business of capturing and sequestering emissions from our operations and from operations of third parties is a critical component of our “closed-loop” approach to achieving our goal of net zero Scope 1, 2 and 3 emissions from our owned and operated upstream businesses by the early 2030s. We expect to continue to identify and evaluate additional CCUS projects and we believe that we will be able to complete a sufficient number of the above-described or other CCUS projects in order to meet our Scope 1, 2 and 3 emissions goals by the early 2030s. See “— Path to Net Zero Emissions” for a more detailed description of how we anticipate reaching our Scope 1, 2 and 3 emissions goals.

While the aggregate forecasted annual volume of CO2e captured and sequestered from our twelve identified potential CCUS projects is approximately 30 million metric tons per year, which is more than our current Scope 1, 2 and 3 annual emissions from our owned and operated upstream businesses, we do not anticipate achieving an aggregate yearly volume of sequestration of 30 million metric tons per year of captured CO2e by the early 2030s. Furthermore, there can be no guarantee that we will be able to execute and complete any of the twelve identified CCUS projects (or any other CCUS projects) with sufficient volumes of CO2e sequestration to achieve our Scope 1, 2 and 3 emissions goals on the timelines we anticipate.

We estimate the aggregate investment required by us to fund a sufficient number of the identified potential CCUS projects in order to achieve our Scope 1, 2 and 3 emissions goals to be between approximately $1.3 billion and $1.8 billion over the next seven to ten years. We anticipate that some of these project costs will be borne by third-party investors in these projects, including emitters, landowners and other stakeholders. In order to achieve the projected timeline for commercial operations of such projects, we expect to fund the anticipated cost of these CCUS projects with a combination of cash flows from operations and up to 40% from external sources, which may include joint ventures, project-based equity partnerships and federal grants. We are able to moderate the capital required to fund our CCUS business, as our CCUS business

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model provides flexibility for us to selectively invest in only the sequestration component of a project or in the capture, transportation and sequestration components, depending on the scope of the project. Therefore, if sufficient external funding is not available, then we would expect to continue to develop our CCUS business from cash flows from operations on a less accelerated timeline, which may result in an inability to achieve our Scope 1, 2 and 3 emissions goals on the timeline we anticipate.

Our CCUS business and all of our CCUS projects are in the early stages of development and while we have reached FID and entered into definitive agreements with respect to the Barnett Zero Project and reached internal FID for the Cotton Cove Project, we have not reached FID with respect to or entered into the definitive agreements necessary to execute any of the other ten potential projects identified above. We may not be able to reach agreements on terms acceptable to us or achieve our projected timeline for commercial operations for these projects. In addition, the development of our CCUS business is expected to require material capital investments, and the projected timeline for commercial operations depends on our ability to secure external funding for up to 40% of the anticipated capital requirements for the potential projects that we have identified. Furthermore, the commercial viability of our CCUS projects depends, in part, on obtaining necessary permits and other regulatory approvals and on certain financial and tax incentives provided by the U.S. federal government. In particular, we must meet certain wage and apprenticeship requirements in order to qualify for enhanced Section 45Q tax credits. For more information about the risks involved in our CCUS business, see “Risk Factors — Risks Related to Our CCUS Business.”

To help us achieve our goal of becoming a leader in CCUS, we established a steering committee that includes two engineers renowned for their work in the development of CCUS projects: Dr. Paitoon (P.T.) Tontiwachwuthikul (Professor of Industrial & Process Systems Engineering & Fellow, Canadian Academy of Engineering) and Dr. Malcolm A. Wilson (Program Director, CO2 Management, Office of Energy & Environment (OEE), Adjunct Professor of Engineering and Graduate Studies). These individuals are professors at the University of Regina, a leading carbon capture research institution, and each has been engaged in CCUS for over 30 years.

For more information on our CCUS business, see “Business  —  Our Operations — Carbon Capture, Utilization and Sequestration.”

Path to Net Zero Emissions

We estimate that our owned and operated upstream Scope 1 and 2 annual emissions were approximately 1.70 Mtpy CO2e as of December 31, 2022. This reflects a reduction of 0.5 Mtpy CO2e from our estimated owned and operated upstream Scope 1 and Scope 2 annual emissions as of December 31, 2021 due to the implementation of “Pad of the Future” emissions reductions that began in the fourth quarter of 2021 and occurred throughout 2022. The 2022 estimate is also inclusive of the assets acquired in the Exxon Barnett Acquisition in June 2022.

Our emissions estimates presented in this prospectus are based on information with respect to our owned and operated assets in the Barnett and NEPA through fiscal year 2022 and reported by BKV pursuant to the Subpart C and Subpart W, as applicable, requirements of the federal Clean Air Act GHG reporting program regulations of the EPA. These estimates fluctuate throughout the year and will be updated on an annual basis to reflect any changes in activity, inventory, production throughput, and emissions reduction retrofits or equipment modifications.

We estimate that our owned and operated upstream Scope 3 annual emissions were approximately 13.62 Mtpy CO2e as of December 31, 2022. These Scope 3 GHG emissions are currently estimated in accordance with IPIECA’s “Sustainability reporting guidance for oil and gas industry,” dated March 2020, specifically for Scope 3 emissions as estimated per Category 11 (Use of Sold Product). Scope 3 emissions estimated using source Category 11 represent the majority of Scope 3 emissions from our upstream operations with minor contributions from other source categories. Additionally, our estimated Scope 3 emissions calculations assume that all natural gas produced is combusted and does not account for other potential end use of natural gas. Scope 3 mass emissions are calculated using the EPA’s prescribed emissions factors for the speciated natural gas (methane and ethane) as well as NGLs assuming Y-grade NGLs. CO2e emissions are estimated using AR4 Global Warming Potentials, similar to those used by the EPA. Our projected Scope 3 CO2e annual emissions are estimated at an approximated year-end net production

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volume of 900 MMcfe/d, with an approximate split of 80% natural gas (95% methane and 5% ethane) and 20% NGLs. Our NGL constituents are estimated based on average constituent NGL barrel. Allocating the entire 900 MMcfe/d towards combustion as the end use, applying suitable combustion emission factors from the EPA, and using AR4 GWPs, Scope 3 annual emissions from our owned and operated upstream operations are estimated to be approximately 13.62 Mtpy CO2e. We currently engage third party consultants to develop and review our Scope 3 emissions estimates.

The charts below reflect (i) our owned and operated upstream Scope 1 and 2 annual emissions estimates as of December 31, 2022, and (ii) our owned and operated upstream Scope 3 annual emissions estimates as of December 31, 2022, in each case, inclusive of the emissions generated by the assets acquired in the Exxon Barnett Acquisition. These two charts also reflect our intended path to net zero Scope 1 and 2 emissions by the end of 2025 and net zero Scope 1, 2 and 3 emissions by the early 2030s, in each case, for our owned and operated upstream businesses. As part of our “closed-loop” approach to our emissions goals, we intend to achieve these goals through our “Pad of the Future” emissions reductions, reductions attributable to emissions monitoring and leak surveys, emissions offsets from installing solar power and executing CCUS projects to sequester our and third-party emissions.

(1)

Scope 1 and 2 calculated emissions are based on 830 MMscf/d production volume (net sales) for 2022 Subpart W in the Barnett and 144 MMscf/d production volume for 2022 Subpart W in NEPA.

(2)

Emissions surveys to accomplish a one-to-two month leakage review period versus 12-month period which must have regulatory updates (current proposed OOOO.b,c) to include continuous flyover/​satellite technology sensitivities.

(3)

Installation of a 2.5 MW to 5 MW solar farm. We have obtained permits for 2.5 MW and are in the process of obtaining permits for the remaining 2.5 MW.

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(1)

Scope 1 and 2 calculated emissions are based on 830 MMscf/d production volume for 2022 Subpart W in the Barnett and 144 MMscf/d production volume for 2022 Subpart W in NEPA.

(2)

Emissions surveys to accomplish a one-to-two month leakage review period versus 12-month period which must have regulatory updates (current proposed OOOO.b,c) to include continuous flyover/​satellite technology sensitivities. Installation of a 2.5 MW to 5 MW solar farm. We have obtained permits for 2.5 MW and are in the process of obtaining permits for the remaining 2.5 MW.

(3)

Scope 3 calculated emissions are based on an estimated net production rate of approximately 900 MMcfe/d (approximately 720 MMscf/d of natural gas and 31,000 Bbl/day of NGLs).

(4)

Scope 3 calculated emissions are estimated assuming fuel-based usage of all produced natural gas and NGLs. Approximately 58% of NGLs are assumed to be combusted for fuel while 100% of all natural gas sold is assumed to be combusted for fuel. Scope 3 emissions estimation methodology is therefore considered to be conservative.

Planned Path to Net Zero (Scope 1 and 2)

Pad of the Future.   Our “Pad of the Future” program implements pad level design improvements to reduce pad level usage of natural gas, reduce GHG emissions, and maintain operational continuity. As of December 31, 2022, we had implemented elements of our “Pad of the Future” program on approximately 2,500 of our existing wells, thereby eliminating an aggregate of approximately 0.38 Mtpy CO2e in annual GHG emissions from commencement in the fourth quarter of 2021 through such date. Our estimated emissions reduction from year-end 2021 to year-end 2022 was primarily the result of our “Pad of the Future” program. These reductions are calculated by using our pneumatic and other pad inventories, and such emissions are factored to be eliminated once the system has been converted from natural gas supplied to compressed air or electric.

We expect to implement elements of our “Pad of the Future” program on more than 6,000 of our existing wells (more than 8,000 pneumatic devices and 2,000 pneumatic pumps) by the end of 2025 for an aggregate estimated cost of approximately $35 to $40 million. Once this expansion is completed, we expect to eliminate approximately 0.77 Mtpy CO2e, or approximately 45%, of the currently estimated Scope 1 and 2 annual emissions from our owned and operated upstream businesses.

Emissions Monitoring and Solar.   Our leak detection and repair emissions monitoring program involves continuous ground-based instrument monitoring, satellite-based monitoring, aerial flyovers, and on the ground leak detection and repair inspections. In addition, we expect to install a 2.5 MW to 5 MW solar farm, which is scheduled to begin generating power in 2024. We have obtained permits for 2.5 MW and are in the process of obtaining permits for the remaining 2.5 MW. For every 1,000 kilowatt-hours of electricity produced by an eligible solar facility, one SREC is awarded. For a solar facility to be credited with that SREC, the system must be certified and registered by state agencies. The solar farm is expected to generate

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enough SRECs, when combined with our leak detection and repair emissions monitoring program, to offset approximately 0.23 Mtpy CO2e in GHG emissions from our owned and operated upstream businesses. Solar facilities may be subject to increasingly arduous regulatory requirements, including additional permitting requirements.

CCUS.   Further, as discussed under “— Carbon Capture, Utilization and Sequestration” above, we believe that the Barnett Zero Project and the Cotton Cove Project, together with the three additional near-term NGP projects for the capture and sequestration of third-party emissions that we have identified, have a combined annual forecasted sequestration volume of approximately 1.23 Mtpy CO2e. We believe that these projects are capable of offsetting by the end of 2025 more than the approximately 0.70 Mtpy CO2e Scope 1 and 2 emissions from our owned and operated upstream businesses that we currently estimate will remain after taking into account the expected emissions reductions from our “Pad of the Future” program and emissions monitoring and leak surveys and Scope 2 emissions offsets from the retirement of SRECs generated by our planned solar farm. Although no definitive agreements have been entered into with respect to any of these additional NGP projects, we expect these projects to reach FID in either 2023 or 2024. A significant portion of the carbon capture infrastructure necessary to execute these potential NGP projects already exists and, as discussed above, we continue to accomplish important milestones consistent with our projected timeline. Therefore, if approved at FID, and assuming we are able to execute definitive agreements on the terms and timeline we believe are obtainable and secure sufficient external funding, we expect these projects to start sequestration operations before December 31, 2025. If we are unable to complete each of these three projects before December 31, 2025, we may still reach our Scope 1 and 2 emissions goals with less than all of these projects completed as, individually, the annual forecasted sequestration volume by the end of 2025 of (i) the Barnett Zero Project is 0.21 Mtpy CO2e, (ii) the Cotton Cove Project is 0.05 Mtpy CO2e and (iii) the three near-term NGP projects is .07, 0.27 and 0.64 Mtpy CO2e, respectively. However, we have not secured external funding, reached FID or entered into definitive agreements for any of these three additional NGP projects. We may not complete all or any of these three additional NGP projects, the Barnett Zero Project or the Cotton Cove Project by December 31, 2025, in which case, we may consider alternatives to offset our Scope 1 and Scope 2 owned and operated upstream emissions (including the purchase of verified offset credits or pursuing alternative CCUS projects) but, ultimately, we may not be able to achieve our goal of net zero Scope 1 and 2 emissions from our owned and operated upstream businesses by the end of 2025.

Planned Path to Net Zero (Scope 1, 2 and 3)

We also aspire to offset the Scope 3 emissions impact of our owned and operated upstream businesses by the early 2030s, which we estimate to be approximately 13.62 Mtpy CO2e annually as of December 31, 2022, and our CCUS business of capturing and sequestering our and third-party emissions is a critical component to achieving this net zero goal. This aspiration to offset the Scope 3 emissions of our owned and operated upstream businesses by the early 2030s is limited to our Category 11 (Use of Sold Product) emissions. As discussed in “— Carbon Capture, Utilization and Sequestration,” above, we have identified twelve potential CCUS projects that we believe are commercially viable that we estimate would have a combined forecasted annual volume of carbon capture and sequestration of approximately 30 Mtpy CO2e (which exceeds our current Scope 1, 2 and 3 annual emissions from our owned and operated upstream businesses). This forecast of annual sequestration volume of our and third-party emissions includes all twelve of our identified CCUS projects, including the Barnett Zero Project, the Cotton Cove Project and the three potential near-term NGP projects described in “— Planned Path to Net Zero (Scope 1 and 2)” above. While we expect to pursue a sufficient number of CCUS projects to achieve our Scope 3 emissions goal, we do not anticipate achieving an aggregate yearly volume of sequestration of 30 million metric tons per year of captured CO2e before the early 2030s.

Large scale CCUS projects are subject to numerous risks and uncertainties, including securing third-party financing, reaching definitive agreements with third parties and obtaining necessary permits and other regulatory approvals, and we may be unable to execute on some or all of these projects, including the projects for which we have reached FID, on the timeline we anticipate, on terms acceptable to us or at all. There can be no guarantee that we will be able to execute and complete any of these identified CCUS projects and there can be no guarantee that we will be able to achieve our net zero Scope 1, 2 and 3 emissions goals. The projected timeline for commercial operations of our CCUS projects depends in part on our

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ability to secure external funding for up to 40% of the anticipated capital requirements for the potential projects that we have identified. If sufficient external funding is not available, then we would expect to continue to develop our CCUS business from cash flows from operations on a less accelerated timeline. If we are not able to complete CCUS projects having a sufficient forecasted volume of carbon capture to offset our Scope 1, 2 and 3 annual emissions on the timeline and upon terms that we believe are obtainable, we may not be able to achieve our goal of net zero Scope 1, 2 and 3 emissions from our owned and operated upstream businesses by the early 2030s.

In addition, our path to net zero does not address GHG emissions from other business operations, including our midstream, power or CCUS business operations, but solely GHG emissions relating to our owned and operated upstream businesses. Although we believe our current path to net zero will be sufficient to reduce emissions related to our existing owned and operated upstream businesses, the future growth of our natural gas production assets will result in additional CO2e emissions. We believe our approach to reducing the emissions from our owned and operated upstream operations is repeatable and scalable. Through continued investment and expansion of our “Pad of the Future” program, our emissions and leak surveys as well as additional CCUS and solar projects, we believe will be able to offset any such additional emissions from our owned and operated upstream businesses resulting from our continued growth.

Business Strategy

Our strategy is to create value for our stockholders by managing and growing our integrated asset base and focusing on our net zero objectives. Our strategy has the following principal elements:

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Optimize the value of our core businesses.   We utilize technology and data analysis to enhance our assets and operations, which we believe improves operational efficiencies, reduces our emissions and helps us realize our operational and financial goals as we continue to scale our business. For example, our “Pad of the Future” program, which includes conversion of natural gas-powered instrument pneumatics to compressed air power instruments on existing pads, combined with emission and leak surveys, is expected to eliminate or reduce approximately 1.15 Mtpy CO2e of our annual GHG emissions by the end of 2025. Our “Pad of the Future” application also improves pad efficiencies and operating revenue. By employing technology, data analytics and operational excellence, for the six months ended June 30, 2023, we have reduced our lease operating costs in the Barnett (excluding the 2022 Barnett Assets) by 3% compared to the six months ended June 30, 2022. These cost reduction initiatives decreased our average monthly operating costs by 10% for the three months ended June 30, 2023 compared to the six months ended December 31, 2022, based on average monthly costs associated with identical operating positions. In NEPA, we reduced our lease operating costs by 25% since January 2019, based on a twelve-month rolling average for this time period compared to the prior operatorship twelve-month rolling average ending in January 2019. Additionally, our refrac and long lateral drill programs have allowed us to organically grow our reserves base. As of June 30, 2023, our Barnett refrac program has added 371 Bcfe of proved reserves since its inception in early 2021, as well as an estimated 507 Bcfe of probable reserves and 150 Bcfe of possible reserves. As of June 30, 2023, our Barnett refrac program has an average of $0.79/Mcfe in finding and development costs with respect to proved reserves. This refrac program employs specifically designed perforating technology and a suite of innovative refrac techniques, as well as advanced refrac designs and diversion methods to maximize reserves recovery and economics from legacy Barnett wells. Our Barnett new well drilling program has added 679 Tcfe of proved reserves since our entry into the Barnett, with a total estimate of approximately 627 Bcfe of probable reserves and 406 Bcfe of possible reserves. By combining our reserves into a growing asset base with vertically integrated components, we believe we can enhance margins and create a “closed loop” business that reduces Scope 1 and 2 emissions from our owned and operated upstream businesses and captures margin across the value chain. Estimates of probable and possible reserves are inherently imprecise and are more uncertain than proved reserves but have not been adjusted for risk due to that uncertainty, and therefore they may not be comparable with each other and should not be summed either together or with estimates of proved reserves. For more information regarding the presentation of probable and possible reserves, see “Business — Preparation of Reserves Estimates and Internal Controls.”

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Grow through opportunistic, synergistic acquisitions.   A significant element of our business strategy is gaining scale through accretive acquisitions. We have a track record of growth through acquisitions,

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which we believe have been at attractive valuations. Since 2016, we have completed 19 acquisitions and two CCUS partnerships, resulting in greater than a 100% compound annual growth rate of Adjusted EBITDAX as of June 30, 2023. We believe our business model, management team experience and application of technology enable us to quickly and efficiently integrate additional upstream, midstream and power assets into our business.

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Maintain a disciplined financial strategy.   We believe we can execute on our business plan and grow our business while continuing to generate substantial Adjusted Free Cash Flow. We target a Maintenance Reinvestment Rate of less than 40% and an Upstream Reinvestment Rate of less than 50%. We are focused on our goal of maintaining a conservative financial profile, with a long-term Total Net Leverage Ratio target of 1.0x to 1.5x. Although we may allow our leverage ratio to exceed our target in connection with a strategic acquisition, we would seek to return our leverage level to between 1.0x and 1.5x as soon as reasonably possible thereafter through Adjusted Free Cash Flow and, if needed, reduced activity levels. To support the generation of future Adjusted Free Cash Flow, we have a policy of hedging approximately 25% to 60% of our production volumes over a given 12 to 24‑month period. We believe our capital efficient project inventory, low-decline natural gas production and multiple, integrated business lines will provide consistent returns through varying business cycles. We intend to apply our cash flows to manage our indebtedness in line with our leverage target, fund our capital expenditure program, enhance stockholder value and execute opportunistic acquisitions across our four business lines. Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP. See “— Summary Historical and Unaudited Pro Forma Financial Information — Non-GAAP Financial Measures” for a description of this measure and a reconciliation to the most directly comparable GAAP measure.

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Focus on our net zero objectives.   We seek to apply our integrated business model, CCUS projects, and carbon-negative initiatives to realize Scope 1 and 2 net zero upstream owned and operated emissions by the end of 2025. We believe we can achieve this through reductions in and offsets to our upstream emissions from our “Pad of the Future” emissions reductions program and emissions monitoring and leak surveys, installing solar power and executing CCUS projects. We believe that carbon emissions within the United States can be reduced substantially through carbon capture on natural gas production, power plants, processing facilities and other energy and industrial infrastructure. As such, in addition to lowering emissions in our owned and operated upstream businesses, CCUS for third parties has become a core focus of our business plan. We expect our CCUS projects to represent a meaningful portion of our budgeted capital expenditures going forward as we advance our long-term goal of offsetting Scope 3 emissions from our owned and operated upstream businesses.

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Encourage innovation.   Our distinctive culture encourages innovation with a value-driven focus that feeds into our competitive advantage. For example, our emphasis on the efficient application of modern technology led to the development of our “Pad of the Future” program, our advancements in Barnett refracs and other operational improvements. We intend to continue to develop, retain and add to our already talented, experienced and forward-thinking employees. Our unified team and mantra of “Being a force for good” underpin our core values and provides us with confidence in our ability to successfully manage and grow our business.

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Deliver robust returns to stockholders.   We intend to prioritize delivering strong returns to our stockholders through our focus on creating stockholder value. We believe our operational expertise in successfully drilling and refracturing wells, acquiring and integrating assets purchased at attractive valuations and maintaining financial discipline will underpin our ability to meet our stockholder return goals. Our integrated businesses and natural gas-weighted, low-decline PDP reserves collectively reduce our downside risk while providing asymmetric upside returns from the confluence of commodity price uplift potential, operational improvement and development opportunities, and future accretive acquisition opportunities. See “Risk Factors — Risks Related to the Offering and Our Common Stock.”

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Competitive Strengths

We have a number of strengths that we believe will help us successfully execute our business strategy, including:

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Integrated asset base well positioned for sustainable growth.   Our upstream, midstream and power asset bases reside in geographically concentrated areas with numerous asset acquisition opportunities in close proximity. Our proven ability to successfully negotiate, close and integrate these acquisition opportunities quickly and cost effectively will allow us to continue to grow our portfolio of assets synergistically. We believe that scale and the continued application of technological developments and operational excellence, combined with stable, low-decline production profiles, will continue to generate significant capital efficient development opportunities in the Barnett and NEPA.

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High quality, low decline assets serving key demand markets.   Through a series of accretive acquisitions, we have established an extensive and largely contiguous acreage position in two key markets, the Barnett and NEPA. Our Barnett assets cover approximately 460,000 net acres, with an approximately 80.2% Effective NRI, and are located in close proximity to key Gulf Coast industrial and LNG demand centers. Our NEPA assets consist of 37,000 net acres in one of the most prolific parts of the Marcellus Shale and are located within less than 200 miles to key demand markets in the U.S. Northeast. We believe the geologic, operational and engineering risks associated with our leasehold acreage have been significantly mitigated through historical development activity. Our PDP reserves had an estimated 7.9% year-over-year average base decline rate over the next 10 years as of June 30, 2023. Additionally, we have an inventory of over 10 years of refrac and new drill locations within our core acreage that give us the flexibility to maintain or slightly grow current production levels, depending on the commodity cycle.

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Lower emissions energy production.   We are focused on achieving Scope 1 and 2 net zero emissions from our owned and operated upstream businesses by the end of 2025. We believe we have a comprehensive ESG program, which is overseen and directed by an executive ESG steering committee. We have certified our entire NEPA production and a portion of our Barnett production and, in each case, achieved a Gold rating with Project Canary’s TrustWell environmental assessment (Project Canary is an environmental certification and ESG data company). This is the second highest rating a company can receive for its production, qualifying the certified portion of our natural gas production as Responsibly Sourced Gas, which may be considered less carbon-intensive by some purchasers due to the way it was produced. In addition, we intend to advance the market for our produced gas beyond RSG and its current certification towards Carbon Sequestered Gas, a Scope 1, 2 and 3 carbon neutral natural gas product. We expect that production of Carbon Sequestered Gas will be achieved by bundling RSG with carbon credits sufficient to offset the estimated emissions associated with the production, gathering and boosting of such RSG, as well as the estimated emissions from its transmission, distribution (if applicable) and ultimate combustion, with the quantified emissions and the requisite volume of CCUS offsets being third-party certified. The carbon credits included in our Carbon Sequestered Gas will be generated by our CCUS projects, as described in “— Overview — Our Operations — Path to Net Zero Emissions,” and retired against our Scope 1 and/or Scope 3 emissions. We believe Carbon Sequestered Gas could potentially provide a fully decarbonized, certified, and qualified fuel and retired credits bundle that is a differentiated and premium product. We expect that both RSG and Carbon Sequestered Gas could command a premium in the marketplace. Additionally, we have a plan to achieve net zero Scope 1 and 2 owned and operated upstream emissions by the end of 2025 based on our “Pad of the Future” program, emissions monitoring and leak surveys, installing solar power and executing CCUS projects. However, if we are not able to complete CCUS projects having sufficient sequestration volumes of CO2 on this timeline, we may consider alternatives to offset our Scope 1 and Scope 2 emissions (including the purchase of verified offset credits). Ultimately, we may not be able to achieve this goal, produce Carbon Sequestered Gas or obtain a premium on such gas (particularly to the extent there are any concerns regarding the type, ownership or quality of offsets or other environmental attributes used for our characterization of Carbon Sequestered Gas).

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Efficient use of capital.   Our deep, high-graded inventory of refrac opportunities coupled with our inventory of new drill locations allow us to create meaningful additional cash flow with comparatively

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modest additional capital investments. We utilize operational improvements such as operational process and procurement efficiencies, use of existing field infrastructure, innovative and cost-effective refrac techniques and designs (including diversion methods), drilling long laterals in the Barnett, and optimizing available midstream capacity to further maximize our capital efficiency. Through our midstream, power and CCUS business lines, we are capturing margin across the value chain.

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Well capitalized and conservative balance sheet.   Following the completion of this offering, we intend to continue to maintain a strong balance sheet and fund our upstream, midstream and power operations predominantly with internally generated cash flows. We believe that the low decline, predictable nature of our upstream production profile, combined with our hedging plan and reinvestment rate targets, will allow us to successfully meet our leverage goals.

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High caliber and proven management team.   We maintain a highly experienced and knowledgeable management team with an average of over 25 years of experience among our senior management team. Our leadership team has significant experience managing integrated energy and power assets for large-scale enterprises, including companies such as PTT Exploration and Production Public Company Limited (“PTT Exploration”) and BP p.l.c. (“BP”). Furthermore, our sponsor, Banpu, one of Asia Pacific’s largest integrated energy companies, provides us with unique and valuable insights into optimizing our integrated energy business.

Recent Developments

Projects and Acquisitions

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Temple II Acquisition.   In July 2023, BKV-BPP Power acquired CXA Temple 2, LLC, the owner of 100% of the interests in Temple II, a combined cycle gas turbine and steam turbine power plant located on the same site as Temple I in the ERCOT North Zone in Temple, Texas, for an aggregate purchase price of $460.0 million. Temple II began commercial operation in May 2015 and is equipped with modern, flexible and efficient combined cycle turbines and advanced emissions-control technology. Temple II provides enough energy to power 750,000 homes across central Texas.

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Carbon Sequestration Agreement with the State of Louisiana.   On August 10, 2023, High West Sequestration LLC (“High West”), a wholly owned subsidiary of BKV dCarbon Ventures, entered into a carbon sequestration agreement with the State of Louisiana to develop facilities and permanently sequester CO2 from local emissions sources. The State of Louisiana granted High West the carbon storage and sequestration rights on approximately 21,000 acres of land in St. Charles and Jefferson Parishes. The acreage is in an ideal location for targeted carbon capture and sequestration efforts, with an estimated 22 Mtpy CO2e of potential capture and sequestration located within a 15 mile radius from various emissions points. In addition, the storage site has a large CO2 storage potential, estimated to be between 140 to 1,000 Mtpy CO2, subject to further evaluation, planning, and development design decisions. Under the agreement, High West will dispose CO2e waste from local emissions sources through permanent sequestration via injection wells on the designated acreage. This project, which we refer to as the High West Project, is expected to reach FID by the end of 2024.

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Contract with ENGIE.   On August 10, 2023, BKV entered into a contract with ENGIE Energy Marketing NA, Inc, a subsidiary of global energy utility ENGIE S.A. (“ENGIE”), for the sale and purchase of our Carbon Sequestered Gas. The carbon credits included in our Carbon Sequestered Gas will be generated by our CCUS projects and will be third-party verified. Following first injection at the Barnett Zero Project and satisfaction of other conditions precedent, delivery of Carbon Sequestered Gas is expected to commence in early 2024. Under the contract terms, BKV is committed to deliver up to 10,000 MMBtu/day of Carbon Sequestered Gas to ENGIE with standardized terms and conditions, as well as independent certifications.

Credit Facilities

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Revolving Credit Agreement.    On August 24, 2022, we entered into the Revolving Credit Agreement (as amended, the “Revolving Credit Agreement”) with Bangkok Bank Public Company Limited (New York Branch), as the administrative agent and sole initial lender. The Revolving Credit

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Agreement includes $100.0 million of commitments for unsecured revolving loans used for short-term working capital and operating needs. As of October 6, 2023, the outstanding balance under the Revolving Credit Agreement was $69.0 million. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Loan Agreements and Credit Facilities — Revolving Credit Agreement” for additional information regarding the Revolving Credit Agreement.

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Amendment of SCB Credit Facility.   On February 1, 2023, we entered into an amendment letter with Standard Chartered Bank that increased the limit of the SCB Credit Facility (as defined herein) from $25.0 million to $50.0 million. Of the $50.0 million, $35.0 million is available for cash draw downs, and the full $50.0 million less any outstanding cash draw downs is available for letters of credit. As of October 6, 2023, we had outstanding letters of credit of $13.7 million under our SCB Credit Facility and outstanding cash draw downs of $31.0 million.

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Covenant Waivers.   On July 6, 2023, the lenders under the Revolving Credit Agreement agreed to waive compliance with respect to our minimum marketer receivables covenant for up to $40.0 million of our credit facility borrowings under the Revolving Credit Agreement with total borrowings not to exceed $100.0 million. This waiver is through the fiscal quarter ending December 31, 2023. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Loan Agreements and Credit Facilities” for additional information regarding the Term Loan Credit Agreement and the Revolving Credit Agreement and the covenants contained therein.

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Credit Agreement Amendments.    On July 18, 2023, we entered into the Third Amendment to the Term Loan Credit Agreement and the Third Amendment to the Revolving Credit Agreement with the respective lenders thereunder, pursuant to which such credit agreements were amended to permit, subject to certain restrictions, third parties to acquire up to 49% of the ownership interests in our CCUS project companies. On September 29, 2023, we entered into the Fourth Amendment to the Term Loan Credit Agreement and the Fourth Amendment to the Revolving Credit Agreement with the respective lenders thereunder, pursuant to which such credit agreements were amended to (i) remove the Company’s maximum total net leverage ratio covenant and minimum consolidated fixed charge coverage ratio covenant; and (ii) insert the following financial covenants: (a) minimum debt service coverage ratio, which must not be less than 1.05 to 1.00 at the end of each fiscal quarter and (b) maximum net indebtedness to equity ratio, which must not be greater than 1.50 to 1.00 at the end of each fiscal quarter. The Fourth Amendment to the Term Loan Credit Agreement inserted an additional financial covenant requiring us to hold a certain amount of cash in a restricted bank account at Bangkok Bank Public Company Limited (New York Branch) (the “Debt Service Reserve Account”). To fund the Debt Service Reserve Account, BKV made a capital call on BNAC of $150.0 million and, pursuant to the requirements of the existing stockholders’ agreement, on September 27, 2023, BNAC made such capital contribution in exchange for 15,000,000 shares of BKV common stock. $138.0 million of BNAC’s capital contribution will be placed in the Debt Service Reserve Account to comply with our financial covenant under the Term Loan Credit Agreement.

Corporate Values, Management Team and Sponsor

The following corporate values underpin our corporate culture and decision-making: Deliver on Promises, Have Grit, Embrace Change, Show Courage, Solve Problems, Do Good and Be One BKV.

Our management team is led by our Chief Executive Officer and founder, Christopher P. Kalnin, who has approximately 22 years of experience in exploration and production (“E&P”) (PTT Exploration & Production), management consulting (McKinsey & Company) and finance (Credit Suisse First Boston). Eric Jacobsen serves as our Chief Operating Officer with over 28 years of energy operational experience, including 11 years of experience in shale, 16 years of experience at BP and its predecessors and six years of experience at Noble Energy, Inc. John Jimenez serves as our Chief Financial Officer with over 30 years of international energy experience working with BP and Reliance Industries Limited.

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BNAC, our majority stockholder, is an indirect, wholly owned subsidiary of Banpu, our ultimate parent company. Banpu is a multi-billion U.S. dollar market cap energy company publicly traded in Thailand. With nearly four decades of experience in business operations covering 10 countries across the Pacific Rim region and the United States, Banpu is an international versatile energy provider committed to its Greener & Smarter strategy, which prioritizes environmentally sustainable businesses and leverages smart technologies and innovations. Upon completion of this offering, Banpu will beneficially own approximately    % of our common stock (or approximately    % if the underwriters exercise in full their option to purchase additional shares of our common stock). Banpu has informed us that although it may reduce a portion of its ownership position over time, it intends to remain a long-term stockholder and supporter of BKV. If, after this initial public offering, Banpu and its wholly owned subsidiaries cease to own at least 51% of our equity interests, or if they allow any lien to exist on our equity interests that they own, such event will be an event of default under the Term Loan Credit Agreement and the Revolving Credit Agreement. See “Risk Factors — Risks Related to Our Relationship with Banpu and its Affiliates.”

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Our Structure

The chart below displays a summary of our ownership structure after giving effect to this offering.

The information in the chart above does not include 10,000,000 additional shares of our common stock reserved for future awards pursuant to the BKV Corporation 2022 Equity and Incentive Compensation Plan (the “2022 Plan”), including        shares of common stock that may be issued upon vesting of equity awards that we expect to be granted in connection with this offering, and 1,000,000 shares of our common stock available for purchase by employees pursuant to the BKV Corporation Employee Stock Purchase Plan (the “ESPP”).

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Implications of Being an Emerging Growth Company

We qualify as an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act of 1933, as amended (the “Securities Act”), including as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As a result, for so long as we qualify as an emerging growth company, we are eligible to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies. These exemptions include:

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being permitted to present only two years of audited financial statements and only two years of related “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this prospectus;

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not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002, as amended (the “Sarbanes-Oxley Act”);

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reduced disclosure obligations regarding executive compensation in our periodic reports, proxy statements and registration statements, including in this prospectus;

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not being required to comply with any new requirements adopted by the Public Company Accounting Oversight Board (“PCAOB”) requiring a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; and

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exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved.

We have elected to take advantage of certain of the reduced disclosure obligations in this prospectus. As a result, the information that we provide in this prospectus may be different than you might receive from other public reporting companies in which you hold equity interests.

Because our gross revenues for the year ended December 31, 2022 exceeded $1.235 billion, we will not qualify as an emerging growth company following the consummation of this offering.

Controlled Company

We have applied to list our common stock on the NYSE under the symbol “BKV.” Upon completion of this offering, BNAC will hold approximately    % of our total outstanding shares of common stock (or approximately    % if the underwriters exercise in full their option to purchase additional shares), comprising more than 50% of the voting power of our outstanding common stock. As a result, we will be a “controlled company” within the meaning of the corporate governance rules of the NYSE. As a “controlled company,” we will be eligible to rely on exemptions from the obligation to comply with certain NYSE corporate governance requirements, including the requirements that:

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a majority of our board of directors consist of independent directors;

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we have a corporate governance and nominating committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

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we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

These exemptions do not modify the independence requirements for our audit committee. As a controlled company, we will remain subject to the rules of the Sarbanes-Oxley Act and the NYSE that require us to have an audit committee composed entirely of independent directors. Under these rules, we must have at least one independent director on our audit committee by the date our common stock is listed on the NYSE, at least two independent directors on our audit committee within 90 days of the listing date, and at least three independent directors on our audit committee within one year of the listing date. We expect to have four independent directors upon the closing of this offering.

While BNAC continues to control more than 50% of the voting power of our outstanding common stock, we qualify for, and intend to rely on, these exemptions. Accordingly, you will not have the same

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protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE.

If we cease to be a controlled company within the meaning of the applicable rules of the NYSE, we will be required to comply with these requirements after specified transition periods.

Contact Information

Our principal executive offices are located at 1200 17th Street, Suite 2100, Denver, Colorado 80202, and our telephone number at such address is (720) 375-9680. Our website address is www.bkvcorp.com. The contents of our website are not incorporated by reference herein and are not a part of, and shall not deemed to be a part of, this prospectus.

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The Offering

Issuer

BKV Corporation, a Delaware corporation

Securities offered

Common stock, par value $0.01 per share (“common stock”)

Common stock offered by us

       shares (or        shares if the underwriters exercise in full their option to purchase additional shares)

Underwriters’ option to purchase additional shares

The underwriters have an option for a period of 30 days to purchase up to an additional        shares of our common stock.

Common stock outstanding immediately after this offering

       shares (or        shares if the underwriters exercise in full their option to purchase additional shares)

Use of proceeds

We estimate that the net proceeds to us from the sale of our common stock in this offering, after deducting underwriting discounts and commissions and estimated offering expenses payable by us, will be approximately $      million (or approximately $      million if the underwriters exercise in full their option to purchase additional shares), based on an assumed initial public offering price of $      per share (the midpoint of the price range set forth on the cover page of this prospectus).

Of the net proceeds we receive from the sale of our common stock in this offering, we intend to use approximately $       million to make additional contingent consideration payments payable in connection with the Devon Barnett Acquisition and the remainder for other general corporate purposes, which may include the expansion of our CCUS business and the repayment of outstanding indebtedness. See “Use of Proceeds.”

Dividend policy

We currently do not pay a fixed cash dividend to holders of our common stock, and certain of our debt agreements place certain restrictions on our ability to pay cash dividends to holders of our common stock. Any future determination related to our dividend policy will be made at the sole discretion of our board of directors. See “Dividend Policy.”

Voting rights

Each share of common stock will entitle the holder to one vote per share. Generally, matters to be voted on by stockholders must be approved by a majority of the votes entitled to be cast at a meeting by holders of all shares of common stock present in person or represented by proxy.

In addition, pursuant to the stockholders’ agreement to be entered into upon the completion of this offering between BNAC and us (our “Stockholders’ Agreement”), for so long as BNAC and Banpu beneficially own 10% or more of our voting stock, BNAC will be entitled to designate for nomination to our board of directors a number of individuals approximately proportionate to such beneficial ownership, provided that (i) from the completion of this offering until the first anniversary of the completion of this offering, at least three board seats will not be BNAC designees, (ii) from and after the first anniversary of the completion of this offering until the first

22

date on which BNAC and Banpu beneficially own 50% or less of our voting stock, at least four board seats will not be BNAC designees, and (iii) from and after the first date on which BNAC and Banpu beneficially own 50% or less of our voting stock, a number of board seats equal to the minimum number of directors that would constitute a majority of the total number of directors comprising our board of directors will not be BNAC designees. See “Management,” “Principal Stockholders,” “Description of Capital Stock” and “Certain Relationships and Related Party Transactions” for additional information.

Risk factors

You should read the section of this prospectus titled “Risk Factors” and other information included in this prospectus for a discussion of factors to carefully consider before deciding to invest in shares of our common stock.

Controlled company

We will be a “controlled company” within the meaning of the corporate governance rules of the NYSE. Upon completion of this offering, BNAC will hold     % of our common stock (or approximately    % if the underwriters exercise in full their option to purchase additional shares), comprising more than 50% of the voting power of our outstanding common stock. See “Management — Controlled Company.”

Listing and stock exchange symbol

We have applied to list our common stock on the NYSE under the symbol “BKV.”

Reserved Share Program

At our request, an affiliate of BofA Securities, Inc., a participating Underwriter, has reserved for sale, at the initial public offering price, up to 5% of the shares of common stock being offered by this prospectus for sale to some of our directors, executive officers, employees, business associates and related persons at the public offering price. If these persons purchase reserved shares, it will reduce the number of shares of common stock available for sale to the general public. Any reserved shares that are not so purchased will be offered by the underwriters to the general public on the same terms as the other shares offered by this prospectus. These persons must commit to purchase no later than the close of business on the day following the date of this prospectus. Any participants purchasing such reserved common stock will be prohibited from selling such stock for a period of 180 days after the date of this prospectus. See “Principal Stockholders” for more information.

The number of shares of common stock that will be outstanding immediately after the completion of this offering is based on                 shares of our common stock to be issued pursuant to this offering (assuming the underwriters do not exercise their option to purchase additional shares), and excludes 10,000,000 additional shares of our common stock reserved for future awards pursuant to our 2022 Plan and 1,000,000 shares of our common stock available for purchase by employees pursuant to the our ESPP, which will become effective upon the completion of this offering.

Unless otherwise indicated and except for our historical consolidated financial statements and related notes included elsewhere in this prospectus, the information in this prospectus:

•

assumes the execution of our Stockholders’ Agreement, as further described under “Certain Relationships and Related Party Transactions”;

23

•

assumes the amendment and restatement of our existing certificate of incorporation and the amendment and restatement of our existing bylaws in connection with the consummation of the offering;

•

assumes an initial public offering price of $      per share of common stock (the midpoint of the price range set forth on the cover page of this prospectus);

•

assumes that the underwriters do not exercise their option to purchase additional shares of common stock; and

•

excludes shares of common stock that directors and executive officers may purchase through the reserved share program.

Risk Factors Summary

Investing in our common stock involves risks, including those highlighted in the section titled “Risk Factors” immediately following this prospectus summary, of which you should be aware before making a decision to invest in our common stock. These risks may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our common stock and a loss of all or part of your investment. These risks include, among others, the following:

Risks Related to Our Upstream Business and Industry

•

the volatility of natural gas and NGL prices due to factors beyond our control;

•

our reliance on a single third party for all of our natural gas marketing and another third party for substantially all of our natural gas and NGL midstream services with respect to the Barnett assets we acquired from Devon Energy;

•

our reserves estimates are based on assumptions that may prove to be inaccurate;

•

our ability to find or acquire additional natural gas and NGL reserves that are economically recoverable, including development of our proved undeveloped reserves and associated capital expenditures;

•

uncertainties in evaluating the expected benefits and potential liabilities of recoverable reserves;

•

risks and uncertainties related to drilling operations, which are high-risk and operationally complex;

•

the availability or cost of water, equipment, supplies, personnel and oilfield services;

•

our limited control over activities on properties we do not operate;

Risks Related to Our Power Generation Business

•

extreme weather, transmission congestion, and changes to the regulatory environment;

•

the operation of our power generation business through a joint venture which we do not control;

•

risks and hazards related to the operation or maintenance of electric generation facilities, including disruption of the fuel supplies necessary to generate power at the Temple Plants;

•

the lack of long-term power sales agreements for the Temple Plants;

Risks Related to Our Retail Power Business

•

the operation of our retail power business through a joint venture which we do not control;

•

our ability to attract and retain customers in the competitive retail power marketplace;

•

market price risk and changes in law, regulation or market structure resulting in unanticipated costs;

•

our ability to maintain our retail electric provider certification;

24

Risks Related to Our CCUS Business

•

our ability to successfully pursue and develop our CCUS business, the associated material capital investments and any changes to financial and tax incentives;

Risks Related to Our Midstream Business

•

risks and hazards related to midstream operations as complex activities;

•

our dependence on our natural gas midstream system;

Risks Related to Our Business Generally

•

the geographical concentration of substantially all of our oil and gas and midstream properties;

•

the effect of a deterioration in general economic, business or industry conditions;

•

our ability to achieve our near term and long term net zero goals on our anticipated time frame;

•

our ability to generate cash flow to meet our debt obligations or fund our other liquidity needs;

•

events of default if we are unable to comply with restrictions in our debt agreements (including if Banpu and its wholly owned subsidiaries cease to own at least 51% of our equity interests or allow any lien to exist on our equity interests that they own);

•

risks related to our debt and debt agreements and hedging arrangements that expose us to risk of financial losses and counterparty credit risk;

•

our dependence, as a holding company, on our subsidiaries and our joint venture for cash;

•

operating hazards that could result in substantial losses or liabilities for which we may not have adequate insurance coverage;

•

our ability to make accretive acquisitions or successfully integrate acquired businesses or assets;

•

our substantial capital requirements and our ability to obtain financing or fund working capital needs;

•

the intense competition in the energy industry and our ability to compete with other companies;

•

cybersecurity or physical security threats or disruptions or loss of our information systems;

•

increased activism and negative investor sentiment regarding upstream activities and companies;

•

the loss of our executive officers and technical personnel and our ability to retain technical personnel;

Risks Related to Environmental, Legal Compliance and Regulatory Matters

•

complex laws, regulations and initiatives related to our operations and the use of hydraulic fracturing;

•

the effect of increased attention to ESG matters and environmental conservation measures;

•

reductions in demand for natural gas, NGL and oil;

•

risks related to climate change, including transitional, legal, political, financial and physical risks;

•

significant costs and liabilities related to environmental, health and safety laws and regulations;

•

potential tax law changes;

•

complex and evolving laws and regulations regarding privacy and data protection;

Risks Related to Our Relationship with Banpu and its Affiliates

•

the substantial influence of Banpu, our controlling stockholder, over us;

•

our historical reliance on Banpu for capital investments to fund our business operations;

25

•

we expect to be a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for and could rely on exemptions from certain corporate governance requirements;

•

conflicts of interest between Banpu and us or our other stockholders or conflicts of interest of our officers and/or directors as a result of their positions with, or ownership of common stock of, Banpu;

Risks Related to the Offering and Our Common Stock

•

our actual operating results and activities could differ materially from our estimates;

•

the impact of our lack of dividend payments on the market price of our common stock;

•

the costs of, and our ability to comply with, the requirements of being a public company;

•

we have identified material weaknesses in our internal control over financial reporting;

•

the lack of an existing market for our common stock;

•

provisions in our governing documents and Delaware law that could discourage acquisition bids or merger proposals; and

•

future sales of our common stock in the public market, or the perception that such sales may occur, could reduce our stock price.

26

Summary Historical and Unaudited Pro Forma Financial Information

The following table shows our summary historical consolidated financial information and summary unaudited pro forma combined consolidated financial information for the periods and as of the dates indicated. The summary unaudited pro forma combined consolidated financial information presents the combination of our historical consolidated financial information, as adjusted to give effect to the Exxon Barnett Acquisition, the related financing under the Term Loan Credit Agreement and the $75 Million Loan Agreement (collectively, the “Transaction”).

The summary historical consolidated financial information as of and for the six months ended June 30, 2023 and 2022 was derived from our unaudited historical condensed consolidated financial statements, included elsewhere in this prospectus. The summary historical consolidated financial information as of and for the years ended December 31, 2022, 2021 and 2020 was derived from our audited historical consolidated financial statements, included elsewhere in this prospectus.

The summary unaudited pro forma combined consolidated financial information was derived from the unaudited pro forma combined consolidated financial statements included elsewhere in this prospectus. The unaudited pro forma combined consolidated statements of operations data for the year ended December 31, 2022 has been prepared to give pro forma effect to the Transaction as if it had been consummated on January 1, 2022. This information is subject to, and gives effect to, the assumptions and adjustments described in the notes accompanying the unaudited pro forma combined consolidated financial statements included elsewhere in this prospectus. The pro forma financial information is provided for illustrative purposes only and is not intended to represent what our financial position or results of operations would have been had the Transaction occurred on the assumed date nor does it purport to project our future operating results or financial position following the Transaction. The summary pro forma financial information does not include pro forma balance sheet information because the Exxon Barnett Acquisition was consummated on June 30, 2022 and, therefore, the 2022 Barnett Assets and related financing are included in our historical balance sheet as of December 31, 2022, together with the related indebtedness under the Term Loan Credit Agreement and the $75 Million Loan Agreement.

The summary financial data is qualified in its entirety by, and should be read in conjunction with, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Unaudited Pro Forma Combined Consolidated Financial Statements” included elsewhere in this prospectus, as well as our historical consolidated financial statements and related notes, the historical statements of revenues and direct operating expenses and related notes for the 2022 Barnett Assets acquired in the Exxon Barnett Acquisition and other financial information included in this prospectus. Historical and pro forma results are not necessarily indicative of results that may be expected for any future period.

​

Six Months Ended June 30,

Year Ended December 31,

Pro Forma Year Ended December 31, 2022

​

2023

2022

2022

2021

2020

​

(in thousands, except per share amounts)

Revenues and other operating income

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas revenues

​

$

257,032

​

$

487,813

​

$

1,310,339

​

$

597,050

​

$

101,758

​

​

*

NGL revenues

​

​

91,477

​

​

163,498

​

​

311,542

​

​

225,135

​

​

11,952

​

​

*

Oil revenues

​

​

4,398

​

​

5,120

​

​

11,866

​

​

7,560

​

​

1,333

​

​

*

Natural gas, NGL, and oil revenues

​

​

352,907

​

​

656,431

​

​

1,633,747

​

​

829,745

​

​

115,043

​

$

1,852,979

Midstream revenues

​

​

8,428

​

​

3,344

​

​

12,676

​

​

6,917

​

​

7,458

​

$

16,297

Derivative gains (losses), net

​

​

116,947

​

​

(450,784)

​

​

(629,701)

​

​

(383,847)

​

​

20,755

​

$

(629,701)

Marketing revenues

​

​

4,732

​

​

5,328

​

​

11,001

​

​

52,616

​

​

—

​

$

11,001

Related party and other

​

​

3,314

​

​

1,327

​

​

2,799

​

​

251

​

​

33

​

$

3,047

Total revenues and other operating income

​

​

486,328

​

​

215,646

​

​

1,030,522

​

​

505,682

​

​

143,289

​

$

1,253,623

27

​

Six Months Ended June 30,

Year Ended December 31,

Pro Forma Year Ended December 31, 2022

​

2023

2022

2022

2021

2020

​

(in thousands, except per share amounts)

Operating expenses

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Lease operating and workover

​

​

80,723

​

​

45,141

​

​

135,064

​

​

88,105

​

​

31,260

​

$

193,240

Taxes other than income

​

​

41,496

​

​

41,001

​

​

114,668

​

​

45,650

​

​

5,151

​

$

125,364

Gathering and transportation

​

​

120,586

​

​

98,756

​

​

208,758

​

​

173,587

​

​

—

​

$

234,079

Depreciation, depletion, amortization and accretion(1)

​

​

78,354

​

​

42,255

​

​

118,909

​

​

92,277

​

​

87,343

​

$

145,100

General and administrative

​

​

52,488

​

​

51,497

​

​

148,559

​

​

85,740

​

​

29,442

​

$

148,559

Other

​

​

8,483

​

​

192

​

​

—

​

​

—

​

​

—

​

$

—

Total operating expenses

​

​

382,130

​

​

278,842

​

​

725,958

​

​

485,359

​

​

153,196

​

$

846,342

Income (loss) from operations

​

​

104,198

​

​

(63,196)

​

​

304,564

​

​

20,323

​

​

(9,907)

​

$

407,281

Other income and expense

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Bargain purchase gain

​

​

—

​

​

163,653

​

​

170,853

​

​

—

​

​

—

​

$

170,853

Gain on settlement of litigation

​

​

—

​

​

16,866

​

​

16,866

​

​

—

​

​

—

​

$

16,866

Gains (losses) on contingent consideration liabilities(2)

​

​

22,910

​

​

(31,915)

​

​

6,632

​

​

(194,968)

​

​

7,135

​

$

6,632

Earnings (losses) from equity affiliate

​

​

(14,275)

​

​

(23,958)

​

​

8,493

​

​

910

​

​

—

​

$

8,493

Interest income

​

​

1,136

​

​

128

​

​

1,143

​

​

8

​

​

121

​

$

1,143

Interest expense

​

​

(34,377)

​

​

(1,025)

​

​

(26,322)

​

​

—

​

​

—

​

$

(47,396)

Interest expense, related party

​

​

(3,083)

​

​

(5,673)

​

​

(10,846)

​

​

(2,134)

​

​

(1,713)

​

$

(11,663)

Other income

​

​

2,190

​

​

516

​

​

1,411

​

​

872

​

​

—

​

$

1,411

Income (loss) before income taxes

​

​

78,699

​

​

55,396

​

​

472,794

​

​

(174,989)

​

​

(4,364)

​

$

553,620

Income tax benefit (expense)

​

​

(17,885)

​

​

24,903

​

​

(62,652)

​

​

40,526

​

​

(38,982)

​

$

(81,242)

Net income (loss) attributable to BKV Corporation

​

​

60,814

​

​

80,299

​

​

410,142

​

​

(134,463)

​

​

(43,346)

​

$

472,378

Less accretion of preferred stock to redemption value

​

​

—

​

​

—

​

​

—

​

​

(3,745)

​

​

—

​

$

—

Less preferred stock dividends

​

​

—

​

​

—

​

​

—

​

​

(9,900)

​

​

(460)

​

$

—

Less deemed dividend on redemption of preferred stock

​

​

—

​

​

—

​

​

—

​

​

(22,606)

​

​

—

​

$

—

Net income (loss) attributable to common stockholders

​

​

60,814

​

​

80,299

​

​

410,142

​

​

(170,714)

​

​

(43,806)

​

$

472,378

Net income (loss) per common share:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Basic

​

$

0.52

​

$

0.68

​

$

3.50

​

$

(1.46)

​

$

(0.42)

​

$

4.03

Diluted

​

$

0.49

​

$

0.65

​

$

3.31

​

$

(1.46)

​

$

(0.42)

​

$

3.81

Weighted average number of common shares outstanding

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Basic

​

​

117,559

​

​

117,310

​

​

117,318

​

​

116,904

​

​

105,275

​

​

117,318

Diluted

​

​

124,706

​

​

123,221

​

​

123,980

​

​

116,904

​

​

105,275

​

​

123,980

Balance sheet information (at period end):

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Cash and cash equivalents

​

$

22,421

​

$

169,161

​

$

153,128

​

$

134,667

​

$

17,445

​

​

**

Restricted cash(3)

​

$

—

​

$

17,473

​

$

—

​

$

—

​

$

—

​

​

**

Total natural gas properties, net

​

$

2,237,870

​

$

2,157,889

​

$

2,209,518

​

$

1,176,117

​

$

1,169,297

​

​

**

Total assets

​

$

2,503,242

​

$

2,642,395

​

$

2,702,573

​

$

1,620,828

​

$

1,342,492

​

​

**

Total liabilities

​

$

1,239,558

​

$

1,787,997

​

$

1,506,649

​

$

865,889

​

$

262,424

​

​

**

Total mezzanine equity

​

$

142,149

​

$

152,863

​

$

151,883

​

$

83,847

​

$

137,212

​

​

**

Total stockholders’ equity

​

$

1,121,535

​

$

701,535

​

$

1,044,041

​

$

671,092

​

$

942,856

​

​

**

28

​

Six Months Ended June 30,

Year Ended December 31,

Pro Forma Year Ended December 31, 2022

​

2023

2022

2022

2021

2020

​

(in thousands, except per share amounts)

Statement of cash flows information

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Net cash provided by (used in) operating activities

​

$

80,924

​

$

160,758

​

$

349,194

​

$

358,133

​

$

(7,405)

​

​

**

Net cash used in investing activities

​

$

(128,606)

​

$

(705,791)

​

$

(865,566)

​

$

(161,858)

​

$

(513,992)

​

​

**

Net cash provided by (used in) financing activities

​

$

(83,025)

​

$

597,000

​

$

534,833

​

$

(79,053)

​

$

442,723

​

​

**

Other financial data (unaudited)(4)

​

​

​

​

​

​

Adjusted EBITDAX

​

$

108,725

​

$

254,928

​

$

576,396

​

$

281,024

​

$

65,147

​

$

704,975

Upstream Reinvestment Rate(5)

​

​

115%

​

​

31%

​

​

42%

​

​

24%

​

​

16%

​

​

**

Adjusted Free Cash Flow

​

$

(11,389)

​

$

130,272

​

$

169,213

​

$

165,090

​

$

56,604

​

​

**

Adjusted Free Cash Flow Margin

​

​

(3)%

​

​

20%

​

​

10%

​

​

19%

​

​

46%

​

​

**

Total Net Leverage Ratio

​

​

2.90x

​

​

1.15x

​

​

1.00x

​

​

0.11x

​

​

0.10x

​

​

**

(1)

Includes accretion of lease liabilities related to office space and compressor leases.

(2)

Represents contingent consideration liabilities as of the dates set forth above accruing as an earnout obligation under the terms of our purchase agreements with Devon Energy and ExxonMobil Corporation for the purchase of our 2020 Barnett Assets and 2022 Barnett Assets, respectively. Contingent consideration is stated at fair value on our consolidated balance sheets, with changes in fair value recorded in the consolidated statement of operations.

(3)

Represents cash borrowed as of June 30, 2022 under the Term Loan Credit Agreement which could only be used for costs related to the Exxon Barnett Acquisition. The restricted cash was used for transaction and integration costs related to the Exxon Barnett Acquisition.

(4)

Adjusted EBITDAX and Adjusted Free Cash Flow are not financial measures calculated in accordance with GAAP. See “— Non-GAAP Financial Measures” for how we define each of these measures and a reconciliation to the most directly comparable GAAP measures. In addition, we define Upstream Reinvestment Rate as total cash paid for upstream capital expenditures (excluding leasehold costs and acquisitions) as a percentage of Adjusted EBITDAX, and we define Adjusted Free Cash Flow Margin as the ratio of Adjusted Free Cash Flow to total revenues excluding derivative gains and losses. Total Net Leverage Ratio represents the ratio of total debt less cash and cash equivalents to Adjusted EBITDAX.

(5)

The six months ended June 30, 2023 includes cash paid of approximately $22.0 million for upstream capital expenditures accrued in 2022.

*

Revenues with respect to the 2022 Barnett Assets (as defined herein) for the year ended December 31, 2022 are reported only on a consolidated basis. Accordingly, the unaudited pro forma combined consolidated natural gas, NGL and oil sales revenues are presented only in the aggregate. See “—Unaudited Pro Forma Combined Consolidated Financial Statements.”

**

The Exxon Barnett Acquisition was consummated on June 30, 2022, and, therefore, the 2022 Barnett Assets and related financing are included in the historical balance sheet of the Company as of December 31, 2022, and no pro forma balance sheet is presented. See “Unaudited Pro Forma Combined Consolidated Financial Statements.”

Non-GAAP Financial Measures

Adjusted EBITDAX

We define Adjusted EBITDAX as net income (loss) attributable to BKV Corporation before (i) non-cash derivative gains (losses), (ii) depreciation, depletion, amortization and accretion, (iii) exploration and impairment expense, (iv) gains (losses) on contingent consideration liabilities, (v) interest expense, (vi) interest expense, related party, (vii) income tax benefit (expense), (viii) equity-based compensation expense, (ix) bargain purchase gains, (x) earnings or losses from equity affiliate, (xi) early settlement of derivative

29

contracts and (xii) other nonrecurring transactions. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by our management and external users of our consolidated financial statements, such as industry analysts, investors, lenders, rating agencies and others to more effectively evaluate our operating performance and results of operations from period to period and against our peers. We believe Adjusted EBITDAX is a useful performance measure because it allows us to effectively evaluate our operating performance and results of operations from period to period and against our peers, without regard to our financing methods, corporate form or capital structure.

We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) determined in accordance with GAAP. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Other companies, including other companies in our industry, may not use Adjusted EBITDAX or may calculate this measure differently than as presented in this prospectus, limiting its usefulness as a comparative measure.

The table below presents a reconciliation of Adjusted EBITDAX to net income, our most directly comparable GAAP financial measure for the periods indicated.

​

Six Months Ended June 30,

Year Ended December 31,

Pro Forma Year Ended December 31, 2022

​

2023

2022

2022

2021

2020

​

(in thousands)

​

​

​

Net income (loss) attributable to BKV Corporation

​

$

60,814

​

$

80,299

​

$

410,142

​

$

(134,463)

​

$

(43,346)

​

$

472,378

Unrealized derivative (gains) losses

​

​

(46,245)

​

​

200,136

​

​

(58,815)

​

​

115,161

​

​

(10,329)

​

​

(58,815)

Forward month gas derivative settlement(1)

​

​

(2,751)

​

​

32,377

​

​

(9,013)

​

​

15,406

​

​

(5,489)

​

​

(9,013)

Depreciation, depletion, amortization and accretion

​

​

79,026

​

​

47,847

​

​

130,038

​

​

98,833

​

​

90,191

​

​

155,900

Exploration and impairment expense

​

​

—

​

​

—

​

​

—

​

​

34

​

​

560

​

​

—

Change in contingent consideration liabilities

​

​

(22,910)

​

​

31,915

​

​

(6,632)

​

​

194,968

​

​

(7,135)

​

​

(6,632)

Interest expense

​

​

34,377

​

​

1,025

​

​

26,322

​

​

—

​

​

—

​

​

47,396

Interest expense, related party

​

​

3,083

​

​

5,673

​

​

10,846

​

​

2,134

​

​

1,713

​

​

11,663

Income tax expense (benefit)

​

​

17,885

​

​

(24,903)

​

​

62,652

​

​

(40,526)

​

​

38,982

​

​

81,242

Equity-based compensation expense

​

​

10,295

​

​

20,254

​

​

31,947

​

​

30,387

​

​

—

​

​

31,947

Bargain purchase gain

​

​

—

​

​

(163,653)

​

​

(170,853)

​

​

—

​

​

—

​

​

(170,853)

(Earnings) losses from equity affiliate

​

​

14,275

​

​

23,958

​

​

(8,493)

​

​

(910)

​

​

—

​

​

(8,493)

Early settlement of derivative contracts

​

​

(39,124)

​

​

—

​

​

158,255

​

​

—

​

​

—

​

​

158,255

Adjusted EBITDAX

​

$

108,725

​

$

254,928

​

$

576,396

​

$

281,024

​

$

65,147

​

$

704,975

(1)

Natural gas derivative contracts settle and are realized in the month prior to the production covered by the contract. This adjustment removes the timing difference between the settlement date and the underlying production month that is hedged.

30

Adjusted Free Cash Flow

We define Adjusted Free Cash Flow as net cash provided by (used in) operating activities, excluding cash paid for contingent consideration and changes in operating assets and liabilities, less total cash paid for capital expenditures (excluding leasehold costs and acquisitions).

Adjusted Free Cash Flow is not a measure of net cash flow provided by or used in operating activities as determined by GAAP. Adjusted Free Cash Flow is a supplemental non-GAAP financial measure that is used by our management and other external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others to assess our ability to internally fund our capital program, service or incur additional debt and to pay dividends. We believe Adjusted Free Cash Flow is a useful liquidity measure because it allows us and others to compare cash flow provided by operating activities across periods and to assess our ability to internally fund our capital program (including acquisitions), to reduce leverage, fund acquisitions and pay dividends to our stockholders. Adjusted Free Cash Flow should not be considered as an alternative to, or more meaningful than, net income (loss) or net cash provided by (used in) operating activities determined in accordance with GAAP. Other companies, including other companies in our industry, may not use Adjusted Free Cash Flow or may calculate this measure differently than as presented in this prospectus, limiting its usefulness as a comparative measure.

The table below presents our reconciliation of Adjusted Free Cash Flow to net cash provided by (used in) operating activities, our most directly comparable GAAP financial measure for the periods indicated.

​	Six Months Ended June 30,						Year Ended December 31,
​	2023			2022			2022			2021			2020
​	(in thousands)
Net cash provided by (used in) operating activities	​	$	80,924	​	$	160,758	​	$	349,194	​	$	358,133	​	$	(7,405)
Cash paid for contingent consideration(1)	​	​	65,000	​	​	45,300	​	​	45,300	​	​	—	​	​	—
Changes in operating assets and liabilities	​	​	(32,008)	​	​	2,414	​	​	22,816	​	​	(126,862)	​	​	74,536
Cash paid for capital expenditures	​	​	(125,305)	​	​	(78,200)	​	​	(248,097)	​	​	(66,181)	​	​	(10,527)
Adjusted Free Cash Flow(2)	​	$	(11,389)	​	$	130,272	​	$	169,213	​	$	165,090	​	$	56,604

(1)

Cash paid for contingent consideration is included as a deduction to arrive at net cash provided by (used in) operating activities and therefore, is added back for the purpose of computing Adjusted Free Cash Flow.

(2)

Adjusted Free Cash Flow for the six months ended June 30, 2023 and for the year ended December 31, 2022 was $39.1 million higher than the six months ended June 30, 2022 and $158.3 million lower than the year ended December 31, 2021, respectively, due to the early termination of derivative contracts.

31

Summary Reserves, Production and Operating Data

Ryder Scott, our independent petroleum engineers, prepared estimates of our natural gas, NGL and oil reserves as of June 30, 2023 and December 31, 2022, 2021 and 2020. These reserves estimates were prepared in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”) regarding oil and natural gas reserves reporting using an average price equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period as adjusted for location and quality differentials, unless prices are defined by contractual arrangements, excluding escalations based on future conditions (“SEC Pricing”) (except for the table that provides our estimated reserves as of June 30, 2023 at “NYMEX strip pricing” using pricing based on NYMEX future prices as of market close on June 30, 2023). For more information about our reserves volumes and values, see “Business — Preparation of Reserves Estimates and Internal Controls” and Ryder Scott’s summary reserves reports, which are filed as exhibits to the registration statement of which this prospectus forms a part.

The following table provides our estimated proved reserves, probable reserves and possible reserves information prepared by Ryder Scott as of June 30, 2023 and December 31, 2022, 2021 and 2020 and PV-10 Value and the standardized measure of discounted future net cash flows (the “Standardized Measure”) for each period. The increase in our proved reserves and the PV-10 Value of those reserves as of June 30, 2023 and December 31, 2022, as compared to December 31, 2021, is primarily due to the Exxon Barnett Acquisition, our refrac and restimulation program, adding NGL rich locations to the drilling program. There are numerous uncertainties inherent in estimating quantities of natural gas, NGL and oil reserves and their values, including many factors beyond our control. In addition, estimates of probable and possible reserves are inherently imprecise and are more uncertain than proved reserves but have not been adjusted for risk due to that uncertainty, and therefore they may not be comparable with each other and should not be summed either together or with estimates of proved reserves. See “Risk Factors — Risks Related to Our Upstream Business and Industry — Our estimated natural gas, NGL and oil reserves quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in the reserves estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.”

Estimated Reserves at SEC Pricing(1)

​

June 30, 2023

December 31,

​

2022

2021

2020

Estimated proved developed reserves:

​

​

​

​

​

​

​

​

​

​

Natural gas (MMcf)

​

​

3,531,686

​

​

3,798,019

​

​

2,494,926

​

​

1,893,161

Producing

​

​

3,232,932

​

​

3,468,896

​

​

2,346,712

​

​

1,893,161

Non-producing.

​

​

298,753

​

​

329,123

​

​

148,214

​

​

—

Natural gas liquids (MBbls)

​

​

161,018

​

​

170,840

​

​

151,433

​

​

107,234

Producing

​

​

149,038

​

​

157,585

​

​

142,961

​

​

107,234

Non-producing.

​

​

11,980

​

​

13,255

​

​

8,472

​

​

—

Oil (MBbls)

​

​

997

​

​

1,111

​

​

867

​

​

723

Producing

​

​

997

​

​

1,111

​

​

876

​

​

723

Non-producing.

​

​

—

​

​

—

​

​

—

​

​

—

Total estimated proved developed reserves (MMcfe)

​

​

4,503,774

​

​

4,829,725

​

​

3,408,723

​

​

2,540,901

Producing

​

​

4,133,142

​

​

4,421,072

​

​

3,209,679

​

​

2,540,901

Non-producing.

​

​

370,633

​

​

408,653

​

​

199,044

​

​

—

Standardized Measure (millions)

​

$

3,602

​

$

5,809

​

$

2,119

​

$

504

PV-10 (millions)(2)(3)

​

$

4,549

​

$

7,389

​

$

2,672

​

$

552

32

​

June 30, 2023

December 31,

​

2022

2021

2020

Estimated proved undeveloped reserves:

​

​

​

​

​

​

​

​

​

​

Natural gas (MMcf).

​

​

798,352

​

​

1,057,657

​

​

950,359

​

​

92,373

Natural gas liquids (MBbls)

​

​

29,263

​

​

40,660

​

​

13,722

​

​

—

Oil (MBbls)

​

​

592

​

​

758

​

​

58

​

​

—

Total estimated proved undeveloped reserves (MMcfe)(4)(5)

​

​

977,482

​

​

1,306,165

​

​

1,033,040

​

​

92,373

Standardized Measure (millions)

​

$

441

​

$

1,185

​

$

295

​

$

6

PV-10 (millions)(2)(6)

​

$

594

​

$

1,566

​

$

403

​

$

9

Estimated total proved reserves:

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas (MMcf).

​

​

4,330,037

​

​

4,855,676

​

​

3,445,285

​

​

1,985,534

Natural gas liquids (MBbls)

​

​

190,281

​

​

211,500

​

​

165,155

​

​

107,234

Oil (MBbls)

​

​

1,589

​

​

1,869

​

​

925

​

​

723

Total estimated proved reserves (MMcfe)

​

​

5,481,257

​

​

6,135,890

​

​

4,441,763

​

​

2,633,274

Standardized Measure (millions)

​

$

4,043

​

$

6,994

​

$

2,413

​

$

510

PV-10 (millions)(2)(7)

​

$

5,143

​

$

8,955

​

$

3,074

​

$

561

Estimated probable developed reserves:

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas (MMcf).

​

​

344,634

​

​

367,081

​

​

—

​

​

—

Natural gas liquids (MBbls)

​

​

27,066

​

​

25,558

​

​

—

​

​

—

Oil (MBbls)

​

​

—

​

​

—

​

​

—

​

​

—

Total estimated probable developed reserves (MMcfe)(5)(8)

​

​

507,030

​

​

520,430

​

​

—

​

​

—

Standardized Measure (millions)

​

$

163

​

$

281

​

​

—

​

​

—

PV-10 (millions)(2)(9)

​

$

218

​

$

372

​

​

—

​

​

—

Estimated probable undeveloped reserves:

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas (MMcf).

​

​

544,083

​

​

572,425

​

​

522,442

​

​

61,884

Natural gas liquids (MBbls)

​

​

35,321

​

​

39,319

​

​

31,227

​

​

—

Oil (MBbls)

​

​

1,342

​

​

1,556

​

​

486

​

​

—

Total estimated probable undeveloped reserves (MMcfe)(5)(8)

​

​

764,061

​

​

817,675

​

​

712,725

​

​

61,884

Standardized Measure (millions)

​

$

203

​

$

420

​

$

146

​

​

—

PV-10 (millions)(2)(10)

​

$

281

​

$

563

​

$

202

​

​

—

Estimated total probable reserves:

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas (MMcf).

​

​

888,717

​

​

939,506

​

​

522,442

​

​

61,884

Natural gas liquids (MBbls)

​

​

62,387

​

​

64,877

​

​

31,227

​

​

—

Oil (MBbls)

​

​

1,342

​

​

1,556

​

​

486

​

​

—

Total estimated probable reserves (MMcfe)(5)(8)

​

​

1,271,091

​

​

1,338,105

​

​

712,725

​

​

61,884

Standardized Measure (millions)

​

$

366

​

$

701

​

$

146

​

​

—

PV-10 (millions)(2)(11)

​

$

499

​

$

935

​

$

202

​

$

2

33

​	June 30, 2023			December 31,
​				2022			2021			2020
Estimated possible developed reserves:	​	​	​	​	​	​	​	​	​	​	​
Natural gas (MMcf).	​	​	106,709	​	​	84,124	​	​	—	​	—
Natural gas liquids (MBbls)	​	​	7,237	​	​	8,146	​	​	—	​	—
Oil (MBbls)	​	​	—	​	​	—	​	​	—	​	—
Total estimated possible developed reserves (MMcfe)(5)(8)	​	​	150,131	​	​	133,000	​	​	—	​	—
Standardized Measure (millions)	​	$	33	​	$	53	​	​	—	​	—
PV-10 (millions)(2)(12)	​	$	43	​	$	70	​	​	—	​	—
Estimated possible undeveloped reserves:	​	​	​	​	​	​	​	​	​	​	​
Natural gas (MMcf).	​	​	727,206	​	​	540,878	​	​	381,941	​	—
Natural gas liquids (MBbls)	​	​	19,413	​	​	16,876	​	​	32,047	​	—
Oil (MBbls)	​	​	619	​	​	789	​	​	1,841	​	—
Total estimated possible undeveloped reserves (MMcfe)(5)(8)	​	​	847,398	​	​	646,868	​	​	585,269	​	—
Standardized Measure (millions)	​	$	184	​	$	247	​	$	51	​	—
PV-10 (millions)(2)(13)	​	$	251	​	$	330	​	$	75	​	—
Estimated total possible reserves:	​	​	​	​	​	​	​	​	​	​	​
Natural gas (MMcf).	​	​	833,915	​	​	625,002	​	​	381,941	​	—
Natural gas liquids (MBbls)	​	​	26,650	​	​	25,022	​	​	32,047	​	—
Oil (MBbls)	​	​	619	​	​	789	​	​	1,841	​	—
Total estimated possible reserves (MMcfe)(5)(8)	​	​	997,529	​	​	779,868	​	​	585,269	​	—
Standardized Measure (millions)	​	$	217	​	$	300	​	$	51	​	—
PV-10 (millions)(2)(14)	​	$	294	​	$	400	​	$	75	​	—

(1)

Prices for natural gas, oil and NGLs, respectively, used in preparing our estimated proved reserves and the associated PV-10 Value based on SEC Pricing (i) at June 30, 2023 were $4.763 per MMBtu (Henry Hub), $82.82 per Bbl (WTI Cushing) and NGL pricing equal to 36.7% of WTI Cushing, (ii) at December 31, 2022 were $6.358 per MMBtu (Henry Hub), $93.67 per Bbl (WTI Cushing) and NGL pricing equal to 36.7% of WTI Cushing, (iii) at December 31, 2021 were $3.598 per MMBtu (Henry Hub), $66.56 per Bbl (WTI Cushing) and NGL pricing equal to 39.5% of WTI Cushing and (iv) at December 31, 2020 were $1.985 per MMBtu (Henry Hub), $39.57 per Bbl (WTI Cushing) and NGL pricing equal to 47% of WTI Cushing.

(2)

PV-10 refers to the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. PV-10 is not a financial measure calculated in accordance with GAAP because it does not include the effects of income taxes on future net revenues. PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure. Neither PV-10 nor Standardized Measure represent an estimate of the fair market value of our oil and natural gas properties. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and gas properties. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the Standardized Measure reported in accordance with GAAP, but rather should be considered in addition to the Standardized Measure.

34

(3)

The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated proved developed reserves as of June 30, 2023 and December 31, 2022, 2021 and 2020:

​	June 30, 2023			December 31,
​				2022			2021			2020
PV-10 (millions)	​	$	4,549	​	$	7,389	​	$	2,672	​	$	552
Present value of future income taxes discounted at 10%	​	​	(947)	​	​	(1,580)	​	​	(553)	​	​	(48)
Standardized Measure	​	$	3,602	​	$	5,809	​	$	2,119	​	$	504

(4)

Proved undeveloped reserves as of June 30, 2023 and December 31, 2022 and 2021 are part of a development plan that has been adopted by management indicating that such locations are scheduled to be drilled within five years.

(5)

Sustained lower prices for oil and natural gas may cause us to forecast less capital to be available for development of our PUD, probable and possible reserves, which may cause us to decrease the amount of our PUD, probable and possible reserves we expect to develop within the allowed time frame. In addition, lower oil and natural gas prices may cause our PUD, probable and possible reserves to become uneconomic to develop, which would cause us to remove them from their respective reserves category.

(6)

The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated proved undeveloped reserves as of June 30, 2023 and December 31, 2022, 2021 and 2020:

​	June 30, 2023			December 31,
​				2022			2021			2020
PV-10 (millions)	​	$	594	​	$	1,566	​	$	403	​	$	9
Present value of future income taxes discounted at 10%	​	​	(153)	​	​	(381)	​	​	(108)	​	​	(3)
Standardized Measure	​	$	441	​	$	1,185	​	$	295	​	$	6

(7)

The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated proved reserves as of June 30, 2023 and December 31, 2022, 2021 and 2020:

​	June 30, 2023			December 31,
​				2022			2021			2020
PV-10 (millions)	​	$	5,143	​	$	8,955	​	$	3,074	​	$	561
Present value of future income taxes discounted at 10%	​	​	(1,100)	​	​	(1,961)	​	​	(661)	​	​	(51)
Standardized Measure	​	$	4,043	​	$	6,994	​	$	2,413	​	$	510

(8)

Estimates of probable and possible reserves, respectively, and the respective future cash flows related to such estimates, are inherently imprecise and are more uncertain than proved reserves, and the future cash flows related to such estimates. For more information regarding the presentation of probable and possible reserves, see “Business — Preparation of Reserves Estimates and Internal Controls.”

(9)

The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated probable developed reserves as of June 30, 2023 and December 31, 2022, 2021 and 2020:

​	June 30, 2023			December 31,
​				2022			2021			2020
PV-10 (millions)	​	$	218	​	$	372	​	$	—	​	$	—
Present value of future income taxes discounted at 10%	​	​	(55)	​	​	(91)	​	​	—	​	​	—
Standardized Measure	​	$	163	​	$	281	​	$	—	​	$	—

35

(10)

The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated probable undeveloped reserves as of June 30, 2023 and December 31, 2022, 2021 and 2020:

​	June 30, 2023			December 31,
​				2022			2021			2020
PV-10 (millions)	​	$	281	​	$	563	​	$	202	​	$	—
Present value of future income taxes discounted at 10%	​	​	(78)	​	​	(143)	​	​	(56)	​	​	—
Standardized Measure	​	$	203	​	$	420	​	$	146	​	$	—

(11)

The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated probable reserves as of June 30, 2023 and December 31, 2022, 2021 and 2020:

​	June 30, 2023			December 31,
​				2022			2021			2020
PV-10 (millions)	​	$	499	​	$	935	​	$	202	​	$	—
Present value of future income taxes discounted at 10%	​	​	(133)	​	​	(234)	​	​	(56)	​	​	—
Standardized Measure	​	$	366	​	$	701	​	$	146	​	$	—

(12)

The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated possible developed reserves as of June 30, 2023 and December 31, 2022, 2021 and 2020:

​	June 30, 2023			December 31,
​				2022			2021			2020
PV-10 (millions)	​	$	43	​	$	70	​	$	—	​	$	—
Present value of future income taxes discounted at 10%	​	​	(10)