DRS/A

As confidentially submitted to the Securities and Exchange Commission on October 25, 2022

This draft registration statement has not been publicly filed with the Securities and Exchange Commission
and all information herein remains strictly confidential.

Registration No. 333-      ​

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

CONFIDENTIAL DRAFT SUBMISSION NO. 3

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     , 2022

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 intend to apply 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 30 of this prospectus.

​	Per Share			Total
Public offering price	​	$		​	$
Underwriting discount and commissions(1)	​	$		​	$
Proceeds to us before expenses	​	$		​	$	​

(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            , 2022.

Credit Suisse BofA Securities Barclays

The date of this prospectus is               , 2022.

TABLE OF CONTENTS

​	Page
PROSPECTUS SUMMARY	​	1
RISK FACTORS	​	30
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	​	81
USE OF PROCEEDS	​	83
DIVIDEND POLICY	​	84
CAPITALIZATION	​	85
DILUTION	​	87
UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS	​	88
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	​	99
INDUSTRY	​	138
BUSINESS	​	140
MANAGEMENT	​	188
EXECUTIVE COMPENSATION	​	196
PRINCIPAL STOCKHOLDERS	​	210
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	​	212
DESCRIPTION OF CAPITAL STOCK	​	218
SHARES ELIGIBLE FOR FUTURE SALE	​	226
CERTAIN ERISA CONSIDERATIONS	​	229
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS OF OUR COMMON STOCK	​	231
UNDERWRITING	​	235
LEGAL MATTERS	​	242
EXPERTS	​	242
WHERE YOU CAN FIND MORE INFORMATION	​	243
INDEX TO FINANCIAL STATEMENTS	​	F-1

Dealer Prospectus Delivery Obligation

Through and including             , 2022 (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, Reserve 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, 2021 or June 30, 2022, 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 Condensed Combined Consolidated Financial Statements” included elsewhere in this prospectus.

The historical natural gas, NGL and oil reserves data presented in this prospectus as of September 30, 2022 and December 31, 2021 and 2020 is based on the reserve 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 reserve 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:

“3P” refers to proven, probable and possible reserves.

“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.

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

‘‘IPIECA’’ refers to the International Petroleum Industry Environmental Conservation Association.

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

“LNG” refers to liquefied natural gas.

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“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.

“MMscf” refers to one million standard cubic feet.

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

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

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

“Mtpy CO2e” refers to million metric tonnes of CO2e 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.

“Proved developed non-producing reserves” means reserves (i) expected to be recovered from zones capable of producing but which are shut-in because no market outlet exists at the present time or whose date of connection to a pipeline is uncertain, (ii) wells not capable of producing for mechanical reasons or (iii) currently behind the pipe in existing wells and will require additional completion work or future re-completion, in each case, which are considered proved by virtue of successful testing or production of offsetting wells.

“Proved developed reserves” or “PDP reserves” refers to reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves” refers to the estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions and 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. For a complete definition of proved crude oil and natural gas reserves, refer to the SEC’s Regulation S-X, Rule 4-10(a)(22).

“Proved undeveloped reserves” or “PUD reserves” refers to proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is

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required for recompletion. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

“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 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.

“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.

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, 2022.

“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 O&G.

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

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

“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.

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

“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.

“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.

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

“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.

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

“ESG” refers to environmental, social and governance.

“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.

“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 and Scope 2 emissions in our owned and operated upstream businesses.

“NGP” refers to natural gas processing.

“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 SREC is awarded. 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.

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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 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. 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 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 ESG 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 capital expenditure program, enhance stockholder value and support future acquisitions across our four business lines 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 September 30, 2022, our total acreage position was approximately 505,000 net acres, 99% of which was held by production. As of September 30, 2022, our net daily production (after giving effect to the Exxon Barnett Acquisition) averaged 864 MMcfe/d, consisting of approximately 79% natural gas and approximately 21% NGLs. As of September 30, 2022, our total proved reserves of 6,332 Bcfe had an estimated 7% 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 508 horizontal locations and approximately 1,700 refracture (“refrac”) candidates. Based on current commodity prices, the capital investment required to hold production flat year-over-year is less than approximately 30% of our annual Adjusted EBITDAX. Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP. See “— Summary Historical 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 175,000 net acres, 2,100 operated wells and related upstream, midstream and other assets in the Exxon Barnett Acquisition. As of September 30, 2022, our Barnett acreage position was approximately 468,000 net acres, which is approximately 99% held by production. Our average daily Barnett production of approximately 731 MMcfe/d for the nine months ended September 30, 2022 consisted of 75% natural gas and 25% NGLs. We had an average working interest in our operated wells in the Barnett of approximately 96.8% as of September 30, 2022 and an Effective NRI in the Barnett of approximately 80.37%.

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 (including the Exxon Barnett Acquisition), which represent approximately 29% of the total Barnett production, and nearly double that of the next largest producer in the Barnett for the month of March 2022.

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We entered NEPA in 2016 and have subsequently scaled our position through 12 acquisitions. As of September 30, 2022, our acreage position was approximately 37,000 net acres, which is approximately 94% held by production. Our average net daily production of 133 MMcfe/d for the nine months ended September 30, 2022 consisted entirely of natural gas. We had an average working interest in our operated wells in NEPA of 89%, as of September 30, 2022.

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, as of September 30, 2022, approximately 220 MMcf/d of our gross production (approximately 29% 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 September 30, 2022, 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 Temple I, a newly-constructed, modern combined cycle gas and steam turbine power plant 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 has an annual average power generation capacity of 755 MW and delivers power to customers on the ERCOT power network in Texas. Temple I is among the most efficient generators supplying power to ERCOT, with a baseload design heat rate of approximately 6,950 Btu/kWh, which is well below the ERCOT Combined

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Cycle Gas Turbines (“CCGT”) average. Temple I’s modern technology enables it to respond to rapidly changing market signals in real time by minimizing congestion risk and ensuring the highest operational readiness during the time when electricity consumption peaks (in winter and summer), making it 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 Temple I and its firm intrastate natural gas storage service at the Bammel storage facility. Supplying our own natural gas to Temple I will 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. We intend to continue to build out our power generation business through opportunistic acquisitions of power generation assets and eventually to expand into retail power, which would enable us to ultimately provide net zero wellhead-to-household energy to the end-consumer.

Carbon Capture, Utilization and Sequestration

We are committed to capturing CO2 that is separated from natural gas power generation and compression and from various industrial and natural gas processing CO2 sources, and then compressing and injecting the CO2 into underground injection control (“UIC”) wells. We have been evaluating project opportunities and developing our CCUS business for over 20 months. 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, we will begin generating positive CCUS business revenue via tax credits and other tax benefits by the end of 2023, and we expect to begin generating positive Adjusted EBITDAX in 2025.

We seek to execute CCUS projects with attractive standalone economics for high, medium and low CO2 concentration streams that contribute to our goal of the full elimination and/or offset of the Scope 1 and 2 emissions in our owned and operated upstream businesses by the end of 2025.

In March 2022, we formally launched our CCUS business with the establishment of BKV dCarbon Ventures and in June 2022, we reached a Phase I final investment decision (“FID”) on 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, which we expect to achieve an average injection rate of up to 185,000 tons of CO2 per year. We estimate this initial CCUS project will represent more than 8% of our estimated Scope 1 and 2 emissions from our owned and operated upstream businesses, with the first injection scheduled for the second half of 2023. Following commencement of commercial operations of our project with EnLink, we intend to use this project as a prototype for modular projects that can be repeated and quickly scaled.

On October 18, 2022, BKV dCarbon Ventures reached a Phase I FID to develop our second CCUS project to dispose of, and geologically sequester, acid gas and CO2 generated as a byproduct of the production of our natural gas in the Barnett and will utilize our newly acquired BKV Midstream assets. This CCUS project, which we refer to as the Cotton Cove Project, will separate CO2 from our natural gas production in the Barnett. We estimate the Cotton Cove Project will geologically sequester up to 45,000 tons of CO2 per year initially, which we expect will increase to an average of up to 82,350 tons CO2 per year by the end of 2024 through ongoing well development in the area. We currently estimate the total project cost for the Cotton Cove Project to be between $14.0 and $24.0 million. We expect to own or hold the source, the capture, the transportation pipeline and the lease to the pore space with respect to this project. We are targeting commencement of CO2 injection activities by the first half 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 up to eight potential NGP projects that are in different phases of the appraisal and development process. As part of the Cotton Cove Project, we also expect to pilot, and then scale, post-combustion carbon capture technology that would allow us to sequester an additional 250,000 tons per year of captured CO2 from low concentration emissions from within our BKV Midstream operations. We expect that our technology applications will utilize compressor waste heat to reduce energy requirements and cost. We also expect to

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reduce the cost of low concentration transport and sequestration as the cost of the initial infrastructure build will have been incurred in connection with the high concentration anchor injection. We expect this project to initially offset our current Scope 1 and 2 annual emissions from our owned and operated upstream businesses by approximately 2%, bringing us closer to our goal of reaching net zero across our Scope 1 and 2 owned and operated upstream emissions by the end of 2025.

Further, in August 2022, we entered into a development agreement with Verde CO2 CCS, LLC (“Verde CO2”), an independent carbon capture and sequestration developer and operator, to identify, evaluate and develop additional 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 and aligns with our goal to reach net zero owned and operated upstream emissions across Scope 1 and 2 by the end of 2025. As of October 20, 2022, we have invested $8.3 million to Verde CO2 under the development agreement and we currently expect to invest up to $250.0 million over the next three years to fund efforts by BKVerde, LLC (“BKVerde”), a subsidiary of BKV dCarbon Ventures, to efficiently identify and evaluate a pipeline of feasible CCUS projects, and to execute on those projects. We expect to fund BKVerde through BKV’s cash flow from operations. See “ — Recent Developments — CCUS Project Development with Verde CO2.”

We are currently evaluating and discussing with third parties three to ten additional CCUS projects (inclusive of the projects with Verde CO2). Assuming we reach FID with respect to each of these projects, we would expect to develop and complete each of these projects during the next several years based on economics supported by the carbon tax credits available under Section 45Q of the Code (the “Section 45Q tax credits”).

For three of these potential CCUS projects, we expect to reach FID within three to six months. We believe these projects could generate an aggregate of up to 4.5 Mtpy CO2e in carbon capture and sequestration on a total capital investment of approximately $520.0 million (inclusive of the investment with Verde CO2). We also are currently evaluating an additional seven potential CCUS projects with respect to which we have begun commercial discussions with third parties. Although each of these potential projects are in different stages of the evaluation process and we have not reached FID or entered into any agreements with respect to any of them, if these potential CCUS projects, together with the Barnett Zero Project and the Cotton Cove Project, are ultimately completed, based on our current estimates we believe these potential projects represent a project pipeline of nearly 30 Mtpy CO2e of carbon capture and sequestration, with the largest potential CCUS project representing approximately 8 Mtpy CO2e and the smallest representing approximately 0.8 Mtpy CO2e. The aggregate number of metric tons of CO2 represented by these potential projects would represent nearly twice the aggregate size of our current Scope 1, 2 and 3 emissions from our owned and operated upstream businesses, which we estimate to be approximately 16.1 Mtpy CO2e as of September 30, 2022. See “ — Path to Net Zero Emissions” below for a description of how we estimate our Scope 3 emissions.

We estimate the aggregate cost to us to offset all of our Scope 3 emissions through at least some of these ten identified potential projects, to be between approximately $1.3 billion and $1.8 billion over the next seven to ten years. We expect to fund these costs through our cash flows from operations, as well as a variety of 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 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. In addition, we anticipate that some of the project costs will be borne by third party investors in these projects, including emitters, landowners and other stakeholders.

As we strive to become a leader in CCUS, our steering committee 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.

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Our CCUS business and all of our CCUS projects are in the early stages of development, and we have not executed any definitive agreements with respect to our identified potential projects. In addition, the development of our CCUS business is expected to require material capital investments, and the commercial viability of our CCUS projects depends, in part, 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 the majority of the Section 45Q tax credits, the details of which have not yet been released and are to be included in future guidance. Our ability to establish large scale CCUS projects is subject to numerous risks and uncertainties, including 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 on the timeline we anticipate, on terms acceptable to us or at all. For more information on our CCUS business, see “Business — Our Operations  — Carbon Capture, Utilization and Sequestration.” For more information about the risks involved in our CCUS business, see “Risk Factors — Risks Related to Our CCUS Business.”

Path to Net Zero Emissions

We estimate that our owned and operated upstream Scope 1 and 2 emissions were 2.2 Mtpy CO2e as of September 30, 2022. Our estimates are based on information with respect to our operated assets in the Barnett and NEPA through fiscal year 2021 and reported by BKV for the Subpart W requirements of the U.S. Environmental Protection Agency (“EPA”) and supplemented with additional inventories that are not required to be reported into Subpart W, as well as 2020 Subpart W emission information submitted by XTO Energy, Inc. for the assets acquired in the Exxon Barnett Acquisition. We will further evaluate these estimates as a part of our combined Subpart W submittal for calendar year 2022 and will factor in additional inventory efforts performed during 2022. These estimates fluctuate throughout the year and will be updated on an annual basis to reflect any changes in inventory, production throughput, and emissions reduction retrofits or equipment modifications.

We estimate that our owned and operated upstream Scope 3 emissions were 13.9 Mtpy CO2e as of September 30, 2022. Our 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 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 emissions are estimated at an approximated year-end production volume of 900 million standard cubic feet net equivalent per day of gas, 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 million standard cubic feet net equivalent per day towards combustion as the end use, applying suitable combustion emission factors from the EPA, and using AR4 GWPs, Scope 3 emission from our owned and operated upstream operations are estimated to be approximately 13.9 Mtpy CO2e. We currently leverage third party consultants to develop, estimate and review the Scope 3 emissions.

The charts below reflect (i) our owned and operated upstream Scope 1 and 2 emissions as of September 30, 2022, including Scope 1 and 2 emissions estimates from the Exxon Barnett Acquisition, and (ii) our owned and operated upstream Scope 3 emissions as of September 30, 2022, including Scope 3 emissions estimates from 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 end of 2030, in each case, for our owned and operated upstream businesses. We intend to achieve these goals through our “Pad of the Future” emissions reductions, emissions and leak surveys, and installing solar power and executing CCUS projects.

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(1)

Scope 1 and 2 calculated emissions are based on 545 MMscfd production volume for 2021 BKV Subpart W in the Barnett, 167 MMscfd production volume for 2021 BKV Subpart W in NEPA, and 352 MMscfd production volume with respect to the acquired Exxon Barnett assets based on 2020 Subpart W submissions.

(2)

Emissions surveys to accomplish a one-two month leakage 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.

(1)

Scope 1 and 2 calculated emissions are based on 545 MMscf/d production volume for 2021 BKV Subpart W in the Barnett, 167 MMscf/d production volume for 2021 BKV Subpart W in NEPA, and 352 MMscf/d production volume with respect to the acquired Exxon Barnett assets based on 2020 Subpart W submissions.

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(2)

Emissions surveys to accomplish a one-to-two month leakage 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 900 MMscfe/d (approximately 730 MMscf/d of gas and 28,000 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 produced is assumed to be combusted for fuel. Scope 3 emissions estimation methodology is therefore considered to be conservative.

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 September 30, 2022, we had implemented elements of our “Pad of the Future” on approximately 2,200 of our existing wells, thereby eliminating an aggregate of approximately 0.51 Mtpy CO2e in GHG emissions from commencement in the fourth quarter of 2021 through such date. 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 by the end of 2025 for an aggregate estimated cost of $36.9 million. Once this expansion is completed, we expect to eliminate an aggregate 1.40 Mtpy CO2e, or approximately 64%, of our currently estimated annual Scope 1 and 2 owned and operated upstream emissions.

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 the second quarter of 2023. 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 enough SRECs that, when combined with our leak detection and repair emissions monitoring program, is expected to eliminate or offset approximately 0.18 Mtpy CO2e in GHG emissions.

Further, we believe our total pipeline of potential CCUS projects, together with the Barnett Zero Project and the Cotton Cove Project, will offset more than the remaining 0.61 Mtpy CO2e, or approximately 28%, of our currently estimated annual Scope 1 and 2 owned and operated emissions, by the end of 2025. 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 13.9 Mtpy CO2e as of September 30, 2022. We believe we can achieve this goal if certain of the ten identified potential CCUS projects in our project pipeline are completed upon terms that we believe are obtainable. In addition to these identified projects, we expect to continue to identify and evaluate additional CCUS projects, some of which are already in a preliminary screening stage.

Although we believe our current path to net zero will be sufficient to reduce emissions related to our existing production, the future growth of our natural gas production, midstream and power assets will result in additional CO2e emissions. We believe our approach to reducing the emissions of our direct operations is repeatable and scalable and that 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 eliminate and/or offset any such future emissions in connection with 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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Deliver robust returns to stockholders.    We intend to prioritize delivering strong returns to our stockholders through our dividend policy and focus on creating stockholder value. See “Dividend

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Policy.” 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. The payment of any future dividends on our common stock will be at the discretion of our board of directors and may vary significantly from quarter to quarter and may be zero. Any determination to pay dividends and the amount of any such dividends will depend on, among other factors, the restrictions under our Term Loan Credit Agreement and the Revolving Credit Agreement, as described under “Dividend Policy.” See “Risk Factors — Risks Related to the Offering and Our Common Stock.”

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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-powered instruments on existing pads, combined with emission and leak surveys, reduces our GHG emissions by 72%, based on current Scope 1 and 2 emissions from production in our owned and operated natural gas upstream business. Our Pad of the Future application also improves pad efficiencies and operating revenue. As of the year ended December 31, 2021, employing technology and operational excellence, we reduced our lease operating costs in the Barnett by 14% since October 2020, and in NEPA by 26% since January 2019, based on prior 12-month rolling averages. Additionally, our refrac and long lateral drill programs have allowed us to organically grow our reserves base. As of September 30, 2022, our Barnett refrac program has added 491 Bcfe of proved reserves since its inception in early 2021, with an estimated 1.1 Tcfe net proved, probable and possible (“3P”) reserves at less than an average $0.70/Mcfe finding and development costs during 2021. 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 reserve recovery and economics from legacy Barnett wells. Our Barnett new well drilling program has added 1.1 Tcfe of proved reserves since our entry into the Barnett with a total estimate of approximately 2.1 Tcfe 3P reserves. By combining these 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 in our owned and operated upstream businesses and captures margin across the value chain.

•

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, 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, 2022. 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.

•

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 30% and an Upstream Reinvestment Rate of less than 40%. We are focused on our goal of maintaining a conservative financial profile, with a long-term leverage target of less than 1.0x Total Net Leverage Ratio. 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 below 1.0x 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

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in accordance with GAAP. See “— Summary Historical Financial Information — Non-GAAP Financial Measures” for a description of this measure and a reconciliation to the most directly comparable GAAP measure.

•

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 our “Pad of the Future” emissions reductions program, emissions 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 direct operations, CCUS for third parties has become a core focus of our business plan. We expect to represent a meaningful portion of our budgeted capital expenditures going forward as we advance our long-term goal of eliminating and/or offsetting Scope 3 emissions from our owned and operated upstream businesses.

•

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.

Competitive Strengths

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

•

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.

•

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 468,000 net acres, with an approximately 80.37% 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% year-over-year average base decline rate over the next 10 years as of September 30, 2022. 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.

•

Lower emissions energy production.   We are focused on achieving Scope 1 and 2, net zero operational emissions from our owned and operated upstream production of natural gas by the end of 2025. We believe we have a comprehensive ESG program, which is overseen and directed by an executive ESG steering committee. In 2021, we certified our entire NEPA production and, in 2022, we certified 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 NEPA and Barnett natural gas production as Responsibly Sourced Gas (“RSG”), which we believe could command a premium in the marketplace. In the future, we intend to expand beyond RSG, with aspirations for fully carbon neutral gas sales through net zero Scope 3

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from our owned and operated upstream businesses, which we expect can be achieved beginning in the fourth quarter of 2023 with initial gas sales volumes and continuing through the early 2030s to encompass all gas sales volumes. Additionally, we have a plan to achieve net zero Scope 1 and 2 emissions by the end of 2025 based on our “Pad of the Future” emissions reductions, emissions surveys, installing solar power and executing CCUS projects. We believe BKV dCarbon Ventures will be able to capture and sequester over one million metric tons of CO2 per year by the end of 2025, which exceeds the balance of our current Scope 1 and 2 emissions required to achieve net zero upstream emissions, and will additionally enable initial sales of some fully carbon neutral gas volumes.

•

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 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.

•

Well capitalized and conservative balance sheet.   As of June 30, 2022, we had a Total Net Leverage Ratio of 1.21x. Following the completion of this offering, we intend to continue to maintain a strong balance sheet and fund our 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.

•

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

Barnett Zero CCUS Project with EnLink

On June 8, 2022, BKV dCarbon Ventures and EnLink reached a Phase I FID to develop our first CCUS project and entered into an agreement to dispose of, and geologically sequester, CO2 generated as a byproduct of the production of our natural gas in the Barnett and will utilize our newly acquired BKV Midstream assets. This CCUS project, which we refer to as the Barnett Zero Project, will separate CO2from substantially all of our EnLink-gathered natural gas production, which we expect to achieve an average injection rate of up to 185,000 tons of CO2 per year. We currently estimate the total project cost to us of the Barnett Zero Project to be between $20.0 and $22.0 million. We are targeting commencement of CO2 injection activities by the second half of 2023, subject to our ability to secure all required permits, at which point we expect this project to be one of the first permanent commercial CO2 disposal and sequestration projects to come online in the United States. We expect this project to offset our current Scope 1 and 2 annual emissions from our owned and operated upstream businesses by approximately 8%, bringing us closer to our goal of reaching net zero across Scope 1 and 2 upstream emissions by the end of 2025.

Exxon Barnett Acquisition

On June 30, 2022, we closed the acquisition (the “Exxon Barnett Acquisition”) of natural gas upstream and associated midstream infrastructure in the Barnett from XTO Energy, Inc. and Barnett Gathering LLC, subsidiaries of Exxon Mobil Corporation, for a total purchase price of $750.0 million, plus additional contingent consideration of up to $50.0 million depending on future natural gas prices. Pursuant to the Exxon Barnett Acquisition, we acquired approximately 175,000 total net acres that are approximately 99% held by production, primarily in Tarrant, Johnson and Parker counties, and additional smaller positions in Jack, Wise, Denton, Erath, Hood and Ellis counties, Texas (our “2022 Barnett Assets”). These upstream assets include low decline wells, ideal for delivering consistent cash flow, and high average working interests of

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approximately 94% in over 2,100 operated wells. The Exxon Barnett Acquisition also included approximately 778 miles of gathering pipelines and compression and processing midstream infrastructure with, as of September 30, 2022, over 450 MMcf/d of throughput capacity and approximately 26 MMcf/d of third-party production being gathered on the system. In connection with the Exxon Barnett Acquisition, we entered into the Term Loan Credit Agreement (as defined herein) with a syndicate of banks and Bangkok Bank Public Company Limited (New York Branch), as the administrative agent. The Term Loan Credit Agreement includes up to $600.0 million of commitments for term loans to be used solely to fund a portion of the purchase price for the Exxon Barnett Acquisition and other costs and expenses associated with the acquisition. As of June 30, 2022, there was $570.0 million in aggregate principal amount outstanding under the Term Loan Credit Agreement. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Loan Agreements and Credit Facilities —  Term Loan Credit Agreement” for more information.

Amendment to Derivative Agreement

On August 4, 2022, we entered into an amendment to our ISDA Master Agreement with a counterparty to our derivative contracts pursuant to which we agreed to terminate or novate, at our election, at least $100.0 million of our derivative contracts. As of September 9, 2022, we terminated derivative contracts of $100.2 million with the counterparty to satisfy this requirement. In connection with such termination, we are required to make cash payments to the counterparty in an aggregate amount of $100.2 million, of which $30.0 million was paid in September 2022, an additional $30.0 million is due and payable before October 31, 2022 and the remaining $40.2 million must be paid by November 30, 2022. We intend to make the remaining payments with cash flows from operations. See “Note 14 —  Commitments and Contingencies” to our unaudited condensed consolidated financial statements included elsewhere in this prospectus for additional information regarding this agreement.

CCUS Project Development with Verde CO2

On August 22, 2022, we entered into a development agreement with Verde CO2 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. As of October 20, 2022, we have invested $8.3 million to Verde CO2 As of October 20, 2022, we have paid $8.3 million to Verde CO2 under the development agreement and we currently expect to invest up to $250.0 million over the next three years to fund efforts by BKVerde, LLC (“BKVerde”), a subsidiary of BKV dCarbon Ventures, to efficiently identify and evaluate a pipeline of feasible CCUS projects, and to execute on those projects. We expect to fund BKVerde through BKV’s cash flow from operations.

Revolving Credit Agreement

On August 24, 2022, we entered into a Revolving Credit Agreement (the “Revolving Credit Agreement”) with Bangkok Bank Public Company Limited (New York Branch), as the administrative agent and sole initial lender. The Revolving Credit Agreement includes $100.0 million of commitments for unsecured revolving loans used for short-term working capital and operating needs. As of October 19, 2022, $45.0 million was outstanding under the Revolving Credit Agreement. 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 more additional information regarding the Revolving Credit Agreement.

Cotton Cove CCUS Project

On October 18, 2022, BKV dCarbon Ventures reached a Phase I FID to develop our second CCUS project to dispose of, and geologically sequester, acid gas and CO2 generated as a byproduct of the production of our natural gas in the Barnett and will utilize our newly acquired BKV Midstream assets. This CCUS project, which we refer to as the Cotton Cove Project, will separate CO2 from our natural gas production in

13

the Barnett. We estimate the Cotton Cove Project will geologically sequester up to 45,000 tons of CO2 per year initially, which we expect will increase to an average of up to 82,350 tons CO2 per year by the end of 2024 through ongoing well development in the area. We currently estimate the total project cost for the Cotton Cove Project to be between $14.0 and $24.0 million. We expect to own or hold the source, the capture, the transportation pipeline and the lease to the pore space with respect to this project. We are targeting commencement of CO2 injection activities by the first half 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 up to eight potential NGP projects that are in different phases of the appraisal and development process. As part of the Cotton Cove Project, we also expect to pilot, and then scale, post-combustion carbon capture technology that would allow us to sequester an additional 250,000 tons per year of captured CO2 from low concentration emissions from within our BKV Midstream operations. We expect that our technology applications will utilize compressor waste heat to reduce energy requirements and cost. We also expect to reduce the cost of low concentration transport and sequestration through high concentration anchor injection. We expect this project to initially offset our current Scope 1 and 2 annual emissions from our owned and operated upstream businesses by approximately 2%, bringing us closer to our goal of reaching net zero across our Scope 1 and 2 owned and operated upstream emissions by the end of 2025.

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.

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.”

14

Our Structure

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

(1)

Consists of management, directors and other employee and non-employee stockholders.

The information in the chart above does not include        additional shares of our common stock reserved for future awards pursuant to the BKV Corporation 2022 Equity and Incentive Compensation

15

Plan (the “2022 Plan”), including        shares of common stock that may be issued upon vesting of outstanding equity awards, and        shares of our common stock available for purchase by employees pursuant to the BKV Corporation Employee Stock Purchase Plan (the “ESPP”).

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:

•

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;

•

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”);

•

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

•

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

•

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 and may elect to take advantage of other reduced reporting requirements in our future filings with the Securities and Exchange Commission (the “SEC”). As a result, the information that we provide to our stockholders may be different than you might receive from other public reporting companies in which you hold equity interests.

The JOBS Act also provides that an emerging growth company can take advantage of an extended transition period for complying with new or revised accounting standards, but we have irrevocably elected not to avail ourselves of this exemption. Rather, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.

We may take advantage of these provisions until the last day of our fiscal year following the fifth anniversary of the date of the first sale of our common equity securities pursuant to an effective registration statement under the Securities Act. Such fifth anniversary will occur in 2027. However, if certain events occur prior to the end of such five-year period, including if we become a “large accelerated filer,” our gross revenues for any fiscal year equal or exceed $1.235 billion or we issue more than $1.0 billion of non-convertible debt in any three-year period, we will cease to be an emerging growth company prior to the end of such five-year period.

Controlled Company

We intend to apply to list our common stock on the NYSE. 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:

•

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

16

•

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

•

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        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 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.

17

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 fund the expansion of our CCUS business, $       million in contingent consideration payments to be paid in 2023 with respect to the Devon Barnett Acquisition (as described in Note 15 — Commitments and Contingencies to our audited consolidated financial statements included elsewhere in this prospectus) and the remainder for other general corporate purposes. See “Use of Proceeds.”

Dividend policy

At or prior to the closing of this offering, our board of directors will adopt a written policy pursuant to which we intend to pay to stockholders, subject to the factors described herein, including the restrictions under the Term Loan Credit Agreement and the Revolving Credit Agreement, quarterly cash dividends and to consider the payment of additional special dividends from time to time. 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

18

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 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 intend to list our common stock on the NYSE under the symbol “BKV.”

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 up to        shares of our common stock reserved for future issuance under our equity compensation plans, 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”;

•

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); and

•

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

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:

19

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 reserve 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

•

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;

•

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

•

our ability to fulfill our business plan to supply our own natural gas to Temple I;

•

the disruption of the fuel supplies necessary to generate power at Temple I;

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 for the gathering and processing of our natural gas production;

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 and COVID-19 (including any variants thereof, “COVID-19”);

•

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;

•

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;

20

•

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;

•

exemptions from certain reporting requirements for as long as we are an emerging growth company;

Risks Related to Environmental, Legal Compliance and Regulatory Matters

•

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

•

reductions in demand for natural gas, NGL and oil due to conservation measures and technological advances;

•

the effect of increased attention to ESG matters, conservation measures and technological advances;

•

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

•

significant costs and liabilities related to federal, state and local 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;

•

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;

•

Banpu and its wholly owned subsidiaries ceasing to own at least 51% of our equity interests or allowing any lien to exist on the equity interests in us they own will be an event of default under the Term Loan Credit Agreement and the Revolving Credit Agreement;

•

conflicts of interest between Banpu and us or our other stockholders or conflicts of interest of our 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;

•

risks related to payment of dividends on our common stock, including the lack of sufficient available cash, the discretion of our board of directors, and restrictions in our debt agreements, with respect to payment of dividends and the impact of our dividend policy on our ability to grow;

•

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.

21

Summary Historical and Unaudited Pro Forma Financial Information

The following table shows our summary historical consolidated financial information and summary unaudited pro forma condensed combined consolidated financial information for the periods and as of the dates indicated. The summary unaudited pro forma condensed 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, 2022 and 2021 was derived from our unaudited historical consolidated financial statements, included elsewhere in this prospectus. The summary historical consolidated financial information as of and for the years ended December 31, 2021 and 2020 was derived from our audited historical consolidated financial statements, included elsewhere in this prospectus.

The summary unaudited pro forma condensed combined consolidated financial information was derived from the unaudited pro forma condensed 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, 2021 and the unaudited pro forma condensed consolidated statements of operations data for the six months ended June 30, 2022 has been prepared to give pro forma effect to the Transaction as if it had been consummated on January 1, 2021. This information is subject to, and gives effect to, the assumptions and adjustments described in the notes accompanying the unaudited pro forma condensed 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 June 30, 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 Condensed 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 Six Months Ended June 30, 2022

Pro Forma Year Ended December 31, 2021

​

2022

2021

2021

2020

​

(in thousands, except per share amounts)

Statement of Operations Information:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Revenues and other operating income

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas sales

​

$

487,813

​

$

174,120

​

$

597,050

​

$

101,758

​

*

​

*

NGL sales

​

​

163,498

​

​

111,166

​

​

225,135

​

​

11,952

​

*

​

*

Oil sales

​

​

5,120

​

​

4,056

​

​

7,560

​

​

1,333

​

*

​

*

Natural gas, NGL and oil sales

​

​

656,431

​

​

289,342

​

​

829,745

​

​

115,043

​

875,663

​

1,137,725

Non-operated midstream revenues

​

​

3,344

​

​

3,972

​

​

6,917

​

​

7,458

​

6,965

​

13,161

Derivative (losses) gains, net

​

​

(450,784)

​

​

(178,275)

​

​

(383,847)

​

​

20,755

​

(450,784)

​

(383,847)

Marketing revenues

​

​

5,328

​

​

50,296

​

​

52,616

​

​

—

​

5,328

​

52,616

Other

​

​

1,327

​

​

—

​

​

251

​

​

33

​

1,575

​

518

Total revenues and other operating income

​

​

215,646

​

​

165,335

​

​

505,682

​

​

143,289

​

438,747

​

820,173

22

​

Six Months Ended June 30,

Year Ended December 31,

Pro Forma Six Months Ended June 30, 2022

Pro Forma Year Ended December 31, 2021

​

2022

2021

2021

2020

​

(in thousands, except per share amounts)

Operating expenses

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Lease operating and workover

​

​

45,333

​

​

40,515

​

​

88,105

​

​

31,260

​

​

103,509

​

​

185,853

Taxes other than income

​

​

41,001

​

​

16,697

​

​

45,650

​

​

5,151

​

​

51,697

​

​

67,317

Gathering and transportation

​

​

98,756

​

​

76,756

​

​

173,587

​

​

—

​

​

124,077

​

​

223,382

Accretion of asset retirement obligations

​

​

5,320

​

​

4,904

​

​

10,030

​

​

3,211

​

​

7,093

​

​

13,616

Depreciation, depletion and amortization

​

​

36,800

​

​

40,842

​

​

81,986

​

​

83,388

​

​

61,442

​

​

141,718

Exploration and impairment

​

​

—

​

​

34

​

​

34

​

​

560

​

​

—

​

​

34

General and administrative

​

​

51,497

​

​

37,988

​

​

85,740

​

​

29,442

​

​

51,497

​

​

92,540

Accretion of right of use liabilities(1)

​

​

135

​

​

106

​

​

227

​

​

184

​

​

135

​

​

227

Total operating expenses

​

​

278,842

​

​

217,842

​

​

485,359

​

​

153,196

​

​

399,450

​

​

724,687

(Loss) income from operations

​

​

(63,196)

​

​

(52,507)

​

​

20,323

​

​

(9,907)

​

​

39,297

​

​

95,486

Other income and expense

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Loss on contingent consideration liabilities(2)

​

​

(31,915)

​

​

(115,345)

​

​

(194,968)

​

​

7,135

​

​

(31,915)

​

​

(194,968)

Interest expense

​

​

(6,698)

​

​

(314)

​

​

(2,134)

​

​

(1,713)

​

​

(28,589)

​

​

(51,018)

Other income

​

​

516

​

​

62

​

​

872

​

​

—

​

​

516

​

​

872

Bargain purchase gain

​

​

163,653

​

​

—

​

​

—

​

​

—

​

​

163,653

​

​

—

Gain on settlement of litigation

​

​

16,866

​

​

—

​

​

—

​

​

—

​

​

16,866

​

​

—

(Loss)/income from equity affiliates

​

​

(23,958)

​

​

—

​

​

910

​

​

—

​

​

(23,958)

​

​

910

Interest income

​

​

128

​

​

2

​

​

8

​

​

121

​

​

128

​

​

8

Income (loss) before income taxes

​

​

55,396

​

​

(168,102)

​

​

(174,989)

​

​

(4,364)

​

​

135,998

​

​

(148,710)

Income tax benefit (expense)

​

​

24,903

​

​

38,648

​

​

40,526

​

​

(38,982)

​

​

6,365

​

​

34,482

Net income (loss) and comprehensive income (loss) attributable to BKV Corporation

​

​

80,299

​

​

(129,454)

​

​

(134,463)

​

​

(43,346)

​

​

142,363

​

​

(114,228)

Less accretion of preferred stock to redemption value

​

​

—

​

​

(2,336)

​

​

(3,745)

​

​

—

​

​

—

​

​

(3,745)

Less preferred stock dividends

​

​

—

​

​

(9,900)

​

​

(9,900)

​

​

(460)

​

​

—

​

​

(9,900)

Less deemed dividend on redemption of preferred stock

​

​

—

​

​

(1,353)

​

​

(22,606)

​

​

—

​

​

—

​

​

(22,606)

Net income (loss) and comprehensive income (loss) attributable to common stockholders

​

​

80,299

​

​

(143,043)

​

​

(170,714)

​

​

(43,806)

​

​

142,363

​

​

(150,479)

Net income (loss) and comprehensive income (loss) per common share

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Basic

​

$

0.68

​

$

(1.22)

​

$

(1.46)

​

$

(0.42)

​

$

1.21

​

$

(1.29)

Diluted

​

$

0.65

​

$

(1.22)

​

$

(1.46)

​

$

(0.42)

​

$

1.16

​

$

(1.29)

Weighted average number of common shares outstanding

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Basic

​

​

117,310

​

​

117,052

​

​

116,904

​

​

105,275

​

​

117,310

​

​

116,904

Diluted

​

​

123,221

​

​

117,052

​

​

116,904

​

​

105,275

​

​

123,221

​

​

116,904

Balance Sheet Information (at period end):

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Restricted cash(3)

​

$

17,473

​

$

—

​

$

—

​

$

—

​

​

**

​

​

**

Cash and cash equivalents

​

$

169,161

​

$

90,147

​

$

134,667

​

$

17,445

​

​

**

​

​

**

Total natural gas properties, net

​

$

2,157,889

​

$

1,148,372

​

$

1,176,117

​

$

1,169,297

​

​

**

​

​

**

Total assets

​

$

2,642,395

​

$

1,391,797

​

$

1,620,828

​

$

1,342,492

​

​

**

​

​

**

Total liabilities

​

$

1,787,997

​

$

548,005

​

$

865,889

​

$

262,424

​

​

**

​

​

**

23

​

Six Months Ended June 30,

Year Ended December 31,

Pro Forma Six Months Ended June 30, 2022

Pro Forma Year Ended December 31, 2021

​

2022

2021

2021

2020

​

(in thousands, except per share amounts)

Total mezzanine equity

​

$

152,863

​

$

132,536

​

$

83,847

​

$

137,212

​

​

**

​

​

**

Total stockholders’ equity

​

$

701,535

​

$

711,258

​

$

671,092

​

$

942,856

​

​

**

​

​

**

Statement of Cash Flows Information

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Net cash provided by (used in) operating activities

​

$

160,758

​

$

217,686

​

$

358,133

​

$

(7,405)

​

​

**

​

​

**

Net cash used in investing activities

​

$

(705,791)

​

$

(14,164)

​

$

(161,858)

​

$

(513,992)

​

​

**

​

​

**

Net cash provided by (used in) financing activities

​

$

597,000

​

$

(130,820)

​

$

(79,053)

​

$

442,723

​

​

**

​

​

**

Other Financial Data (unaudited):(4)

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Adjusted EBITDAX

​

$

254,562

​

$

176,917

​

$

281,391

​

$

65,147

​

$

383,469

​

$

419,872

Upstream Reinvestment Rate

​

​

30%

​

​

6%

​

​

24%

​

​

16%

​

​

**

​

​

**

Adjusted Free Cash Flow

​

$

131,195

​

$

122,723

​

$

165,090

​

$

41,794

​

​

**

​

​

**

Adjusted Free Cash Flow Margin

​

​

20%

​

​

36%

​

​

19%

​

​

34%

​

​

**

​

​

**

Total Net Leverage Ratio(5)

​

​

1.21x

​

​

0.10x

​

​

0.10x

​

​

0.10x

​

​

**

​

​

**

(1)

Represents right of use liabilities related to office space, a pipe yard, 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 agreement with Devon Energy for the purchase of our 2020 Barnett Assets. This contingent consideration is stated at fair value on our consolidated balance sheet, 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 can only be used for costs related to the Exxon Barnett Acquisition. We anticipate the restricted cash will be used for remaining 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)

Total Net Leverage Ratio is the ratio of our total debt less cash and cash equivalents to Adjusted EBITDAX. For the six months ended June 30, 2022 and for the pro forma six months ended June 30, 2022, Adjusted EBITDAX has been annualized to $509.1 million and $767.1 million, respectively.

*

Revenues with respect to the 2022 Barnett Assets (as defined herein) for the six months ended June 30, 2022 and the year ended December 31, 2021 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 June 30, 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) before (1) non-cash derivative gain (loss), (2) accretion of asset retirement obligation, (3) accretion of right of use liability, (4) depreciation, depletion,

24

and amortization, (5) exploration and impairment expense, (6) (loss) gain on contingent consideration liabilities, (7) interest expense, (8) income tax benefit (expense), (9) equity-based compensation expense, (10) bargain purchase gains, (11) income from equity affiliates, (12) early settlement of derivative contracts and (13) 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 operation 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 Six Months Ended June 30, 2022

Pro Forma Year Ended December 31, 2021

​

2022

2021

2021

2020

​

(in thousands)

Net income (loss)

​

$

80,299

​

$

(129,454)

​

$

(134,463)

​

$

(43,346)

​

$

142,363

​

$

(114,228)

Unrealized derivative loss (gain)

​

​

200,136

​

​

156,218

​

​

115,161

​

​

(10,329)

​

​

200,136

​

​

115,161

Forward month gas derivative settlement(1)

​

​

32,010

​

​

13,322

​

​

15,773

​

​

(5,489)

​

​

32,010

​

​

15,773

Accretion of asset retirement obligation

​

​

5,320

​

​

4,904

​

​

10,030

​

​

3,211

​

​

7,093

​

​

13,616

Accretion of right of use liabilities

​

​

353

​

​

172

​

​

330

​

​

336

​

​

353

​

​

330

Depreciation, depletion, and amortization

​

​

42,174

​

​

43,856

​

​

88,473

​

​

86,644

​

​

66,816

​

​

148,205

Exploration and impairment expense

​

​

—

​

​

34

​

​

34

​

​

560

​

​

—

​

​

34

Change in contingent consideration liabilities

​

​

31,915

​

​

115,345

​

​

194,968

​

​

(7,135)

​

​

31,915

​

​

194,968

Interest expense

​

​

6,698

​

​

314

​

​

2,134

​

​

1,713

​

​

28,589

​

​

51,018

Income tax (benefit) expense

​

​

(24,903)

​

​

(38,648)

​

​

(40,526)

​

​

38,982

​

​

(6,365)

​

​

(34,482)

Equity-based compensation expense

​

​

20,254

​

​

10,854

​

​

30,387

​

​

—

​

​

20,254

​

​

30,387

Bargain purchase gain

​

​

(163,653)

​

​

—

​

​

—

​

​

—

​

​

(163,653)

​

​

—

Loss (income) from equity affiliates

​

​

23,958

​

​

—

​

​

(910)

​

​

—

​

​

23,958

​

​

(910)

25

​	Six Months Ended June 30,						Year Ended December 31,						Pro Forma Six Months Ended June 30, 2022			Pro Forma Year Ended December 31, 2021
​	2022			2021			2021			2020
​	(in thousands)
Adjusted EBITDAX	​	$	254,562	​	$	176,917	​	$	281,391	​	$	65,147	​	$	383,469	​	$	419,872

(1)

The forward month gas derivative settlement is derived from the Commodity derivative settlements payable/receivable line item in our condensed consolidated statements of cash flows. 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.

Adjusted Free Cash Flow

We define Adjusted Free Cash Flow as net cash provided by (used in) operating activities excluding changes in operating assets and liabilities, less total cash paid for capital expenditures and settlement of contingent consideration (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,
​	2022			2021			2021			2020
​	(in thousands)
Net cash provided by (used in) operating activities	​	$	160,758	​	$	217,686	​	$	358,133	​	$	(7,405)
Changes in operating assets and liabilities	​	​	2,414	​	​	(85,176)	​	​	(126,862)	​	​	59,726
Cash paid for capital expenditures and settlement of contingent consideration (excluding leasehold costs and acquisitions)	​	​	(31,978)	​	​	(9,787)	​	​	(66,181)	​	​	(10,527)
Adjusted Free Cash Flow	​	$	131,195	​	$	122,723	​	$	165,090	​	$	41,794

Summary Reserve, Production and Operating Data

Ryder Scott, our independent petroleum engineers, prepared estimates of our natural gas, NGL and oil proved reserves as of December 31, 2021 and 2020, and as of September 30, 2022, including the assets we acquired in the Exxon Barnett Acquisition. These reserve estimates were prepared in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve 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”). For more information about

26

our proved reserves, see “Business — Preparation of Reserves Estimates and Internal Controls” and Ryder Scott’s summary reserve reports, which are filed as exhibits to the registration statement of which this prospectus forms a part.

The following table provides our total estimated proved reserve information prepared by Ryder Scott as of September 30, 2022 and December 31, 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 September 30, 2022 as compared to December 31, 2021 is primarily due to the Exxon Barnett Acquisition, our refrac and restimulation program and the increase in natural gas prices used in preparing the December 31, 2021 reserve information. There are numerous uncertainties inherent in estimating quantities of proved natural gas, NGL and oil reserves and their values, including many factors beyond our control. See “Risk Factors — Risks Related to Our Upstream Business and Industry — Our estimated proved natural gas, NGL and oil reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in the reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.”

Estimated Proved Reserves at SEC Pricing(1)

​	September 30, 2022			December 31,
​				2021			2020
Estimated proved developed reserves:	​	​	​	​	​	​	​	​	​
Natural gas (MMcf)	​	​	3,857,807	​	​	2,494,926	​	​	1,893,161
Producing	​	​	3,466,758	​	​	2,346,712	​	​	1,893,161
Non-producing	​	​	391,049	​	​	148,214	​	​	0
Natural gas liquids (MBbls)	​	​	177,692	​	​	151,433	​	​	107,234
Producing	​	​	163,830	​	​	142,961	​	​	107,234
Non-producing	​	​	13,862	​	​	8,472	​	​	0
Oil (MBbls)	​	​	1,123	​	​	867	​	​	723
Producing	​	​	1,019	​	​	876	​	​	723
Non-producing	​	​	104	​	​	0	​	​	0
Total estimated proved developed reserves (MMcfe)	​	​	4,930,696	​	​	3,408,723	​	​	2,540,901
Producing	​	​	4,455,853	​	​	3,209,679	​	​	2,540,901
Non-producing	​	​	474,843	​	​	199,044	​	​	0
Estimated proved undeveloped reserves:	​	​	​	​	​	​	​	​	​
Natural gas (MMcf)	​	​	1,140,466	​	​	950,359	​	​	92,373
Natural gas liquids (MBbls)	​	​	42,896	​	​	13,722	​	​	―
Oil (MBbls)	​	​	620	​	​	58	​	​	―
Total estimated proved undeveloped reserves (MMcfe)(3)	​	​	1,401,561	​	​	1,033,040	​	​	92,373
Estimated proved reserves:	​	​	​	​	​	​	​	​	​
Natural gas (MMcf)	​	​	4,998,273	​	​	3,445,285	​	​	1,985,534
Natural gas liquids (MBbls)	​	​	220,587	​	​	165,155	​	​	107,234
Oil (MBbls)	​	​	1,743	​	​	925	​	​	723
Total estimated proved reserves (MMcfe)	​	​	6,332,257	​	​	4,441,763	​	​	2,633,274
Standardized Measure (millions)	​	$	7,648	​	$	2,413	​	$	510
PV-10 (millions)(2)	​	$	9,818	​	$	3,074	​	$	561

(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 September 30, 2022 were $6.127 per MMbtu

27

(Henry Hub), $91.71 per Bbl (WTI Cushing) and pricing equal to 40% of WTI Cushing, (ii) at December 31, 2021 were $3.598 per MMbtu (Henry Hub), $66.56 per Bbl (WTI Cushing) and pricing equal to 39.5% of WTI Cushing and (iii) at December 31, 2020 were $1.985 per MMbtu (Henry Hub), $39.57 per Bbl (WTI Cushing) and pricing equal to 47% of WTI Cushing.

(2)

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

(3)

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.

The following table provides a reconciliation of the Standardized Measure to PV-10 as of September 30, 2022 and December 31, 2021 and 2020:

​	September 30, 2022			December 31,
​				2021			2020
PV-10 (millions)	​	$	9,818	​	$	3,074	​	$	561
Present value of future income taxes discounted at 10%	​	​	2,170	​	​	661	​	​	51
Standardized Measure	​	$	7,648	​	$	2,413	​	$	510

During the nine months ended September 30, 2022 and the year ended December 31, 2021, we incurred costs of approximately $115.5 million and $24.0 million, respectively, to convert 115.9 Bcfe and 45.5 Bcfe, respectively, of proved undeveloped reserves and proved developed non-producing reserves to proved developed reserves. Estimated future development costs relating to the development of our proved undeveloped reserves and proved developed non-producing reserves at September 30, 2022 and December 31, 2021 are approximately $1,311.7 million and $719.0 million, respectively, over the next five years, substantially all of which we expect to finance through cash flow from operations. Our development programs through the first three quarters of 2022 focused on refracturing under-stimulated wells and designing and drilling new wells in both our Barnett and Marcellus assets. All of our PUD reserves are scheduled to be developed within five years of their initial disclosure as PUDs. See “Risk Factors — Risks Related to Our Upstream Business and Industry — The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.”

2021 Activity

During the year ended December 31, 2021, the Company’s proved reserves increased by 1,808.5 Bcfe. The increase in proved reserves was primarily due to increasing commodity pricing improving economics, and additions to the drilling schedule for both proved developed and undeveloped reserves. The Company produced 245.8 Bcfe during the year ended December 31, 2021.

Revisions of previous estimates primarily consisted of upward revisions to proved developed reserves and proved undeveloped reserves of 715.9 Bcfe and 245.6 Bcfe, respectively, as a result of higher average pricing during 2021 for natural gas, NGLs and oil. The remaining upward adjustment of 139.8 Bcfe relates to upward performance adjustments of 219.2 Bcfe offset by a downward revision of 79.4 Bcfe due to increased production costs.

28

Upon completing our evaluation of properties acquired through our Barnett Asset Acquisition, 550.1 Bcfe of proved undeveloped reserves was recognized for 123 gross (94.8 net) locations added to the Company’s revised drilling schedule during 2021. Additional extensions consisted of proved undeveloped reserves of 143.2 Bcfe related to 13.0 gross (9.6 net) locations in the Marcellus Basin recognized from acquired acreage and the revised 2021 drilling plan. Extensions related to proved developed reserves of 34.8 Bcfe consisted of 14 gross (5.9 net) newly drilled wells.

Improved recoveries consisted of 205.4 Bcfe of proved undeveloped reserves recognized as a result of the application of improved recovery techniques to producing wells during the year ended December 31, 2021.

2020 Activity

During the year ended December 31, 2020, the Company’s proved reserves increased by 1,684.5 Bcfe. The increase in proved reserves was due to the Barnett Asset Acquisition offset by downward revisions primarily due to lower average pricing for natural gas during 2020.The Company produced 111.7 Bcfe during the year ended December 31, 2020.

Revisions of previous estimates primarily consisted of a downward revision of 83.0 Bcfe due to a combination of performance adjustments and lower average pricing of natural gas during 2020, and a downward revision of 171.5 Bcfe which removed locations due to lower average pricing of natural gas during 2020. Proved developed reserves were adjusted downward by 127.4 Bcfe due to lower average natural gas prices and performance.

There were no extensions and discoveries of proved developed or proved undeveloped reserves during the year ended December 31, 2020.

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RISK FACTORS

Investing in our common stock involves risks. The information in this prospectus should be considered carefully, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements” and the following risks, before making an investment decision. The risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. The occurrence of any of the following risks or additional risks and uncertainties that are currently immaterial or unknown could materially and adversely affect our business, financial condition, liquidity, results of operations, cash flows, prospects or ability to pay dividends to holders of our common stock. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to Our Upstream Business and Industry

The volatility of natural gas and NGL prices due to factors beyond our control may materially and adversely affect our business, financial condition or results of operations and our ability to make required capital expenditures, meet our debt service obligations and other financial commitments and pay dividends on our common stock.

Our revenues, operating results, cash available to pay dividends and the carrying value of our natural gas properties, as well as our ability to make required capital expenditures (including the $20.0 to $22.0 million estimated total project cost of the Barnett Zero Project, the $14.0 to $24.0 million estimated total project cost of the Cotton Cove Project and the $250.0 million we expect to spend over the next three years in connection with our CCUS project development partnership with Verde CO2), meet our debt service obligations and other financial commitments and pay dividends on our common stock, depend significantly upon the prevailing market prices for natural gas and NGLs. Prices for natural gas and NGLs are subject to wide fluctuations in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors beyond our control. These factors include, but are not limited to:

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worldwide and regional economic conditions impacting the global supply of, and demand for, natural gas and NGLs, including inflation;

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the price, amount, timing and quantity of foreign imports of natural gas and NGLs;

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political conditions in or affecting other producing countries, including the armed conflict between Russia and Ukraine and associated economic sanctions on Russia and conditions in China, the Middle East, Africa and South America;

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the level of global drilling, exploration and production;

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the level of global inventories;

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prevailing market prices on local price indexes in the areas in which we operate and expectations about future commodity prices;

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the impact on worldwide economic activity of an epidemic, outbreak or other public health events, such as the COVID-19 pandemic or threat of such epidemic or outbreak, or any government response to such occurrence or threat;

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increased associated natural gas and NGL production resulting from higher oil prices and the related increase in oil production;

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the proximity of our natural gas and NGL production to, and capacity and cost of, natural gas and NGL pipelines and other transportation and storage facilities, and other factors that result in differentials to benchmark prices;

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local and global supply and demand fundamentals and transportation availability;

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United States storage levels of natural gas and NGLs;

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weather conditions and other natural disasters;

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domestic and foreign governmental regulations, including environmental initiatives and taxation;

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overall domestic and global economic conditions;

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the value of the dollar relative to the currencies of other countries;

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stockholder activism or activities by non-governmental organizations to restrict the exploration, development and production of natural gas, NGLs and oil to minimize emissions of carbon dioxide, a GHG;

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the actions of OPEC and other oil producing countries, including Russia;

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speculative trading in natural gas and NGL derivative contracts;

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technological advances affecting energy consumption and energy supply;

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the price, availability and acceptance of alternative energy sources; and

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the impact of energy conservation efforts.

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas price movements accurately. Changes in natural gas and NGL prices have a significant impact on the amount of natural gas and NGLs that we can produce economically, the value of our reserves, our cash flows and our ability to satisfy obligations under our firm transportation and storage agreements. Historically, natural gas and NGL prices and markets have been volatile, and those prices and markets are likely to continue to be volatile in the future. For example, during the nine months ended September 30, 2022, the Henry Hub natural gas spot price reached a high of $9.85 per MMBtu in August 2022 and a low of $3.73 in January 2022, and during the year ended December 31, 2021, the Henry Hub natural gas spot price reached a high of $23.86 per MMBtu in February 2021 and a low of $2.43 per MMBtu in April 2021, in each case, according to the U.S. Energy Information Administration (the “EIA”).

A substantial percentage of our natural gas and NGL production is gathered, processed and transported by a single third party and all of our natural gas production is marketed by a single third party.

Approximately 99% of our natural gas and NGL production for the assets we acquired in the Devon Barnett Acquisition, which comprised approximately 72%, 77% and 44% of our total natural gas and NGL production for the nine months ended September 30, 2022 and the years ended December 31, 2021 and 2020, respectively, was gathered, processed and transported by EnLink using its gas gathering systems, gas transportation system and gas processing facilities. Any termination or sustained disruption in the gathering, processing and transportation of our natural gas and NGL production by EnLink on its systems and in its facilities would materially and adversely affect our financial condition and results of operations and may limit our ability to pay dividends on our common stock.

We utilize an unaffiliated third party to market all of our natural gas production to various purchasers, which consist of credit-worthy counterparties, including utilities, LNG producers, industrial consumers, major corporations and super majors, in our industry. We rely on the credit worthiness of such third-party marketer, who collects directly from the purchasers and remits to us the total of all amounts collected on our behalf less their fee for making such sales. Our business, financial condition, results of operations and ability to pay dividends on our common stock would be materially adversely affected if such third party fails to remit to us amounts collected by it on our behalf for such sales or if, in the future, it becomes necessary or advisable for us to replace our third-party marketer and we experience disruption in the marketing and sale of our natural gas production for so long as we are unable to find a replacement marketer.

Our estimated proved natural gas, NGL and oil reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in the reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

Numerous uncertainties are inherent in estimating quantities of natural gas, NGL and oil reserves. The process of estimating natural gas, NGL and oil reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, including assumptions regarding future natural gas, NGL and oil prices, subsurface characterization, production levels and operating and development costs. For example, our estimates of our proved reserves

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are based on the unweighted first-day-of-the-month arithmetic average commodity prices over the prior 12 months in accordance with SEC guidelines. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of those estimates. Sustained lower natural gas, NGL and oil prices will cause the 12-month unweighted arithmetic average of the first-of-the-day price for each of the 12 months preceding to decrease over time as the lower natural gas, NGL and oil prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced. To the extent that natural gas, NGL and oil prices become depressed or decline materially from current levels, such conditions could render uneconomic a portion of our proved natural gas, NGL and oil reserves, and we may be required to write down our proved reserves.

Furthermore, SEC rules require that, subject to limited exceptions, PUD reserves may only be recorded if they relate to wells scheduled to be drilled within five years after the date of booking. This rule may limit our potential to record additional PUD reserves as we pursue our drilling program. To the extent that natural gas, NGL and oil prices become depressed or decline materially from current levels, such condition could render uneconomic a number of our identified drilling locations, and we may be required to write down our PUD reserves if we do not drill those wells within the required five-year time frame or choose not to develop those wells at all.

As a result, estimated quantities of proved natural gas, NGL and oil reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to our reserve estimates. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas, NGL and oil attributable to any particular group of properties, the classifications of reserves based on risk of non-recovery and estimates of future net cash flows.

The present value of future net revenues from our proved natural gas, NGL and oil reserves, or PV-10, will not necessarily be the same as the current market value of our estimated proved natural gas, NGL and oil reserves.

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated natural gas, NGL and oil reserves. We currently base the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months. Actual future net revenues from our natural gas, NGL and oil reserves will be affected by factors such as:

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actual prices we receive for natural gas, NGL and oil;

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actual cost of development and production expenditures;

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the amount and timing of actual production;

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transportation and processing; and

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changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of our natural gas, NGL and oil properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas, NGL and oil industry in general. Actual future prices and costs may differ materially from those used in the present value estimate.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

Recovery of PUD reserves requires significant capital expenditures and successful drilling operations. As of September 30, 2022, approximately 1,857 Bcfe, or 29%, of our total estimated proved reserves were undeveloped or behind pipe. The reserve data included in our reserve report assumes that substantial capital expenditures will be made to develop non-producing reserves. We cannot be sure that the estimated costs attributable to our natural gas, NGL and oil reserves are accurate. We may need to raise additional capital

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to develop our estimated PUD reserves over the next five years and we cannot be certain that additional financing will be available to us on acceptable terms, or at all. Additionally, sustained or further declines in commodity prices will reduce the future net revenues of our estimated PUD reserves and may result in some projects becoming uneconomical. Further, our drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows, results of operations and ability to pay dividends on our common stock.

As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures as compared to the completion cost of a vertical well and therefore may result in fewer wells being completed in any given year. The incremental required capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows, results of operations and ability to pay dividends on our common stock.

In general, the volume of production from natural gas, NGL and oil properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. Except to the extent that we conduct successful exploration, exploitation and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future natural gas and NGL production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves as well as the pace of drilling and completion of new wells. Additionally, the business of exploring for, exploiting, developing or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and NGL reserves would be impaired.

If natural gas and NGL prices become depressed for extended periods of time or decline materially from current levels, we may be required to record write-downs of the carrying value of our proved natural gas and NGL properties.

We follow the successful efforts method of accounting for natural gas producing activities. Impairment is indicated when a triggering event occurs and the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset’s carrying value. If undiscounted future cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in our results of operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. Triggering events could include, but are not limited to, an impairment of natural gas and NGL reserves caused by mechanical problems, faster-than-expected decline of reserves, lease-ownership issues, declines in commodity prices and changes in the utilization of midstream gathering and processing assets. If impairment is indicated, fair value is calculated using a discounted-cash flow approach and any excess of carrying value is expensed. Undeveloped natural gas and NGL properties are evaluated for impairment on a regular basis, based on the results of the exploratory activity and management’s evaluation. If the assessment indicates an impairment, an impairment loss is recognized. Future price decreases could result in reductions in the carrying value of our assets and an equivalent charge to earnings.

We periodically evaluate our unproved natural gas, NGL and oil properties to determine recoverability of our costs and could be required to recognize non-cash charges in the earnings of future periods.

As of June 30, 2022, we carried unproved natural gas, NGL and oil property costs of $16.8 million. GAAP requires periodic evaluation of unproved natural gas, NGL and oil property costs on a project-by-project basis. These evaluations are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of these leases and the contracts and permits relevant

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to such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the costs invested in each project, we will recognize non-cash charges in future periods.

Properties that we have acquired or which we may acquire in the future may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with such properties or obtain protection from sellers against such liabilities.

Acquiring natural gas and NGL properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential liabilities, including environmental liabilities. Such assessments are inherently inexact and uncertain. For these reasons, the properties we have acquired or will acquire in the future may not produce as projected. Further, the annual decline rates of reserves are estimated decline rates, which could ultimately be materially different than actual annual decline rates. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. We perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Our failure to correctly assess reservoir and infrastructure characteristics of the natural gas and NGL properties that we acquire or have acquired, or to identify material defects or liabilities associated with such properties, or actual decline rates that differ materially from estimated decline rates, could have a material adverse effect on our financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Market conditions or operational impediments may hinder our access to natural gas and NGL markets or delay or curtail our natural gas and NGL production.

Market conditions or the unavailability of natural gas and NGL processing, transportation or storage arrangements may hinder our access to natural gas and NGL markets or delay or curtail our production. The availability of a ready market for our natural gas and NGL production depends on a number of factors, including the demand for and supply of natural gas and NGLs, the proximity of our natural gas and NGL production to and capacity of pipelines and storage facilities, gathering systems and other transportation, processing, fractionation, refining and export facilities, competition for such facilities and the inability of such facilities to gather, transport, store or process our natural gas and NGL production due to shutdowns or curtailments arising from mechanical, operational or weather related matters, including hurricanes and other severe weather conditions, or pandemics such as the COVID-19 pandemic or regulatory action related thereto.

Our firm transportation and storage agreements require us to pay demand charges for firm transportation and storage capacities that we do not utilize. If we fail to utilize our firm transportation and storage capacities due to production shortfalls or otherwise, then our margins, results of operations and financial performance could be adversely affected.

We enter into long-term firm transportation agreements, which as of September 30, 2022, provided us with a network of approximately 1,087,500 MMBtu/d of combined firm transportation capacity to East Coast, Gulf Coast, and Southeast markets as it relates to our upstream business units. Additionally, BKV-BPP Power has long-term firm transportation and storage agreements, which, as of September 30, 2022, provided BKV-BPP Power with 75,000 MMBtu/d of firm transportation and 2,812,500 MMBtu of firm storage with Energy Transfer. We are obligated under these arrangements to pay a demand charge for firm transportation and storage capacity rights on a majority these pipeline and storage systems regardless of the amount of pipeline or storage capacity we utilize, subject to our right to release all or a portion of our firm transportation or storage capacities to other shippers and reduce our exposure to demand charges. Our minimum aggregate required payments per year under firm gathering and transportation agreements are

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approximately $16.5 million for 2022, $58.0 million for 2023, $42.1 million for 2024, $22.3 million for 2025, $20.5 million for 2026 and $82.5 million for 2027 and beyond. See “Business — Marketing and Differentials.”

If our anticipated production does not exceed the minimum quantities provided in the agreements, and we are unable to purchase natural gas and NGLs from third parties or release our capacity to other shippers, then our margins, results of operations and financial performance could be adversely affected.

Drilling for natural gas wells is a high-risk activity with many uncertainties that could adversely affect our business, financial condition or results of operations.

Drilling natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive natural gas and NGL reserves (including “dry holes”). We must incur significant expenditures to drill and complete wells, the costs of which are often uncertain. It is possible that we will make substantial expenditures on drilling and not discover reserves in commercially viable quantities.

Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, and our drilling operations and those of our third-party operators may be curtailed, delayed or canceled. The cost of our drilling, completing and well operations may increase and our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:

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unexpected drilling conditions;

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title problems;

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pressure or irregularities in formations;

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equipment failures or accidents;

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adverse weather conditions, such as winter storms, flooding and hurricanes, and changes in weather patterns;

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compliance with, or changes in, environmental laws and regulations relating to air emissions, hydraulic fracturing and disposal of produced water, drilling fluids and other wastes, laws and regulations imposing conditions and restrictions on drilling and completion operations and other laws and regulations, such as tax laws and regulations;

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the availability and timely issuance of required governmental permits and licenses; and

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the availability of, costs associated with, and terms of contractual arrangements for, properties, including mineral licenses and leases, pipelines, facilities and equipment to gather, process, compress, store, transport and market natural gas and NGLs and related commodities.

For instance, in our drilling operations across NEPA and the Barnett from time to time we experience certain issues and the occurrence of risks, including, for example, mechanical and instrument or tool failures, drilling difficulties associated with drilling in swelling clay or shales and unconsolidated formation, particularly in certain parts of our Barnett development acreage, wellbore instability and other geological hazards, loss of well control, loss of drilling fluids, inability to establish fluid circulation, loss of drill pipe, loss of casing integrity, stuck tools and drill pipes, insufficient cementing of casing, among other typical shale drilling challenges.

Our failure to recover our investment in wells, increases in the costs of our drilling operations or those of our third-party operators, and/or curtailments, delays or cancellations of our drilling operations or those of our third-party operators in each case due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations.

Drilling, completions, workover and hydraulic fracturing operations are operationally complex activities which present certain risks that could adversely affect our business, financial condition or results of operations.

In our drilling operations, from time to time we experience certain issues and encounter risks, including, for example, mechanical and instrument or tool failures; drilling difficulties associated with drilling in swelling clay or shales and unconsolidated formation, particularly in select parts of our Barnett development

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acreage; wellbore instability and other geological hazards; loss of well control and associated hydrocarbon release and/or natural gas clouds; loss of drilling fluids circulation; surface spills of various drilling or well fluids; subsurface collision with existing wells; proximity of adjacent water wells or aquifers; inability to establish drilling fluid circulation; loss or compromise of drill pipe or casing integrity; surface pumping operations and associated pressure and hydrocarbon hazards; stuck and lost-in-hole tools, drill pipe or casing; large drilling equipment and machinery including electrical hazards; insufficient cementing of casing causing unwanted casing pressure or fluid migration; surface overpressure events from large machinery (horsepower), equipment or well pressure; fines and violations related to relevant laws and regulations; fires and explosions; personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation and trenching and more; structural damage and collapse to large equipment and machinery; major damage or malfunction to key equipment or processes; in certain instances, close proximity of operations to residences and/or communities; among other typical shale basin drilling challenges and risks.

In our hydraulic fracturing, workover and completions activities, from time to time we experience certain issues and encounter risks, including, for example, mechanical and instrument or tool failures; loss of well control and associated hydrocarbon release and/or natural gas clouds; well kick or flowback during completion or fracturing operations; lost or stuck in hole wireline, coiled tubing or workover strings and tools; loss or compromise of workover string, tubing or casing integrity; large completions, wireline, coiled tubing and workover rig equipment and machinery including electrical hazards; insufficient cementing of casing causing unwanted casing pressure or fluid migration while fracturing or thereafter; proximity of adjacent water wells or aquifers and adjacent producing wells; surface spills of various fracturing, freshwater or well fluids or chemicals; surface pumping and flowback operations and associated pressure and hydrocarbon hazards; surface overpressure events from large machinery (horsepower), equipment or well pressure; fines and violations related to relevant laws and regulations; fires and explosions; personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation and trenching and more; structural damage and collapse to large equipment and machinery; major damage or malfunction to key equipment or processes; in certain instances, close proximity of operations to residences and/or communities; among other typical fracturing, workover and completion challenges and risks.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease or other interest in a specific mineral interest. The existence of a material title deficiency can render a lease or other interest worthless and can adversely affect our results of operations and financial condition. The failure of title on a lease, in a unit or any other mineral interest may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of factors, including commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling conditions, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals, urban growth and other factors. If commodity prices become depressed or decline materially from current levels, the number of locations would decrease as increasing numbers of locations would become uneconomic, and any such decrease may be significant. Even to the extent any locations remain capable of economic production, we may determine not to drill such locations until commodity prices recover. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce natural gas and NGLs from these drilling locations. In addition, unless production is established within the spacing units covering

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the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.

Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involves risks and uncertainties in their application.

To the extent we target emerging areas, the results of our horizontal drilling efforts in such areas will generally be more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which may be subject to well spacing, density and proration requirements, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, access to gathering systems, takeaway capacity constraints or otherwise, availability of drilling surface acreage, or commodity prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local landowners and other sources for use in our operations. Some areas in which we have operations have experienced drought conditions that could result in restrictions on water availability or use. Such drought conditions and water stress may become more frequent or intense as a result of climate change. If we are unable to obtain water to use in our operations from local sources or are unable to transport and store such water, we may be unable to economically produce natural gas and NGLs in the affected areas, which could have an adverse effect on our financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

The unavailability or high cost of equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.

We utilize third-party services to maximize the efficiency of our operations. The cost of oilfield services typically fluctuates based on demand for those services. While we currently have excellent relationships with oilfield service companies, there is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages, quality or the high cost of equipment, supplies or personnel could delay or adversely affect our development and exploitation operations, which could have a material adverse effect on our business, financial condition or results of operations.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

As of September 30, 2022, we operated approximately 93% of our net (70% of our gross) acreage. With respect to our natural gas midstream business, we do not operate the NEPA midstream entities, and in the Barnett, as of September 30, 2022, approximately 29% of our gross operated production volumes were gathered and processed by our owned and operated system. We have limited control over properties and midstream facilities which we do not operate or do not otherwise control operations. If we do not operate or otherwise control the properties and midstream facilities in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of wells in which we own a non-operating interest or an operator of midstream facilities in which we have an interest to adequately perform operations, an operator’s financial difficulties,

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including as a result of price volatility or an operator’s breach of the applicable agreements, could reduce our production and revenues. The success and timing of the drilling and development activities on properties operated by others, as well as the midstream activities with respect to our assets, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology.

Risks Related to Our Power Generation Business

We operate our power generation business through a joint venture which we do not control.

We and BPPUS each have a 50% interest in the BKV-BPP Power Joint Venture. For the six months ended June 30, 2022 and the year ended December 31, 2021, our interest in the BKV-BPP Power Joint Venture represented approximately (11.1)% and approximately 0.2% of our revenues, respectively.

In accordance with the terms of the Limited Liability Company Agreement of BKV-BPP Power (the “BKV-BPP Power LLC Agreement”), the BKV-BPP Power Joint Venture is managed by a board of directors consisting of eight members, four of which are appointed by us and four of which are appointed by BPPUS. Consequently, BKV-BPP Power may not take certain material actions without the consent of BPPUS. For example, without the prior consent of BPPUS, the BKV-BPP Power Joint Venture may not:

•

make distributions or determine the amount of cash to be distributed;

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make capital expenditures, including acquisitions; or

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incur indebtedness in an amount greater than $1,500,000.

See “Certain Relationships and Related Party Transactions — BKV-BPP Power Limited Liability Company Agreement.”

We face certain risks associated with shared control, and BPPUS may at any time have economic, business or legal interests or goals that are inconsistent with ours.

We may be required to make additional capital contributions to the BKV-BPP Power Joint Venture.

In addition, BPPUS may be required to make additional capital contributions to fund items approved in the annual budget or other matters approved by the board of directors of BKV-BPP Power. We do not control the timing or the amount which we may be required to contribute. If we fail to make additional capital contributions to BKV-BPP Power, as approved by the board of directors, such failure could be deemed an event of default under the JV LLCA. If an event of default occurs, the non-defaulting party will be entitled to (i) sell the assets of the joint venture and dissolve the joint venture on reasonable terms deemed acceptable to the BKV-BPP board, (ii) obtain specific performance of the non-defaulting party’s obligations, and/or (iii) exercise any other right or remedy provided in law or in equity. If we default on any obligation to make an additional capital contribution to BKV-BPP Power and any of these events were to occur, it could have a material adverse effect on the BKV-BPP Power Joint Venture and on our business, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Operation of electric generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

The ongoing operation of Temple I involves risks that include performance below expected levels of output or efficiency, as well as the unavailability of key equipment or breakdown or failure of equipment or processes (including an inability to obtain key equipment from Siemens natural gas generators and steam turbines and Benson heat recovery steam generators, which are used by Temple I), due to wear and tear, latent defect, design error or operator error or force majeure events, among other things. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems, occur from time to time and are an inherent risk of the business. Unplanned outages typically increase operation and maintenance expenses and capital expenditures and may reduce revenue available to be distributed to BPPUS and us as a result of selling fewer megawatt hours or require us to incur significant

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costs as a result of obtaining replacement power from third parties in the open market to satisfy forward power sales obligations. Our inability to operate the BKV-BPP Power electric generation assets efficiently, manage capital expenditures and costs and generate distributions from Temple I could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Maintenance, expansion and refurbishment of electric generation facilities involve significant risks that could result in unplanned power outages or reduced output.

Temple I may require periodic upgrading and improvement. Any unexpected operational or mechanical failure, including failure associated with breakdowns and forced outages, could reduce the facility’s generating capacity below expected levels, reducing potential cash distributions to BPPUS and us. Unanticipated capital expenditures associated with maintaining, upgrading or repairing our facility may also reduce profitability.

If we make any major modifications to Temple I, we may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under and determined pursuant to the new source review provisions of the Clean Air Act (“CAA”) at the time of such modifications. Any such modifications could likely result in substantial additional capital expenditures. We may also choose to repower, refurbish or upgrade our facility based on our assessment that such activity will provide adequate financial returns. Such facility requires time for development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices. These events could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Temple I may operate, wholly or partially, without long-term power sales agreements.

Temple I may operate without long-term power sales agreements for some or all of its generating capacity and output and therefore be exposed to market fluctuations. Without the benefit of long-term power sales agreements for the facility, we cannot be sure that the BKV-BPP Power Joint Venture will be able to sell any or all of the power generated by the facility at commercially attractive rates or that the facility will be able to operate profitably. This could lead to less predictable revenues, future impairments of the facility’s property, plant and equipment or the closing of the facility, resulting in economic losses and liabilities, which could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Our near-term business plan contemplates the execution of midstream contracts with certain third parties in order to allow us to supply our own natural gas directly to Temple I and its firm intrastate natural gas storage service at the Bammel storage facility. We cannot assure you that we will be successful in obtaining the commercial contracts necessary to facilitate direct delivery of our natural gas production to Temple I on commercially reasonable terms, or at all.

We cannot assure you that we will succeed in any effort to establish midstream contracts that would allow us to supply our own natural gas directly to Temple I and its firm intrastate natural gas storage service at the Bammel storage facility. Although the physical infrastructure exists to supply our own natural gas directly to Temple I and the Bammel storage facility, our ability to utilize that infrastructure depends on whether we can successfully negotiate and enter into new midstream contracts on satisfactory terms or at all. If we fail to enter into such contracts on satisfactory terms or at all, we may be unable to achieve the synergistic cost savings we anticipated in connection with the BKV-BPP Power Joint Venture, which could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Our long-term business plan involves the development of retail power business, which would enable us to ultimately provide net zero wellhead-to-household energy to the end-consumer.

We intend to continue to build out our power generation business through opportunistic acquisitions of power generation assets and eventually to expand into retail power, which would enable us to ultimately

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provide net zero wellhead-to-household energy to the end-consumer. We may be unable to execute on our business plans, demand for these new services may not develop on a large or economic scale, or we may fail to operate a retail power business effectively. If we were unable to develop a commercially successful retail power business effectively or at all, it could limit our future growth in retail energy markets, and any failure to do so in whole or in part or in any significant measure could have a material adverse effect on our retail power business.

BKV-BPP Power enters into financially settled Heat Rate Call Options (“HRCOs”) that may expose it to basis and buyback risk in its operations.

To reduce its exposure to fluctuations in the market price of electricity and natural gas, BKV-BPP Power enters into financially settled HRCOs, which are contracts for the financial purchase and sale of power based on a floating price of natural gas at a predetermined location using a predetermined conversion factor, or heat rate, required to turn the fuel input into electricity. BKV-BPP Power is exposed to basis risk in its operations when its derivative contracts settle financially, and it delivers physical electricity on different terms. For example, if BKV-BPP Power enters into an HRCO, it hedges its electricity production based on an agreed price for that electricity, but physical electricity must be delivered to delivery points in the market it serves. BKV-BPP Power is exposed to basis risk between the hub price specified in the HRCO and the price that it receives for the sales of physical electricity. BKV-BPP Power attempts to hedge basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the quantities that it requires. BKV-BPP Power’s hedging activities do not provide it with protection for all of its basis risk and could result in economic losses and liabilities, which could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Additionally, by using derivative instruments to economically hedge exposure to changes in power prices, we could limit the benefit we would receive from increases in the power prices, which could have an adverse effect on our financial condition. For example, as of June 30, 2022, we had unrealized losses of approximately $54.9 million on two HRCOs as a result of increased power pricing. In the event BKV-BPP Power is not able to satisfy its obligations under the HRCO, it must purchase power at prevailing market price to satisfy the HRCO. Likewise, increases in power pricing could limit the benefit we receive under HRCOs and result in losses. Either such event could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Our costs, results of operations, financial condition, cash flows and ability to pay dividends could be adversely impacted by the disruption of the fuel supplies necessary to generate power at Temple I, whether as a result of failure of contractual counterparties, disruption in fuel delivery infrastructure or otherwise.

Delivery of natural gas to fuel Temple I is dependent upon the infrastructure (including natural gas pipelines) available to serve such generation facility as well as upon the continuing financial viability of contractual counterparties. As a result, the BKV-BPP Power Joint Venture is subject to the risks of disruptions or curtailments in the production of power at our generation facility if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure. Any such disruptions or curtailments could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Risks Related to Our CCUS Business

Our ability to establish large scale CCUS projects is subject to numerous risks and uncertainties. We may be unsuccessful in developing our CCUS business as currently anticipated, either wholly or in significant measure.

A key element of our business strategy includes the development of a CCUS business. We have no prior experience in the development and operation of a CCUS business, which poses different challenges and risks than our existing upstream and midstream businesses. We may be unable to execute on our business plans, demand for these new services may not develop on a large or economic scale, or we may fail to operate our CCUS business effectively. Our CCUS business may also present novel issues in law, taxation,

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emission offset accounting and accreditation, safety or environmental policy, subsurface storage, supply chain, project design and other areas that we may not be able to manage effectively or that could change considerably. Management’s assessment of the risks in this line of business may be inexact and not identify or resolve all the problems that we would face. If we are unsuccessful in timely developing a commercially successful CCUS, business our future growth and results of operations may be materially and adversely affected, and we may be unable to realize much of our current business plans, including timely reaching our net zero goals of Scope 1, 2 and 3 emissions, either by the dates projected or at all.

Due to the early stage nature of CCUS projects and the sector generally, CCUS projects face considerable risks. In particular, the Barnett Zero Project, our BKV dCarbon Ventures CCUS project with EnLink, and the Cotton Cove Project face, and any of our potential CCUS projects in the future, including potential projects we expect to develop with Verde CO2 as well as the pipeline of CCUS projects currently under evaluation process, will face, operational, technological, regulatory and financial risks (including the risk that EnLink, or any of our other future counterparties to a CCUS project, will not meet their financial or performance obligations with respect to the CCUS project).

Although we have identified three to ten potential CCUS projects, these identified potential projects are in different stages of the evaluation process. We have not entered into any definitive agreements with respect to these potential projects and as such, we cannot assure you that we will reach FID, or enter into any definitive agreements with respect to, any of such potential projects. Our stated goals of timely achieving net zero Scope 1, 2 and 3 emissions are dependent, in part, in being able to commercially develop one or more of our existing pipeline of CCUS projects.

Further, our ability to successfully develop the Barnett Zero Project with EnLink, the Cotton Cove Project and any future potential CCUS projects, including projects we expect to develop with Verde CO2, depends on a number of factors that we are not able to fully control, including the following:

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Commercial scale carbon capture is an emerging sector, and there are not substantial precedents to gauge the likely range of structures or economic terms that will be necessary to reach agreeable terms.

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CCUS injection wells are currently subject to overlapping state and federal jurisdiction and new and evolving regulatory frameworks. The timetable for issuance of permits and authorizations required for a CCUS project is uncertain and could entail a multi-year process. The issuance of permits may be subject to regulatory delays and third-party challenges. We cannot guarantee that we will be able to obtain necessary permits on a timely basis, on favorable terms, or at all.

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As CCUS and carbon management represent an emerging sector, regulations may evolve rapidly, which could impact the feasibility of one or more of our anticipated projects. To the extent regulatory requirements are amended or more stringently enforced or new regulatory requirements are added, we may incur additional delays and/or costs in the pursuit of one or more of our carbon capture projects, which costs may be material or may render any one or more of our projects uneconomical.

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We may not own the pore space at all of our CCUS project sites, which may require us to enter into agreements with multiple owners to secure the necessary real estate rights for the extent of the geologic formation that may be utilized. The failure to obtain necessary pore space rights from all owners, in the absence of a state law mechanism for eminent domain or forced amalgamation, could have a material adverse effect on any proposed CCUS project.

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Robust monitoring, recordkeeping and reporting required in connection with CCUS projects may increase the costs of such operations. Different methodologies may be required to satisfy various regulatory and non-regulatory requirements regarding GHG emissions/sequestration at one or more of our projects, including but not limited to compliance with the EPA mandatory Greenhouse Gas Reporting Program.

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CCUS injection wells and carbon sequestration reservoirs or formations may experience integrity, operating or boundary breaches resulting in additional costs, liability and risk from undesired well casing pressures, breakthrough of injected CO2 to the land surface, CO2 plume migration outside of expected or modeled results into undesired or unwanted surface or subsurface areas, well integrity issues or various other outcomes.

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Carbon capture may be viewed as a pathway to the continued use of fossil fuels, notwithstanding that CO2 emissions are intended to be captured. There may be organized opposition to carbon capture, including our projects, alleging concerns relating to the environment, environmental justice, health or safety, or the federal and state governments may cease supporting carbon capture and sequestration.

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The development of a CCUS project may require us to enter into long-term joint ventures with large carbon emitters (which may need to finance and build, often over a multi-year period, the equipment to capture CO2 emissions from various industrial processes) and operators of infrastructure for transporting CO2 (or other GHGs), and we may not be able to do so on agreeable terms or at all.

The development of our CCUS business is expected to require material capital investments.

We estimate the aggregate cost to us to offset all of our Scope 3 emissions through at least some of these ten identified potential projects, to be between approximately $1.3 billion and $1.8 billion over the next seven to ten years. We currently estimate the total project cost to us of the Barnett Zero Project to be between $20.0 and $22.0 million and the total project cost for the Cotton Cove Project to be between $14.0 and $24.0 million. In addition, we currently expect to invest up to $250.0 million over the next three years in connection with our CCUS project development partnership with Verde CO2. Our CCUS projects are expected to have material capital requirements, and there is no certainty that we will be able to timely finance these projects on commercially reasonable terms or at all, which could result in material delays or abandonment of certain projects, which in turn could negatively impact our ability to realize our business plan or to reach our near term and long term net zero goals on our anticipated time frame or at all. We similarly may not be able to reach out positive revenue goals for our CCUS business on the timeline we have predicted, which may likewise adversely impact our business or financial condition. CCUS activities subject us to the financial risks of rising costs of equipment and capital, possible delays in acquiring them, along with the financial impact of our expending capital on these activities in advance of realizing any CCUS cash flows, any of which could negatively impact our financial condition and operational results in future periods.

To the extent CO2 transportation pipelines are not already present in proposed project areas, or if they do not extend to one or more of our project sites, we may be required to convert existing non-CO2 pipelines, or build new CO2 pipelines or lateral connections, which will require more time before we can bring together captured CO2 emissions and transport them to appropriately tested and prepared sequestration sites, require much larger capital expenditures and may be subject to various environmental and other permitting requirements and authorizations as well as third-party easements that could be difficult or costly to obtain, which may render one or more projects uneconomical or impractical. The availability of eminent domain for carbon capture pipelines varies by state and can be highly controversial; there may be organized opposition to eminent domain for carbon capture pipelines, including those associated with our projects, from environmental or landowner groups. Additionally, even in areas where such pipelines are in place, our use of them may require reaching agreements on CO2 transportation with operators of the pipelines.

The commercial viability of our CCUS projects depends, in part, on certain financial and tax incentives provided by the U.S. federal government.

The economics of CCUS projects depend on financial and tax incentives that could be changed or terminated and that may not currently be sufficient for our CCUS projects to be economical. For example, our qualification for the majority of available Section 45Q tax credits is dependent upon our ability to meet certain wage and apprenticeship requirements, the details of which have not yet been released and which are expected to be included in future guidance. If we are unable to obtain the Section 45Q tax credits included in our financial assumptions, many of our proposed CCUS projects may no longer be commercially viable and may not be completed. We cannot assure you that we will be successful in obtaining any or all of the 45Q tax credits currently available.

CCUS projects will require storage of CO2 in subterranean reservoirs over long periods of time. If accidental releases or subsurface migration of CO2 from our CCUS activities were to occur in the course of operating one or more of our CCUS sites, there is the risk of government recapture of Section 45Q tax credits previously claimed by or issued to us, as well as a risk of trespass or other tort or property claims

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related to the accidental release or migration of CO2 beyond the permitted boundaries of any anticipated project as well as the potential for fines and penalties for violations of environmental requirements.

A successful CCUS project in the United States must comply with what we anticipate will be a stringent regulatory scheme involving multiple federal and state permits applicable to the subsurface injection of CO2 for geologic sequestration. Moreover, when we are the operator of a CCUS project, we must demonstrate and maintain levels of financial assurance sufficient to cover the cost of corrective action, injection well plugging, post-injection site care and site closure, and emergency and remedial response. There is no assurance that we will be successful in obtaining permits or adequate levels of financial assurance for one or more of our CCUS projects or that permits can be obtained on a timely basis, whether due to difficulty with the technical demonstrations required to obtain such permits, public opposition, undeveloped regulatory framework, or otherwise.

There can be no assurances that we will be able to execute on our CCUS strategy and successfully develop the Barnett Zero Project with EnLink in the Barnett, the Cotton Cove Project or any future CCUS projects, including projects we expect to develop with Verde CO2, and any failure to do so in whole or in any significant measure could have a material adverse effect on our ability to reach our near term and long term net zero goals on our anticipated time frame or at all, as well as on our liquidity, financial condition, results of operations and ability to pay dividends on our common stock.

Risks Related to Our Midstream Business

Midstream operations are complex activities which present certain risks that could adversely affect our business, financial condition or results of operations.

In operating our midstream and production facilities, from time to time we experience certain issues and encounter risks, including, for example, mechanical and instrument or tool failures; loss of well, pressure vessel, tank or other related equipment control and associated hydrocarbon release and/or natural gas clouds; loss or compromise of casing integrity during production; unwanted casing pressure or fluid migration during production operations; unwanted migration of sequestered carbon dioxide or other fluids in injection wells; temporary and permanent surface facility operations and associated pressure and hydrocarbon hazards; surface overpressure events and other hazards resulting from machinery (horsepower), equipment or well pressure; fines and violations related to relevant laws and regulations; fires and explosions; pipeline loss of containment due to integrity issues, pipeline strikes or other reasons and associated hydrocarbon release; personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation and trenching and more; major damage or malfunction to key equipment or processes; structural damage and collapse to equipment and machinery; in certain instances, close proximity of operations to residences and/or communities; among other typical midstream and production facilities challenges and risks.

We depend on our natural gas midstream system for the gathering and processing of a substantial percentage of our natural gas production.

As of September 30, 2022, we own and operate approximately 778 miles of gathering pipeline, 65 midstream compressors and one amine processing unit. In the event that our natural gas midstream system is unable to process our natural gas production, or its operations are otherwise disturbed or curtailed, we could experience a disruption in our ability to transport our natural gas production, which could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Construction of midstream projects subjects us to risks of construction delays, cost over-runs, limitations on our growth and negative effects on our financial condition, results of operations, cash flows and liquidity.

From time-to-time, we may plan and construct midstream projects, some of which may take a number of months before commercial operation, such as construction of natural gas, NGL and produced water gathering or transportation systems and construction of related facilities. These projects are complex and subject to a number of factors beyond our control, including delays from third-party landowners, the permitting process, government and regulatory approval, compliance with laws, unavailability of materials,

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labor disruptions, environmental hazards, financing, accidents, weather and other factors. Any delay in the completion of these projects could have a material adverse effect on our financial condition, results of operations, cash flows and ability to pay dividends on our common stock. The construction of these midstream facilities requires the expenditure of significant amounts of capital, which may exceed our estimated costs. Estimating the timing and expenditures related to these development projects is very complex and subject to variables that can significantly increase expected costs. Should the actual costs of these projects exceed our estimates, our liquidity and financial condition could be adversely affected. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions.

We do not own all of the land on which our pipelines and other midstream facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipelines and other midstream facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or leases or if such rights-of-way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases, or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere, and reduce our revenue.

Risks Related to Our Business Generally

Substantially all of our oil and gas and midstream properties are concentrated in Texas and Northeast Pennsylvania, making us vulnerable to risks associated with operating in only two geographic areas.

Substantially all of our oil and gas and midstream properties are located in Texas and Northeast Pennsylvania. As a result of this geographic concentration, an adverse development in the natural gas, NGL and oil and/or midstream business in either or both of these operating areas could have a greater impact on our financial condition, results of operations and cash available to pay dividends on our common stock than if we were more geographically diversified. Due to the concentrated nature of our properties, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by governmental regulation, processing or transportation capacity constraints, water shortages or other drought related conditions, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of natural gas, NGLs and oil.

In addition, the weather in these areas can be extreme and can cause interruption in our operations. Severe weather can result in damage to our facilities entailing longer operational interruptions and significant capital expenditures. For instance, during 2021, Winter Storm Uri in Texas resulted in over 1.5 Bcfe of curtailed production and significant freezing and associated downtime across our facilities and equipment.

The effect of fluctuations on supply and demand may become more pronounced within specific geographic natural gas, NGL and oil producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. A number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

A financial crisis or deterioration in general economic, business or industry conditions could materially adversely affect our results of operations, financial condition and ability to pay dividends on our common stock.

Concerns over global economic conditions, stock market volatility, energy costs, geopolitical issues, inflation and U.S. Federal Reserve interest rate increases in response, the availability and cost of credit, and

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slowing of economic growth in the United States and fears of a recession have contributed and may continue to contribute to economic uncertainty and diminished expectations for the global economy.

Although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021, which has continued into 2022, due to a substantial increase in the money supply, a stimulation focused fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery. Inflation rose from 5.4% in June 2021 to 7.0% in December 2021 to 8.5% in July 2022. We have experienced and expect for the foreseeable future to experience supply chain constraints and inflationary pressure on our cost structure. For example, since the end of the third quarter of 2021, our natural gas production business line has experienced 13% in inflationary cost increases. Our 2022 new drill and completion program, in that same period, has experienced 22% overall inflationary cost increases. In addition, during such period, significant cost increases have occurred in services, labor, fuel, proppant and steel tubulars, with tubular cost increases exceeding 75%. These supply chain constraints and inflationary pressures will likely continue to adversely impact our operating costs and if we are unable to manage our supply chain, our ability to procure materials and equipment in a timely and cost-effective manner, if at all, may be negatively impacted, which could materially adversely impact our results of operations, financial condition and ability to pay dividends on our common stock.

In addition, continued hostilities between Russia and the Ukraine and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. The ongoing conflict in Ukraine could continue to have repercussions globally and in the United States by continuing to cause uncertainty, not only in the natural gas, NGL and oil markets, but also in the capital markets. Such uncertainty could result in stock price volatility and supply chain disruptions, as well as higher natural gas, NGL and oil prices which could potentially result in increased inflation worldwide and could negatively impact demand for natural gas, NGLs, oil and electricity.

Concerns about global economic growth can result in a significant adverse impact on global financial markets and commodity prices. In addition, any financial crisis may cause us to face limitations on our ability to borrow under our debt agreements, service our debt obligations, access the debt and equity capital markets and complete asset purchases or sales and may cause increased counterparty credit risk on our derivative instruments and such counterparties to cause us to post collateral guaranteeing performance.

Further, if there is a financial crisis or the economic climate in the United States or abroad deteriorates, worldwide demand for hydrocarbon-based products could materially decrease, which could impact the price at which natural gas and NGLs from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately materially adversely impact our results of operations, financial condition and ability to pay dividends on our common stock. If a material adverse change occurs in our business such that an event of default occurs under our debt agreements, the lenders under such agreements may be able to accelerate the maturity of our debt.

Events outside of our control, including an epidemic or outbreak of an infectious disease, such as COVID-19, or the threat thereof, could have a material adverse effect on our business, liquidity, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

We face risks related to pandemics, epidemics, outbreaks or other public health events, or the threat thereof, that are outside of our control, and could significantly disrupt our business and operational plans and adversely affect our liquidity, financial condition, results of operations, cash flows and ability to pay dividends on our common stock. The COVID-19 pandemic has adversely affected the global economy and has resulted in unprecedented governmental actions in the United States and countries around the world, including, among other things, social distancing guidelines, travel restrictions and stay-at-home orders, among other actions, which caused a significant decrease in activity in the global economy and the demand for oil, and to a lesser extent, natural gas and NGLs.

The nature, scale and scope of the above-described events, combined with the uncertain duration and extent of governmental actions, prevent us from identifying all potential risks to our business. Additionally, the effects of the COVID-19 pandemic might worsen the likelihood or the impact of other risks already

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inherent in our business. We believe that the known and potential impacts of the COVID-19 pandemic and related events include, but are not limited to, the following:

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disruption in the demand for natural gas, NGLs and oil and other petroleum products;

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intentional project delays until commodity prices stabilize;

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a potential future downgrade of our credit rating and potentially higher borrowing costs in the future;

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a need to preserve liquidity, which could result in reductions, delays or changes in our capital expenditures;

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supply chain disruptions, resulting in shortages of, and increased pricing pressures on, among other things, equipment, services and labor;

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liabilities resulting from operational delays due to decreased productivity resulting from stay-at-home orders affecting our workforce or facility closures resulting from the COVID-19 pandemic;

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future asset impairments, including impairment of our natural gas and NGL properties and other property and equipment; and

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infections and quarantining of our employees and the personnel of vendors, suppliers and other third parties.

New variants of COVID-19 could cause further commodity market volatility and resulting financial market instability, or any other event described above, and these are variables beyond our control that may adversely impact our operating cash flows, distributions from unconsolidated affiliates, our ability to pay dividends on our common stock and our ability to access the capital markets.

The success of our business plan depends, in part, on achieving our near term and long term net zero goals on our anticipated time frame.

The development of our CCUS business, as well as the expansion of our “Pad of the Future” program and the effectiveness of our leak detection and repair emissions monitoring program, are critical to our ability to achieve our emissions goal of the full elimination and/or offset of the Scope 1 and 2 emissions in our owned and operated upstream businesses by the end of 2025 and aspirations to offset Scope 3 emissions from our owned and operated upstream businesses by the early 2030s. We may not meet our near term or long term goals by our target date or at all. Likewise our estimated reduction and offsets expected from these initiatives may turn out to be inaccurate. Our CCUS business and all of our CCUS projects are in the early stages of development, and we have not executed any definitive agreements with respect to our identified potential projects. In addition, the development of our CCUS business is expected to require material capital investments, and the commercial viability of our CCUS projects depends, in part, 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 the majority of the Section 45Q tax credits, the details of which have not yet been released and are to be included in future guidance. Our ability to establish large scale CCUS projects is subject to numerous risks and uncertainties, including 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 on the timeline we anticipate, on terms acceptable to us or at all. We may not be successful in developing any of our currently identified potential CCUS projects or others, our actual costs with respect to any CCUS projects may exceed our current estimate and we may not be able to realize the anticipated reductions and offsets in emissions. There can be no assurances that we will be able to execute on our CCUS strategy and successfully develop the Barnett Zero Project with EnLink in the Barnett, the Cotton Cove Project or any future CCUS projects, and any failure to do so in whole or in any significant measure could have a material adverse effect on our ability to meet our Scope 1, 2 and 3 owned and operated upstream emissions goals. Even if we are able to successfully develop such projects, the underlying agreements may not apportion us the right to claim all emissions offsets, which may impact our net zero strategy. See “— Risks Related to Our CCUS Business.”

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Our revolving credit facilities are uncommitted and as a result the lenders under the facilities have no obligation to honor any request for a loan or the issuance of a letter of credit.

We maintain two revolving credit facilities for purposes of funding certain of our working capital needs: a $55.0 million uncommitted credit facility with Oversea-Chinese Banking Corporation Limited, which includes a $25.0 million sublimit for the issuance of standby letters of credit and a $25.0 million uncommitted credit facility with Standard Chartered Bank. We use these revolving credit facilities for letters of credit and working capital purposes. However, as uncommitted facilities, the lenders under these facilities are not obligated to honor any request for a loan or the issuance of a letter of credit. Further, our borrowings under these revolving credit facilities are repayable upon demand by the applicable lender and the interest rates and fees under these revolving credit facilities can be changed by the applicable lender in its discretion. The refusal of either or both of the lenders under these revolving credit facilities to provide additional borrowings, or the demand by either of these lenders to demand repayment in full of any borrowings under either of these facilities, could materially and adversely affect our liquidity, capital resources or result of operations. Further any such occurrences could cause us to materially delay or abandon one or more capital projects or to fund dividends. Finally, we may not be able to timely replace these sources of liquidity at equivalent cost to us or at all.

We may not be able to generate enough cash flow to meet our debt obligations or fund our other liquidity needs.

As of October 19, 2022, our outstanding debt consisted of (i) $75.0 million in aggregate principal amount under the Subordinated Intercompany Loan Agreements (as defined herein) with BNAC, a wholly owned subsidiary of our parent, Banpu, which are subordinated to our obligations under the Term Loan Credit Agreement, (ii) $570.0 million in aggregate principal amount under the Term Loan Credit Agreement, (iii) $45.0 million in aggregate principal amount under our OCBC Credit Facility, (iv) $10.0 million in aggregate principal amount under our SCB Credit Facility (as defined herein) and (v) $45.0 million in aggregate principal amount under our Revolving Credit Agreement. The Term Loan Credit Agreement, which we entered into in connection with closing of the Exxon Barnett Acquisition on June 30, 2022, allows us to borrow up to $600.0 million in the aggregate in the form of multiple loans during the period commencing with the effective date and ending on the date that is six months thereafter solely to finance the Exxon Barnett Acquisition, provides that amounts repaid may not be reborrowed, and requires annual amortization payments equal to 20% of the original balance. On June 30, 2022, we borrowed $570.0 million of term loans under the Term Loan Credit Agreement. In addition to interest expense and principal on our long-term debt, we have demands on our cash resources including, among others, operating expenses and capital expenditures.

In addition to the Term Loan Credit Agreement, we are party to the Revolving Credit Facilities (as defined herein), which include a $55.0 million uncommitted OCBC Credit Facility and a $25.0 million uncommitted SCB Credit Facility and the Revolving Credit Agreement. We use the Revolving Credit Facilities for letters of credit and working capital purposes and borrowings under the Revolving Credit Agreement for working capital purposes.

Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon future performance and our ability to repay or refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, results of operations and other factors, many of which are beyond our control. Our ability to meet our debt service obligations also may be impacted by changes in prevailing interest rates, as borrowings under the Subordinated Intercompany Loan Agreements, the Term Loan Credit Agreement, the Revolving Credit Facilities and the Revolving Credit Agreement bear interest at floating rates.

We may not generate sufficient cash flow from operations. Without sufficient cash flow, there may not be adequate future sources of capital to enable us to service our indebtedness or to fund our other liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be required to adopt alternative strategies that may include:

•

reducing or delaying capital expenditures;

•

seeking additional debt financing or equity capital;

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•

selling assets; or

•

restructuring or refinancing debt.

We may not be able to complete such alternative strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations and fund our liquidity needs, or to refinance our indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations and may limit our ability to pay dividends on our common stock.

We may be unable to achieve or maintain a low target level of indebtedness.

If we refinance all of our existing debt, or we receive the requisite consents from our existing lenders, we may incur significant additional indebtedness in the future in order to make acquisitions or to develop our properties or for other general corporate purposes.

Our level of indebtedness could affect our operations in several ways, including the following:

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a significant portion of our cash flows could be used to service our indebtedness;

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a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

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the covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay dividends on our common stock, and make certain investments;

•

a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

•

our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; and

•

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate, or other purposes.

An increase in our level of indebtedness may further reduce our financial flexibility. Further, a high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, commodity prices, and financial, business, and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings, or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions (including any financial crisis), the value of our assets, and our performance at the time we need capital.

The agreements governing our indebtedness contain restrictive covenants that may limit our ability to respond to changes in market conditions, pursue business opportunities or pay dividends to our stockholders.

The agreements governing our indebtedness contain restrictive covenants that limit our ability to, among other things:

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incur additional debt;

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incur additional liens;

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sell, transfer or dispose of assets;

•

merge or consolidate, wind-up, dissolve or liquidate;

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pay dividends and distributions on, or repurchases of, equity;

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make acquisitions and investments, other than direct investments in natural gas, NGL and oil properties and other assets in permitted lines of business;

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•

enter into certain transactions with our affiliates;

•

enter into sale-leaseback transactions;

•

make optional or voluntary payment of subordinated debt;

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change the nature of our business;

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change our fiscal year to make changes to the accounting treatment or reporting practices;

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amend constituent documents;

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enter into certain hedging transactions.

The Term Loan Credit Agreement and the Revolving Credit Agreement contain, and any future debt agreement may contain, covenants that prohibit us from paying dividends on our common stock under certain circumstances. For additional information regarding the restrictions contained in the Term Loan Credit Agreement and the Revolving Credit Agreement on our ability to pay dividends to our stockholders, see “— Risks Related to the Offering and Our Common Stock — The agreements governing our indebtedness impose restrictions on dividend payments.”

In addition, the Term Loan Credit Agreement, the Revolving Credit Agreement and certain of our other debt agreements require us to maintain financial ratios and tests. Also, the administrative agent under the Term Loan Credit Agreement has approval rights over our annual budget and our quarterly cash forecasts for the succeeding 12-month period. In addition to customary events of default, the Term Loan Credit Agreement and the Revolving Credit Agreement include an event of default if there is a material adverse change in our business.

The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures, withstand a continuing or future downturn in our business or pay dividends to our stockholders.

If we are unable to comply with the restrictions and covenants in our debt agreements, there could be an event of default under the terms of such agreements, which could result in an acceleration of repayment.

If we are unable to comply with the restrictions and covenants in the Subordinated Intercompany Loan Agreements, Term Loan Credit Agreement, Revolving Credit Facilities, the Revolving Credit Agreement or any future debt agreement or if we default under the terms of the Subordinated Intercompany Loan Agreements, Term Loan Credit Agreement, Revolving Credit Facilities, the Revolving Credit Agreement or any future debt agreement, there could be an event of default. Our ability to comply with these restrictions and covenants, including meeting any financial ratios and tests, may be affected by events beyond our control. Further, if, after this initial public offering, Banpu and its wholly owned subsidiaries at any time cease to own at least 51% of our equity interests, or if any such holder allows 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, which may result in amounts owed by us thereunder to become immediately due and payable. Banpu has no obligation to maintain any particular percentage of equity ownership in the Company (other than the 180-day lock-up agreement and other restrictions described in “Shares Eligible for Future Sale”) may at any time sell all or any portion of its equity interests in us. As a result, we cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. In the event of a default under the Subordinated Intercompany Loan Agreements, Term Loan Credit Agreement, Revolving Credit Facilities, the Revolving Credit Agreement or any future debt agreement, the lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend the Term Loan Credit Agreement, Revolving Credit Facilities, the Revolving Credit Agreement or any future debt agreement or obtain needed waivers on satisfactory terms.

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Our borrowings under the Subordinated Intercompany Loan Agreements, Term Loan Credit Agreement, Revolving Credit Facilities and Revolving Credit Agreement expose us to interest rate risk.

Our results of operations are exposed to interest rate risk associated with borrowings under the Subordinated Intercompany Loan Agreements, Term Loan Credit Agreement, Revolving Credit Facilities and Revolving Credit Agreement, which bear interest at rates based on the Secured Overnight Financing Rate (“SOFR”) or an alternative floating interest rate benchmark. In response to inflation, the U.S. Federal Reserve has increased interest rates four times in 2022 and signaled that additional interest rate increases should be expected in 2022. On July 28, 2022, it raised interest rates by 0.75%, representing the fourth increase in interest rates during 2022 to date. Raising or lowering of interest rates by the U.S. Federal Reserve generally causes an increase or decrease, respectively, in SOFR and other floating interest rate benchmarks. As such, if interest rates increase, so will our interest costs. If interest rates continue to increase, it may have a material adverse effect on our results of operations, financial condition and ability to pay dividends on our common stock.

Our hedging activities do not provide downside protection for all of our production and could result in financial losses or could reduce our net income. Further, our derivative contracts contain certain restrictions and covenants.

From time to time, we enter into derivatives contracts in connection with our natural gas and NGLs, including, for instance, swaps, producer collars and enhanced three-way collars. These derivative arrangements are subject to mark-to-market accounting treatment, and the changes in fair market value of our derivative contracts are reported in our statement of operations and comprehensive loss each quarter, which may result in significant non-cash gains or losses. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

These derivative arrangements are designed to reduce our exposure to commodity price decreases. Therefore, to the extent our production is not hedged, we are exposed to declines in commodity prices. In addition, our derivative arrangements may be inadequate to protect us from continuing and prolonged declines in commodity prices. Further, while designed to reduce our exposure to commodity price decreases, these derivatives arrangements may also limit the potential gains we might otherwise receive from increases in commodity prices if such prices rise over the price established by our derivative contracts. For example, for the six months ended June 30, 2022 and 2021, we incurred a realized loss on derivatives of approximately $250.6 million and $22.1 million, respectively. We incurred a realized loss on derivatives of approximately $268.7 million for the year ended December 31, 2021 and a realized gain on derivatives of approximately $10.4 million for the year ended December 31, 2020. For the six months ended June 30, 2022 and 2021, we had an unrealized loss on derivatives of approximately $200.1 million and $156.2 million, respectively. For the years ended December 31, 2021 and 2020, we had an unrealized loss on derivatives of approximately $115.2 million and an unrealized gain on derivatives of approximately $10.3 million, respectively. In trying to manage our exposure to commodity price risk, we may end up with too many or too few derivative contracts, depending upon where commodity prices settle relative to our derivative price thresholds and how our natural gas and NGL volumes fluctuate relative to our expectations when the derivatives were established.

As of September 30, 2022, we have hedged approximately 459,000 MMBtu/d and 304,000 MMBtu/d of our natural gas production for the remainder of 2022 and 2023, respectively. We have hedged approximately 15,000 Bbl/d and 5,300 Bbl/d of NGL production for the remainder of 2022 and 2023, respectively. Our results of operations, liquidity and financial condition would be negatively impacted if prices of natural gas and NGLs were to become depressed or decline materially from current levels, or there is otherwise an unexpected material impact on commodity prices, and we have experienced variances in our results of operations and financial condition due to our hedging transactions.

Our hedging activities do not provide downside protection for all of our production. In addition, our ability to use hedging transactions to protect us from future commodity price declines will be dependent upon commodity prices at the time we enter into future hedging transactions and our future levels of hedging and, as a result, our future net cash flows may be more sensitive to commodity price changes. Further, if commodity prices decline materially, we will not be able to replace our hedges or enter into new hedges at favorable prices.

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Further, our derivative contracts contain certain restrictions and covenants customary for such types of instruments. For example, an ISDA Master Agreement for certain of our derivative contracts (the “Master Agreement”) previously contained a covenant that restricted us from creating, issuing, incurring or assuming additional indebtedness in excess of $75.0 million. In June 2022, in connection with the completion of the Exxon Barnett Acquisition, we borrowed $570.0 million of term loans under the Term Loan Credit Agreement. In connection with exceeding the $75.0 million indebtedness threshold, on August 4, 2022, we executed an amendment to the Master Agreement pursuant to which we are required to novate or terminate, at our election, at least $100.0 million in derivative contracts by October 4, 2022. As of September 9, 2022, we terminated derivative contracts of $100.2 million with the counterparty to satisfy this requirement. In connection with such termination, we are required to make cash payments to the counterparty in an aggregate amount of $100.2 million, of which $30.0 million was paid in September 2022, an additional $30.0 million is due and payable before October 31, 2022 and the remaining $40.2 million must be paid by November 30, 2022. If we fail to satisfy our obligations under the amendment, the debt incurrence covenant in the Master Agreement would apply. This amendment also includes a cross-default provision pursuant to which a default by us of the covenants under our Term Loan Credit Agreement would cause a default under the Master Agreement. See “Note 14 — Commitments and Contingencies” to our unaudited condensed consolidated financial statements included elsewhere in this prospectus for additional information regarding the Master Agreement.

Subject to restrictions in the Term Loan Credit Agreement and the Revolving Credit Agreement, our hedging strategy and future hedging transactions will be determined at our discretion and may be different than what we have done on a historical basis. In the future, we may enter into additional derivative arrangements or reduce our derivative arrangements. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our price hedging strategy may not protect us from significant declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from future commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our natural gas and NGL revenues becoming more sensitive to commodity price fluctuations.

Our hedging transactions could expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. The risk of counterparty nonperformance is of particular concern in the event of disruptions in the financial markets or the significant decline in commodity prices, which could lead to sudden changes in a counterparty’s liquidity and impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of our hedge providers or some other similar proceeding or liquidity constraint might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities.

During periods of falling commodity prices, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

We may experience difficulty in achieving and managing future growth.

Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition, results of operations, cash flows and ability to pay dividends on our common stock. Our ability to grow will depend on a number of factors, including:

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our ability to acquire additional assets and to successfully integrate acquisitions we may make;

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the results of our drilling program;

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commodity prices;

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•

our ability to develop existing prospects;

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our ability to obtain leases or options on properties for which we have seismic data;

•

our ability to acquire additional seismic data;

•

our ability to identify and acquire new exploratory prospects;

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our ability to continue to retain and attract skilled personnel;

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our ability to maintain or enter into new relationships with project partners and independent contractors; and

•

our access to capital.

We are a holding company with no operations of our own, and we depend on our subsidiaries and our joint venture for cash to fund all of our operations, taxes and other expenses and any dividends that we may pay.

Our operations are conducted entirely through our subsidiaries and the BKV-BPP Power Joint Venture. Our ability to generate cash to meet our debt and other obligations, to cover all applicable taxes payable and to declare and pay any dividends on our common stock is dependent on the earnings and the receipt of funds through distributions from our subsidiaries and the BKV-BPP Power Joint Venture. Our subsidiaries’ and the BKV-BPP Power’s ability to generate adequate cash depends on a number of factors, including development of reserves, successful acquisitions of complementary properties, advantageous drilling conditions, natural gas, NGL and oil prices, successful production and sales of electricity, compliance with all applicable laws and regulations and other factors.

Our business is subject to operating hazards that could result in substantial losses or liabilities for which we may not have adequate insurance coverage.

Natural gas and NGLs operations are subject to many risks, including well blowouts, craterings, explosions, uncontrollable flows of natural gas, NGLs or well fluids, fires, pipe, casing or cement failures, abnormal pressure, pipeline leaks, ruptures or spills, vandalism, pollution, releases of toxic gases, adverse weather conditions or natural disasters and other environmental hazards and risks. If any of these hazards occur, we could sustain substantial losses as a result of:

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injury or loss of life;

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severe damage to or destruction of property, natural resources and equipment;

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pollution or other environmental damage;

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investigatory, monitoring, and cleanup responsibilities;

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regulatory investigations and penalties or lawsuits;

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loss of, or delay in revenue;

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suspension or impairment of operations; and

•

repairs to resume operations.

We maintain insurance against some, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. Our insurance includes deductibles that must be met prior to recovery, as well as sub-limits and/or self-insurance. Additionally, our insurance is subject to exclusions and limitations. Our insurance does not cover every potential risk associated with our operations, including the potential loss of significant revenues. We can provide no assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses.

We currently have insurance policies covering our operations that include coverage for general liability, property damage to certain of our real and personal property, and certain personal property of others, excess liability, physical damage to our upstream and midstream properties, operational control of wells, redrilling expenses, pollution and cleanup, site pollution incidents, damage to lease property, business and contingent

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business interruption, management liability, automobile liability, third-party liability, workers’ compensation, employer’s liability, kidnap and ransom and other coverages. Our insurance policies provide coverage for losses or liabilities relating to pollution, but are largely limited to coverage for sudden and accidental occurrences. For example, the site pollution incident policy we maintain includes coverage for obligations, expenses or claims that we may incur from a sudden incident that results in negative environmental effects, including obligations, expenses or claims related to seepage and pollution, cleanup and containment, evacuation expenses and control of the well (subject to policy terms and conditions). In the specific event of a well blowout or out-of-control well resulting in negative environmental effects, such operator’s extra expense coverage would be our primary source of coverage, with the general liability and excess liability coverage referenced above also providing certain coverage.

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. Some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. If we incur substantial liability from a significant event and the damages are not covered by insurance or are in excess of policy limits, then we would have lower revenues and funds available to us for our operations, that could, in turn, have a material adverse effect on our business, financial condition, results of operations and ability to pay dividends on our common stock.

Additionally, we rely to a large extent on transportation owned and operated by third parties and damage to, or destruction of, those third-party facilities could affect our ability to process, transport and sell our production. To a limited extent, we maintain business interruption insurance related to our processing plants where we are insured for potential losses from the interruption of production caused by loss of or damage to the processing plant.

We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our ability to grow.

There is intense competition for acquisition opportunities in our industry and we may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. We may not be able to obtain contractual indemnities from sellers for liabilities incurred prior to our purchase of the business, asset or property. No assurance can be given that we will be able to identify additional suitable acquisition or asset exchange opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. In addition, there can be no assurance that Banpu will not engage in competition with us in the future. See “Risk Factors — Risks Related to Our Relationship with Banpu and its Affiliates — Banpu’s interests, including interests in certain corporate opportunities, may conflict with our interests and the interests of our other stockholders. Conflicts of interest between us and Banpu could be resolved in a manner unfavorable to us and our other stockholders.” Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.

We may make acquisitions of properties or businesses that complement or expand our current business in the future. The successful acquisition of natural gas and NGL properties requires an assessment of several factors, including:

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recoverable reserves;

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future commodity prices;

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operating costs; and

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potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain and rely on numerous assumptions and we may not be able to identify accretive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Reviews may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily

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observable even when a review is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Market forces often prevent us from negotiating contractual indemnification for environmental liabilities and require us to acquire properties on an “as is” basis.

The success of any of our acquisitions, including the Exxon Barnett Acquisition, will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources which may divert management’s attention from other business concerns. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully, or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

In addition, the Subordinated Intercompany Loan Agreements, Term Loan Credit Agreement, Revolving Credit Facilities and the Revolving Credit Agreement will limit our ability to enter into mergers or combination transactions. These debt arrangements also limit our ability to incur indebtedness and liens, which could indirectly limit our ability to engage in acquisitions.

Our business requires substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms or be able to fund our working capital needs from cash flow from operations, which could lead to a decline in our reserves.

The energy industry is capital intensive. We have made and expect to continue to make substantial capital expenditures in our businesses for the acquisition, exploration, production and development of natural gas and NGL reserves, as well as the gathering, processing and transportation of natural gas and NGLs and the development of our CCUS business. Our capital expenditures in 2021 totaled $63.9 million, primarily relating to completion of drilled but uncompleted wells prior to January 1, 2021, projects to increase reserve recovery and investment in non-operated wells.

The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, the availability of CO2 transportation pipelines in proposed CCUS project areas, and legal, regulatory, environmental, technological and competitive developments. A sustained decline in commodity prices may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. Although we intend to finance our future capital expenditures primarily through cash flow from operations and through available capacity under the Revolving Credit Facilities and the Revolving Credit Agreement, our future needs may require us to alter or increase our capitalization substantially through the increase in the size of our working capital facilities, issuance of additional debt or equity securities or the sale of assets.

Our cash flow from operations and access to capital are subject to a number of variables, including:

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the estimated quantities of our natural gas and NGL reserves;

•

the amount of hydrocarbon we produce from existing wells;

•

the prices at which we sell our production;

•

the levels of our operating expenses;

•

take-away and storage capacity;

•

our ability to acquire, locate, develop and produce new reserves; and

•

our ability to borrow under the Revolving Credit Facilities, the Revolving Credit Agreement and any additional working capital facilities that we obtain.

If our revenues decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our

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planned capital budget or operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available capacity under the Revolving Credit Facilities are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition, results of operations and ability to pay dividends on our common stock.

We may be unable to dispose of nonstrategic assets on attractive terms and may be required to retain liabilities for certain matters.

We regularly review our asset base to assess the market value versus holding value of existing assets with a view to optimizing deployed capital. Our ability to dispose of nonstrategic assets or complete dispositions, such as acreage that we do not intend to place on our production schedule prior to lease expirations, could be affected by various factors, including the availability of buyers willing to purchase the nonstrategic assets at prices acceptable to us. Sellers typically retain certain liabilities or agree to indemnify buyers for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets.

As a result, after a sale, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenues.

The energy industry is intensely competitive, and we compete with other companies that have greater resources than we do. Our ability to acquire additional properties, to discover reserves in the future and to execute on potential CCUS projects will be dependent upon our ability to evaluate and select suitable properties to consummate transactions in a highly competitive market. Many of our larger competitors not only drill for and produce natural gas, NGLs and oil, but they also engage in refining operations and market petroleum and other products on a regional, national or worldwide basis. Our competitors may be able to pay more for natural gas and NGL properties, evaluate, bid for and purchase a greater number of properties than our financial or human resources permit and attract capital at lower rates. In addition, these companies may have a greater ability to continue drilling, production and workover activities during periods of low natural gas and NGL prices, to contract for drilling, production and workover equipment, to pay more for and secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The natural gas, NGL and oil industry has periodically experienced shortages of drilling rigs, equipment, hydraulic fracturing fleets, supply chain resources, pipelines and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive natural gas, NGL and oil producing properties, natural gas, NGL and oil companies, undeveloped leases and drilling rights, and CCUS projects. Further, the current inflation may affect us more than it may affect some of our larger competitors. Our inability to compete effectively with our competitors could have a material adverse impact on our business activities, financial condition and results of operations.

The energy industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. Further, competitors may obtain patents which might prevent us from implementing new technologies. In addition, other energy companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the

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most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected.

The inability of one or more of our significant counterparties to meet their payment or performance obligations may adversely affect our financial results.

We are subject to certain credit risks associated with nonpayment or nonperformance by our counterparties, including joint interest partners and customers. Joint interest receivables arise from billing our joint interest partners who own a partial working interest in our natural gas and NGL wells. These entities participate in our natural gas and NGL wells primarily based on their ownership in leases on which we operate, and we have limited ability to control their participation in our natural gas and NGL wells. Sales receivables arise from the sale of our natural gas and NGL production to our customers. We currently market, directly or indirectly, our natural gas and NGL production to energy marketing companies, refineries, gas processors, petrochemical companies, local distribution companies, power plants and other end users.

We maintain credit procedures and policies to mitigate the credit risks posed by our counterparties. However, our credit procedures and policies may not be adequate to fully eliminate the risk and we do not require all of our counterparties to post collateral. If we fail to adequately assess the creditworthiness of our existing or future significant counterparties, or their creditworthiness unexpectedly materially deteriorates, any resulting nonpayment or nonperformance by them could have a materially adverse effect on our financial condition, results of operations and ability to pay dividends on our common stock.

Our business could be negatively affected by security threats and disruptions, including electronic, cybersecurity or physical security threats and other disruptions.

Our businesses face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. Security breaches could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, cash flows and ability to pay dividends on our common stock. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. The risk of a cybersecurity attack may increase as a result of the increased volume of “remote” work due to workplace policy changes resulting from the spread of COVID-19. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

We may face various risks associated with the long-term trend toward increased activism against natural gas, NGL and oil exploration and development activities.

Opposition toward natural gas, NGL and oil drilling and development activity has been growing globally. Companies in the natural gas, NGL and oil industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, environmental compliance and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain projects such as the development of natural gas, NGL and oil shale plays. For example, environmental activists continue to advocate for increased regulations or bans on shale drilling and hydraulic fracturing in the United States, even in jurisdictions that are among the most stringent in their regulation of the industry. Future activist efforts could result in the following:

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delay or denial of drilling permits;

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shortening of lease terms and reduction in lease size;

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restrictions on installation or operation of production, gathering or processing facilities;

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restrictions on the use of certain operating practices, such as hydraulic fracturing, or disposal of related waste materials, such as hydraulic fracking fluids and production;

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increased severance and/or other taxes;

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cyber-attacks;

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legal challenges or lawsuits;

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negative publicity about our business or the natural gas, NGL and oil industry in general;

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increased costs of doing business;

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reduction in demand for our products; and

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other adverse effects on our ability to develop our properties and expand production.

We may need to incur significant costs associated with responding to these initiatives, and there is no guarantee that our responses will produce favorable outcomes or results. Complying with any resulting additional legal or regulatory requirements that are substantial could have a material adverse effect on our business, financial condition, cash flows, results of operations and ability to pay dividends on our common stock.

Prolonged negative investor sentiment toward upstream natural gas, NGL and oil focused companies could limit our access to capital funding, which would constrain liquidity.

Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other sectors have led to lower natural gas, NGL and oil representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the natural gas, NGL and oil sector based on social and environmental considerations. Certain other stakeholders have pressured commercial and investment banks to stop funding natural gas, NGL and oil projects. If this negative sentiment continues for a prolonged period of time, it may reduce the availability of capital funding for potential development projects, each of which could have a material adverse effect our financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

We may be involved in legal proceedings that could result in substantial liabilities.

Like many energy companies, in the ordinary course of our business, we are from time to time involved in various disputes and disagreements that may lead to legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, prospects, financial condition, results of operations, cash flows and ability to pay dividends on our common stock. Accruals for such liability, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could materially change from one period to the next.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce,

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process and sell natural gas and NGLs and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

We are highly dependent on our executive officers and technical personnel, the loss of any of whom could adversely affect our operations. Additionally, the continued success of our business depends on our ability to attract and retain experienced technical personnel.

We depend on the services of our senior management and technical personnel. There can be no assurance that we would be able to replace such members of management with comparable replacements or that such replacements would integrate well with our existing team. Further, the loss of the services of our senior management could have a material adverse effect on our business, financial condition and results of operations. We do not maintain, nor do we plan to obtain, any “key-man” life insurance against the loss of any of these individuals. As a result, we are not insured against any losses resulting from the death of our key employees. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, prospects, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Our continued success will depend, in part, on our ability to attract and retain experienced technical personnel, including geologists, engineers and other professionals. Competition for these professionals is strong and will likely intensify as a significant portion of today’s engineers, geologists and other professionals working within the oil and natural gas industry will reach the age of retirement in the coming years. Acquiring and retaining these personnel could prove more difficult or cost substantially more than estimated.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including disclosure about our executive compensation, that apply to other public companies.

We are classified as an “emerging growth company” under the JOBS Act. In addition, we have reduced Sarbanes-Oxley Act compliance requirements, as discussed elsewhere, for as long as we are an emerging growth company, which may be up to five full fiscal years. Unlike other public companies, we will not be required to, among other things, (i) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or 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, (ii) provide certain disclosure regarding executive compensation required of larger public companies or (iii) hold nonbinding advisory votes on executive compensation.

To the extent that we rely on any of the exemptions available to emerging growth companies, you will receive less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies. If some investors find our common stock to be less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

Risks Related to Environmental, Legal Compliance and Regulatory Matters

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our natural gas and NGL exploration and production operations are subject to complex and stringent laws and regulations. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling and related permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling and related permits with onerous conditions could increase our compliance costs or decrease our opportunities to execute projects and develop acreage. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of natural gas and NGLs we may produce and sell.

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We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of natural gas and NGLs. The possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs or cause us to cease operations. If we are not able to recover the resulting costs through insurance or increased revenues, our financial condition and ability to pay dividends on our common stock could be adversely affected.

Increased attention to ESG matters and environmental conservation measures may adversely impact our business.

Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG initiatives and disclosures and consumer demand for alternative forms of energy may result in increased costs (including but not limited to increased costs related to compliance, stakeholder engagement, contracting and insurance), reduced demand for our products, reduced profits, increased investigations and litigation and negative impacts on our access to capital markets. Increasing attention to climate change, environmental justice and environmental conservation, for example, may result in demand shifts for natural gas, NGL and oil products and additional governmental investigations and private litigation against us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. Such disclosures may also be at least partially reliant on third-party information that we have not, or cannot, independently verify. In addition, we expect there will likely be increasing levels of regulation, disclosure-related and otherwise, with respect to ESG matters, and increased regulation will likely lead to increased compliance costs as well as scrutiny that could heighten all of the risks identified in this risk factor. We may also take certain actions to improve the ESG profile of our company and/or products, but we cannot guarantee that such actions will have the desired effect.

Additionally, in March 2022, the SEC proposed new rules relating to the disclosure of a range of climate-related data, risks and opportunities. We are currently assessing this rule, but we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, we or our customers could incur increased costs related to the assessment and disclosure of climate-related risks. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive sectors.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change and natural capital related concerns, which could affect our access to capital for potential growth projects. Moreover, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees. Such ESG matters may also impact our suppliers or customers, which may adversely impact our business, financial condition, or results of operations.

Energy conservation measures and technological advances could reduce demand for natural gas, NGL and oil.

Energy conservation measures, alternative fuel requirements, governmental requirements for renewable energy resources, increasing consumer demand for alternatives to natural gas, NGL and oil, technological

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advances in fuel economy and energy generation devices could reduce demand for natural gas, NGLs and oil. The impact of the changing demand for natural gas, NGL and oil services and products may have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes, droughts and floods), sea levels, the arability of farmland, changes in temperature and other meteorological patterns, and water availability and quality. If such effects were to occur, our development and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate related damages to our facilities or in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. We have developed and started to implement a plan to address the potential impacts of climate change on our operations, but we cannot assure you that our operations will not be negatively impacted by climate change.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of natural gas and NGL wells and adversely affect our production.

Hydraulic fracturing is used in many of our operations to stimulate production of hydrocarbons, particularly natural gas and NGLs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation to fracture the surrounding rock and stimulate production. The U.S. Congress (“Congress”) from time to time has considered legislation to amend the federal Safe Drinking Water Act (“SDWA”) to remove the exemption currently available to hydraulic fracturing, which would place additional regulatory burdens upon hydraulic fracturing operations, including requirements to obtain a permit prior to commencing operations adhering to certain construction requirements, to establish financial assurance, and to require reporting and disclosure of the chemicals used in those operations. This legislation has not passed.

Hydraulic fracturing (other than that using diesel) is currently generally exempt from regulation under the SDWA’s UIC program and is typically regulated by state oil and natural gas commissions or similar agencies. However, several federal agencies have asserted regulatory authority or pursued investigations over certain aspects of the process.

For example, in June 2016, the EPA adopted effluent limitations for the treatment and discharge of wastewater resulting from onshore unconventional natural gas, NGL and oil extraction facilities to publicly owned treatment works and, in 2014, the EPA asserted regulatory authority pursuant to the UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities.

Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances.” The final report identified the following risks: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. To date, EPA has taken no further action in response to the December 2016 report.

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In addition, some states have adopted, and other states are considering adopting, regulations that restrict or could restrict hydraulic fracturing in certain circumstances. Further, state and local governmental entities have exercised the regulatory powers to regulate, curtail or in some cases prohibit hydraulic fracturing. New laws or regulations that impose new obligations on, or significantly restrict hydraulic fracturing, could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable and increase our cost of doing business. Such increased costs and any delays or curtailments in our production activities could have a material adverse effect on our business, prospects, financial condition, results of operations, liquidity and ability to pay dividends on our common stock.

Regulatory action may cause us to shut in or curtail production.

Our rate of production and access to transportation and storage options may also be affected by U.S. federal and state regulation of oil and natural gas production. In 2020, actions of foreign oil producers such as Saudi Arabia and Russia and the impact on global demand of the COVID-19 pandemic materially decreased global crude oil prices and generated a surplus of oil. As a result, regulatory action to curtail production has been contemplated in Texas. For example, the TRRC, which regulates the production of oil and natural gas in the State of Texas, held a hearing in April 2020 regarding potential production cuts for producers in Texas in light of the recent decline in oil prices globally. While the TRRC ultimately declined to institute mandatory production cuts, the agency may choose to revisit the issue. Global and domestic oil prices have recovered substantially to the point that TRRC curtailments are highly unlikely. However, if the TRRC decides to limit the production of crude oil in Texas, our business and results of operations are not likely to be materially and adversely impacted given that our production comes from dry gas wells.

Any such production limitations will likely force us to shut in production. If we are forced to shut in production as a result of regulatory actions or otherwise, we will likely incur greater costs to bring the associated production back online. Cost increases necessary to bring the associated wells back online may be significant enough that such wells would become uneconomic at low commodity price levels, which may lead to decreases in our proved reserve estimates and potential impairments and associated charges to our earnings. If we are able to bring wells back online, there is no assurance that such wells will be as productive following recommencement as they were prior to being shut in. Any shut in or curtailment of the natural gas and NGLs produced from our fields could adversely affect our financial condition, results of operations, cash flows, ability to pay dividends on our common stock and ability to fulfill our obligations under our firm transportation service agreements.

Our operations are subject to a series of risks relating to climate change that could result in increased compliance or operating costs, limit the areas in which we may conduct natural gas and NGL exploration and production activities, and reduce demand for the natural gas and NGLs we produce.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of carbon dioxide, methane and other GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, the Inflation Reduction Act, recently passed by Congress, imposed several new climate-related requirements on oil and gas operations. Additionally, President Biden has highlighted addressing climate change as a priority of his administration and has issued several executive orders addressing climate change. In August 2022, the U.S. Congress passed, and President Biden signed into law, the Inflation Reduction Act of 2022, which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on GHG emissions from certain facilities. The emissions fee and funding provisions of the law could increase our operating costs and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations.

Moreover, following the U.S. Supreme Court finding in 2007 that GHG emissions constitute a pollutant under the CAA, the EPA adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring

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and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the DOT, imposing GHG emissions and fuel economy standards for vehicles in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years. The EPA previously had promulgated New Source Performance Standards (“NSPS”) imposing limitations on methane emissions from sources in the oil and gas sector. Subsequently, in September 2020, the Trump Administration rescinded those methane standards and removed the transmission and storage segments from the oil and gas source category under the CAA’s NSPS. However, on June 30, 2021, President Biden signed a resolution passed by Congress under the Congressional Review Act nullifying the September 2020 rule, effectively reinstating the prior standards. In addition, on November 15, 2021, the EPA proposed rules that would establish requirements for methane emissions from existing and modified oil and gas sources and impose additional requirements for new sources with respect to methane emissions. The EPA has announced that it hopes to finalize these rulemakings by the end of 2022. The reinstatement of direct regulation of methane emission for new sources and the promulgation of requirements for existing oil and gas sources and enhanced requirements for new sources could result in increased compliance costs or otherwise impact our results of operations.

Various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, several states, including Pennsylvania and New Mexico, have proposed or adopted regulations restricting the emission of methane from exploration and production activities. At the international level, President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ economy-wide GHG emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. President Biden also agreed in November 2021 to cooperate with Chinese leader Xi Jinping on accelerating the transition to a global net zero economy. The impacts of these pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time. However, to the extent these developments result in new restrictions on natural gas and NGL operations, increase operational costs, or otherwise reduce the demand for natural gas and NGLs, they could have a material adverse effect on our business.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates now in public office. On January 27, 2021, President Biden issued an executive order that calls for substantial action on climate change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors. The Biden Administration also issued orders temporarily suspending the issuance of authorizations, and suspending the issuance of new leases pending a study, for oil and gas development on federal lands, although such orders are no longer in effect. For more information, see “Business — Government Regulation and Environmental Matters.” As a result, we cannot predict the full impact of these developments or whether the Biden Administration may pursue further restrictions. Other actions that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities.

Increasing attention to global climate change has resulted in increased investor attention and an increased risk of public and private litigation, which could increase our costs or otherwise adversely affect our business. A number of parties have sought to bring suit against the largest oil and gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing, handling or marketing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages, or alleging that the companies have been aware of

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the adverse effects of climate change for some time but failed to adequately disclose those impacts. The ultimate outcome and impact to us of any such litigation cannot be predicted with certainty, and we could incur substantial legal costs associated with defending these and similar lawsuits in the future. Stockholder activism has also recently been increasing in our industry, and stockholders may attempt to effect changes to our business or governance, whether by stockholder proposals, public campaigns, proxy solicitations or otherwise. Any of these risks could result in unexpected costs, negative sentiments about us, disruptions in our operations, increases to our operating expenses and reduced demand for our products, which in turn could have an adverse effect on our business, financial condition and results of operations.

There are also increasing financial risks for fossil fuel producers as stockholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into other sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. President Biden signed an executive order calling for the development of a “climate finance plan” and, separately, the Federal Reserve has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. More recently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

Additionally, in March 2022, the SEC proposed new rules relating to the disclosure of a range of climate-related data, risks and opportunities. The proposed rule would impose several new disclosure obligations, including (i) disclosure on an annual basis of a registrant’s Scope 1 and Scope 2 GHG emissions, with third-party independent attestation of such emissions for accelerated filers, (ii) disclosure on an annual basis of a registrant’s Scope 3 GHG emissions for accelerated filers, (iii) disclosure on how the board of directors and management oversee climate-related risks and certain climate-related governance items, (iv) disclosure of information related to a registrant’s publicly announced climate-related targets, goals and/or transition plans and (v) disclosure on whether and how climate-related events and transition activities impact line items above a threshold amount on a registrant’s consolidated financial statements, including the impact of the financial estimates and the assumptions used. We are currently assessing this rule, but we cannot predict the costs of implementation or any potential adverse impacts resulting from the rule. To the extent this rule is finalized as proposed, we or our customers could incur increased costs related to the assessment and disclosure of climate-related risks. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive sectors. The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and gas sector or otherwise restrict the areas in which this sector may produce oil and gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and gas. Additionally, political, litigation and financial risks may result in us restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operations.

Our ability to pursue our business strategies may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental, health and safety laws or regulations or a release into the environment.

We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise

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under a wide range of federal, state and local environmental, health and safety laws and regulations, including, for example, the following federal laws and their state counterparts, as amended from time to time:

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the CAA, which regulates the emission of air pollutants from many sources, imposes various preconstruction, monitoring and reporting requirements and is relied upon by the EPA as authority for adopting climate change regulatory initiatives relating to GHG emissions;

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the Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterbodies are subject to federal jurisdiction and rulemaking as protected waters of the United States;

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the SDWA, which is designed to protect the quality of the nation’s public drinking water through adoption of drinking water standards and UIC over the subsurface injection of fluids into belowground formations;

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the federal Resource Conservation and Recovery Act, as amended (“RCRA”), which imposes requirements for the generation, treatment, storage, transport, disposal and cleanup of nonhazardous and hazardous wastes;

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the federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which imposes liability on generators, and those who arrange for the transportation, treatment or disposal, of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur as well as on present and certain past owners and operators of those sites;

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the Emergency Planning and Community Right-to-Know Act, which requires facilities to implement a safety hazard communication program and disseminate information to employees, local emergency planning committees and response departments about toxic chemical uses and inventories; and

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the Endangered Species Act (“ESA”), which restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating limitations or restrictions or a temporary, seasonal or permanent ban on operations in affected areas.

These U.S. laws and their implementing regulations, as well as state counterparts, generally restrict the level of pollutants emitted to ambient air, discharges to surface water and disposals or other releases or threats of release to surface, soils and groundwater. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the incurrence of capital expenditures, the occurrence of delays in the permitting, development or expansion of projects and the issuance of orders enjoining some or all of our future operations in a particular area. Certain environmental laws impose strict joint and several liability, without regard to fault or legality of conduct, for costs required to clean up and restore sites where hazardous substances or other wastes have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, wastes or other materials into the environment. In addition, these laws and regulations may restrict the rate of natural gas and NGL production or underground injection, disposal, and sequestration of CO2. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material adverse effect on our business and operating results.

In addition, as a result of these environmental, health and safety laws and regulations, and their impact on our operations, we rely on specialized contracted companies to perform the majority of the specialized services inherent in the oil and gas industry. As such, we rely on the ability of these contractors to provide trained labor and properly designed and maintained equipment unique to their services. With the cyclical nature of the oil and gas business, the personnel used by these specialized contractors to perform these services may differ significantly in experience levels. From time to time, these specialized contractors may use new personnel that are still in training or may further sub-contract these services to other companies or personnel. There is a risk that these sub-contractors are unqualified or under-trained or that their equipment is not properly designed or maintained, which could result in work being performed inadequately or unsafely.

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Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the oil and gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or production or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Our gathering systems and processing, treating and fractionation facilities are subject to state regulation that could have a material adverse effect on our operations and cash flows.

State regulation of gathering systems and processing, treating and fractionation facilities includes safety and environmental requirements. In addition, several of our gas gathering systems are also subject to non-discriminatory take requirements and complaint-based state regulation with respect to our rates and terms and conditions of service. Our NGL gathering pipelines and operations may also be or become subject to state public utility or related jurisdiction which could impose additional safety and operational regulations relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL gathering facilities. State and local regulation may cause us to incur additional costs, limit our operations, or prevent us from choosing the customers to which we provide service, any or all of which could have a material adverse effect on our operations and revenue.

Temple I is subject to the rules and regulations of the Public Utility Commission of Texas (the “PUCT”) and ERCOT, which could have a material adverse effect on our operations and cash flows.

Temple I is subject to the rules and regulations of the PUCT and ERCOT. These regulations can impact the operations of generation facilities, which in turn can impact associated costs and revenues. For example, the PUCT is currently considering changes to its rules regarding weatherization of power plants, which could increase capital and operations and maintenance costs for generation facilities. In addition, from time to time, ERCOT makes changes to its protocols or takes out of market actions that impact the wholesale power market. These regulations may cause us to incur additional costs or face delays, or otherwise could have a material adverse effect on our operations and cash flows.

We may face unanticipated water and other waste disposal costs as a result of increased water-related regulations.

We may be subject to regulation that restricts our ability to discharge water produced as part of our natural gas and NGL production operations. Productive zones frequently contain water that must be removed for the natural gas and NGLs to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce natural gas and NGLs in commercial quantities. The produced water must be transported from the leasehold and/or injected into disposal wells. The availability of disposal wells with sufficient capacity to receive all of the water produced from our wells may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability. Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may have to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

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we cannot obtain future permits from applicable regulatory agencies;

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water of lesser quality or requiring additional treatment is produced;

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our wells produce excess water;

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new laws and regulations require water to be disposed in a different manner; or

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costs to transport the produced water to the disposal wells increase.

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In June 2016, the EPA adopted effluent limitations for the treatment and discharge of wastewater resulting from onshore unconventional natural gas, NGL and oil extraction facilities to publicly owned treatment works. The disposal of fluids gathered from natural gas, NGL and oil producing operations in underground disposal wells has been pointed to by some groups and regulators as a potential cause of increased induced seismic events in certain areas of the country, particularly in Oklahoma, Texas, Colorado, Kansas, New Mexico and Arkansas. Certain states have begun to consider or adopt laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing those requirements may issue orders directing certain wells in areas where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. Any one or more of these developments could also increase our cost to dispose of our produced water.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Our natural gas gathering operations are generally exempt from the jurisdiction and regulation of the Federal Energy Regulatory Commission (“FERC”), except for certain anti-market manipulation provisions. Section 1(b) of the Natural Gas Act (“NGA”) exempts natural gas gathering facilities from regulation by FERC as a natural gas company as defined under that statute. We believe the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gathering pipeline not subject to regulation by FERC. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is fact intensive and the subject of ongoing litigation. If FERC were to consider the status of our gathering systems and determine that they are subject to FERC regulation, the rates for, and terms and conditions of, services provided by those gathering systems would be subject to modification by FERC under the NGA or the Natural Gas Policy Act (“NGPA”). Such regulation could decrease revenue, increase operating costs, and adversely affect our business, financial condition, and results of operations. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, it could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such services in excess of the rates established by FERC.

The pipelines used to gather and transport natural gas we produce are subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In April 2016, pursuant to one of the requirements of the 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currently regulated gas gathering and transmission pipelines. The proposal would also significantly expand the regulation of gas gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, and maximum allowable operating pressure limits, among others. PHMSA later announced that the agency would issue three separate final rulemakings relating to the original proposed rule for natural gas pipelines. In October 2019, PHMSA submitted three major rules to the Federal Register, including rules focused on: the safety of gas transmission pipelines (the first of three parts of the so-called gas Mega Rule), the safety of hazardous liquid pipelines and enhanced emergency order procedures. The gas transmission rule requires operators of gas transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the maximum allowable operating pressure. In addition, the rule updates reporting and records retention standards for gas transmission pipelines. PHMSA is expected to issue the second and third parts of the gas Mega Rule in the near future. The safety and hazardous liquid pipelines rule would extend leak detection requirements to all non-gathering hazardous liquid pipelines and require operators to inspect affected pipelines following extreme weather events or natural disasters to address any resulting damage. Finally, the enhanced emergency procedures rule focuses on increased emergency safety measures. In particular, this rule increases the authority of PHMSA to issue an emergency order that addresses unsafe conditions or hazards that pose an imminent threat to pipeline safety. Additional future regulatory action expanding PHMSA’s jurisdiction and imposing stricter integrity management requirements is possible. The

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adoption of laws or regulations that apply more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased operating costs that could be significant. In addition, should we fail to comply with PHMSA or comparable state regulations, we could be subject to substantial fines and penalties. The maximum civil penalties PHMSA can impose are $239,142 per pipeline safety violation per day, with a maximum of $2,391,412 for a related series of violations.

Restrictions on drilling, completion, production or related activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Natural gas and NGL operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife, such as those restrictions imposed under the ESA. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, development and production activities that could have an adverse impact on our ability to develop and produce our reserves. To the extent species are listed or re-designated under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us to incur costs or take other measures which may materially impact our business or operations.

Potential transactions that could benefit our stockholders may be subject to regulatory review and approval requirements, including pursuant to foreign investment regulations and review by governmental entities such as the Committee on Foreign Investment in the United States (“CFIUS”), or may be ultimately prohibited.

Potential transactions we consider may be subject to regulatory review and approval requirements by governmental entities, or ultimately prohibited. For example, CFIUS has authority to review direct or indirect foreign investments in U.S. companies. Among other things, CFIUS is empowered to require certain foreign investors to make mandatory filings, to charge filing fees related to such filings, and to self-initiate national security reviews of foreign direct and indirect investments in U.S. companies if the parties to that investment choose not to file voluntarily. In the case that CFIUS determines an investment to be a threat to national security, CFIUS has the power to unwind or place restrictions on the investment. Whether CFIUS has jurisdiction to review an acquisition or investment transaction depends on, among other factors, the nature and structure of the transaction, including the level of beneficial ownership interest and the nature of any information or governance rights involved. For example, investments that result in “control” of a U.S. business by a foreign person always are subject to CFIUS jurisdiction. CFIUS’s expanded jurisdiction under the Foreign Investment Risk Review Modernization Act of 2018 and implementing regulations that became effective on February 13, 2020 further includes investments that do not result in control of a U.S. business by a foreign person but afford certain foreign investors certain information or governance rights in a U.S. business that has a nexus to “critical technologies,” “critical infrastructure” and/or “sensitive personal data.”

For so long as Banpu retains a material ownership interest in us, we may be deemed a “foreign person” under the regulations relating to CFIUS. As such, potential transactions involving a U.S. business or foreign business with U.S. subsidiaries that we may wish to pursue may be subject to CFIUS review. If a particular transaction falls within CFIUS’s jurisdiction, we may determine that we are required to make a mandatory filing or that we will submit to CFIUS review on a voluntary basis, or to proceed with the transaction without submitting to CFIUS and risk CFIUS intervention, before or after closing the transaction. CFIUS may decide to block or delay transactions that could benefit our stockholders, impose conditions with respect to such transactions or request the President of the United States to order us to divest all or a portion

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of the assets or companies we acquired without first obtaining CFIUS approval, which may limit the attractiveness of, delay or prevent us from pursuing certain target companies or assets that we believe would otherwise be beneficial to us and our stockholders, any of which could have a material adverse effect on our financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Our sales of natural gas and NGLs, and any hedging activities related to such commodities, expose us to potential regulatory risks.

Sales of natural gas and NGLs are not currently regulated and are made at negotiated prices. However, the federal government historically has been active in the area of natural gas and NGL sales regulation. We cannot predict whether new legislation to regulate natural gas and NGL sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, the proposals might have on our operations.

Additionally, the Federal Trade Commission and the Commodity Futures Trading Commissions (the “CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of natural gas and NGLs, and any hedging activities related to these energy commodities, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect our financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

The adoption of derivatives legislation and regulations by Congress related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized.

In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on December 5, 2016, a re-proposed rule imposing position limits for certain futures and option contracts in various commodities (including natural gas, NGL and oil) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. A final rule has not yet been issued. Similarly, on December 2, 2016, the CFTC has reissued a proposed rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, but the CFTC has not yet issued a final rule.

The CFTC has also adopted final rules regarding aggregation of positions, under which a party that controls the trading of, or owns 10% or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. The CFTC’s aggregation rules are now in effect, though CFTC staff have granted relief from various conditions and requirements in the final aggregation rules until the earlier of August 12, 2025 and the effective date of any rulemaking that codifies the relief. With the implementation of the final aggregation rules and upon the adoption and effectiveness of final CFTC position limits rules, our ability to execute our hedging strategies described above could be limited. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.

The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable

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mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types of swap transactions. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.

All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate our commercial risks, these rules and regulations may require us to comply with position limits and with certain clearing and trade-execution requirements in connection with our financial derivative activities. When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require our current swap dealer counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which capital requirements rule could increase the costs to us of future financial derivatives transactions. The Volcker Rule provisions of the Dodd-Frank Act may also require our current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as credit-worthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us, as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.

As a result, the Dodd-Frank Act and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect our capital available for other commercial operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.

If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of commodity prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to natural gas, NGLs and oil. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

Potential future legislation or the imposition of new or increased taxes or fees may generally affect the taxation of natural gas, NGL and oil exploration and development companies and may adversely affect our cash flows.

During the past two years, there have been a significant number of federal and state level legislative proposals that, if enacted into law, would make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently available to natural gas, NGL and oil exploration and development companies. For example, late last year the U.S. House of Representatives passed legislation that was not ultimately enacted and, earlier this year, the Biden administration set forth several tax proposals, that would, if ultimately enacted into law, make significant changes to U.S. tax laws. Such proposals include, but are not limited to, (i) an increase in the U.S. federal income tax rates applicable to corporations, (ii) the repeal of the percentage depletion allowance for certain natural gas, NGL and oil properties, (iii) the elimination of current deductions for intangible drilling and development costs and (iv) an increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas, NGL and oil within the United States. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, the states in which we operate or own assets may impose new or increased taxes or fees on

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natural gas, NGL and oil extraction. The passage of any legislation as a result of these proposals and other similar changes in U.S. federal income tax laws or the imposition of new or increased taxes or fees on natural gas, NGL and oil extraction could adversely affect our operations and cash flows.

Our tax liabilities potentially are subject to periodic audits by U.S. federal, state and local taxing authorities. Although we believe we have used reasonable interpretations and assumptions in calculating our tax liabilities, the final determination of these tax audits and any related proceedings cannot be predicted with certainty. Any adverse outcome of any such tax audits or related proceedings could result in unforeseen tax-related liabilities that may, individually or in the aggregate, materially affect our cash tax liabilities, and, as a result, our business, financial condition, results of operations, and liquidity.

Our business is subject to complex and evolving laws and regulations regarding privacy and data protection.

The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of personal or confidential information pose increasingly complex compliance challenges and could potentially elevate our costs. Any failure to comply with these laws and regulations could result in significant penalties and legal liability. We continue to monitor and assess the impact of these laws, which in addition to penalties and legal liability, could impose significant costs for investigations and compliance, require us to change our business practices and carry significant potential liability for our business should we fail to comply with any such applicable laws.

Risks Related to Our Relationship with Banpu and its Affiliates

Banpu is our controlling stockholder and exercises substantial influence over us, and your ability to influence matters requiring stockholder approval may be limited.

Upon completion of this offering, Banpu will indirectly own approximately    % of our outstanding common stock (or approximately     % if the underwriters exercise in full their option to purchase additional shares). Our outstanding common stock is entitled to one vote per share. As a result of its ownership of our common stock, Banpu will indirectly own approximately    % of the combined voting power of our common stock immediately after completion of this offering (or approximately     % if the underwriters exercise in full their option to purchase additional shares). As a result of this ownership, Banpu has a substantial influence on our affairs and its voting power will constitute a substantial percentage of any quorum of our stockholders voting on any matter requiring the approval of our stockholders. Such matters include the election of directors, the adoption of amendments to our certificate of incorporation and bylaws and the approval of mergers or the sale of all or substantially all of our assets. Banpu’s control or significant influence over us also may delay, defer or prevent an acquisition by a third party or other change of control of our Company and may make some transactions more difficult or impossible without the support of Banpu, even if such events are in the best interests of our other stockholders.

In addition, pursuant to 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 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 — Controlled Company,” “Principal Stockholders” and “Certain Relationships and Related Party Transactions — Stockholders’ Agreement.”

In addition, we do not control the BKV-BPP Power Joint Venture. We and BPPUS jointly control BKV-BPP Power through a board of directors consisting of eight members, four of which are appointed by us and four of which are appointed by BPPUS. See “Risks Related to Our Power Generation Business — We operate our power generation business through a joint venture which we do not control.” Further, if, after this initial

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public offering, Banpu and its wholly owned subsidiaries cease to own at least 51% of our equity interests, or if any such holder allows 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, which may result in the amounts owed by us thereunder to become immediately due and payable.

The interests of Banpu may differ from our interests or those of our other stockholders and the concentration of control in Banpu will limit other stockholders’ ability to influence corporate matters. Banpu may take actions that our other stockholders do not view as beneficial or decline to take actions that our other stockholders view as beneficial, which may adversely affect our business, financial condition, results of operations and our ability to pay dividends on our common stock. In addition, Banpu’s control or significant influence over us may have an adverse effect on the price of our common stock.

Historically we have relied on Banpu and its affiliates for capital investments sufficient to fund our business operations. Banpu has no obligation to make any further capital investments or to provide additional loan proceeds.

Prior to the consummation of this offering, we have relied on Banpu and its affiliates for the capital investments necessary to fund our business through loan proceeds and other contributions. Following this offering, Banpu and its affiliates will have no obligation to provide any additional funding, and instead, we expect to fund our capital expenditures through cash flows from operations and from borrowings under our Revolving Credit Facilities and the Revolving Credit Agreement. Our future operating performance and to meet our debt service obligations will be affected by economic and capital market conditions, results of operations and other factors, many of which are beyond our control.

Restrictive covenants in the agreements governing the indebtedness of Banpu may limit our ability to incur additional debt.

The agreements governing the indebtedness of Banpu require it to maintain certain financial ratios and tests based on consolidated financial statements. Immediately after completion of this offering, Banpu, or a subsidiary of Banpu, will continue to have a substantial influence on our affairs and its voting power will constitute a substantial percentage of any quorum of our stockholders voting on any matter requiring the approval of our stockholders. As a result, Banpu may prevent us from taking corporate actions that could cause Banpu to fail to comply with the applicable provisions of its debt agreements, even when such actions are in our best interests and the interests of our other stockholders. This limitation may materially adversely affect our ability to obtain future financing or fund needed capital expenditures.

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.

Upon the completion of this offering, Banpu will beneficially control a majority of the combined voting power of all classes of our outstanding voting stock. Pursuant to our Stockholders’ Agreement, BNAC, through ownership interests in us held by BNAC and its affiliates, will have certain rights to designate individuals for nomination to our board of directors. “Certain Relationships and Related Party Transactions — Stockholders’ Agreement” contains additional information regarding these risks. As a result, we expect to be a controlled company within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

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

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

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the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

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there be an annual performance evaluation of the nominating and governance and compensation committees.

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These requirements will not apply to us as long as we remain a controlled company. Following this offering, we may utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. “Management — Controlled Company” contains additional information regarding these risks.

Banpu’s interests, including interests in certain corporate opportunities, may conflict with our interests and the interests of our other stockholders. Conflicts of interest between us and Banpu could be resolved in a manner unfavorable to us and our other stockholders.

Banpu could have interests that differ from, or conflict with, the interests of our other stockholders and could cause us to take certain actions even if the actions are not favorable to us or our other stockholders or are opposed by our other stockholders. Potential conflicts of interest or disputes may arise between Banpu and us in a number of areas relating to our past or ongoing relationships, including:

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tax, employee benefits, indemnification and other matters arising from this offering;

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employee retention and recruiting;

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corporate opportunities that may be attractive to both Banpu and us;

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the arrangements governing the BKV-BPP Power Joint Venture and any other new commercial arrangements between the Company and affiliates of Banpu in the future; and

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sales or other disposals by Banpu of all or a portion of its interest in us.

We may not be able to resolve potential conflicts and disputes with Banpu and even if we do, the resolution may be less favorable to us than if we were dealing with an unaffiliated third party. Because we are controlled or significantly influenced by Banpu, we may not have the leverage to negotiate amendments to the arrangements governing the BKV-BPP Power Joint Venture (if any are required) on terms as favorable to us as those we would negotiate with an unaffiliated third party.

Additionally, there can be no assurance that Banpu will not engage in competition with us in the future. Our certificate of incorporation provides that, to the fullest extent permitted by law, neither Banpu nor its affiliates or any director who is not employed by us (including any non-employee director who serves as one of our officers in both his or her director and officer capacities) or his or her affiliates will have any duty to refrain from (i) engaging in the same or similar business activities or lines of business in which we or our affiliates now engage or propose to engage or (ii) otherwise competing with us or our affiliates. In addition, to the fullest extent permitted by law, in the event that Banpu or its affiliates or any non-employee director acquires knowledge of a potential transaction or other business opportunity that may be a corporate opportunity for itself, himself or herself or its or his or her affiliates or for us or any of our affiliates, such person will have no duty to communicate or offer such transaction or business opportunity to us or any of our affiliates and they may take any such opportunity for themselves or offer it to another person or entity.

Our certificate of incorporation also renounces, to the fullest extent permitted by law, any interest or expectancy that we have in, or right to be offered an opportunity to participate in, specified business opportunities that are from time to time presented to our officers, directors or stockholders or their respective affiliates, other than those officers, directors, stockholders or affiliates who are our or our subsidiaries’ employees.

Generally, neither Banpu nor our non-employee directors who also are directors, officers, employees, agents or affiliates of Banpu or its affiliates (other than us) will be liable to us or our stockholders for breach of any fiduciary duty solely by reason of the fact that any such person pursues or acquires any corporate opportunity for, or recommends or transfer any corporation opportunity to, Banpu or its affiliates (other than us), rather than to us. This renunciation will not extend to corporate opportunities expressly offered to one of our non-employee directors solely in his or her capacity as our director or officer.

These provisions create the possibility that a corporate opportunity of our Company may be used for the benefit of Banpu and may significantly impair our ability to grow.

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Certain of our directors may have actual or potential conflicts of interest because of their positions with Banpu and/or their ownership of common stock or equity awards in Banpu.

Following this offering, six of our directors will be employees of Banpu or its affiliates. In addition, such directors may own capital stock or equity awards in Banpu. For certain of these individuals, their holdings of common stock or equity awards in Banpu may be significant compared to their total assets. Their position at Banpu or its affiliates and the ownership of capital stock or equity awards in Banpu creates, or may create the appearance of, conflicts of interest when these directors and officers are faced with decisions that could have different implications for Banpu than for us. These decisions could include:

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corporate opportunities;

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the impact that operating or capital decisions (including the incurrence of indebtedness) relating to our business may have on Banpu’s consolidated financial statements or current or future indebtedness (including related covenants);

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business combinations involving us;

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our dividend and stock repurchase policies;

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compensation and benefit programs and other human resources policy decisions;

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management stock ownership;

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the payment of dividends on our common stock; and

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determinations with respect to our tax returns.

As a result of these actual or apparent conflicts of interest, we may be precluded from pursuing certain growth initiatives or transactions that may be favorable to us or we may take certain actions even if the actions are not favorable to us or are opposed by our stockholders.

If Banpu experiences a change in control, you may not realize any change-of-control premium on shares of our common stock and we may become subject to the control of a presently unknown third party. Further, Banpu may sell, or pledge as collateral for its existing or future indebtedness, the shares of our common stock that it owns.

After this offering, Banpu will own approximately    % of our outstanding common stock (or approximately    % if the underwriters exercise in full their option to purchase additional shares). Subject to the provisions of the lock-up agreement entered into in connection with this offering, Banpu will not be restricted from selling some or all of its shares of our common stock in a privately negotiated transaction or otherwise, and a sale of its shares, if sufficient in size, could result in a change of control of our Company. Further, Banpu will not be restricted from pledging as collateral for its indebtedness the shares of our common stock held by it.

The ability of Banpu to sell its shares of our common stock, with no requirement for a concurrent offer to be made to acquire all of the shares of our common stock held by our other stockholders, could prevent you from realizing any change-of-control premium on your shares of our common stock that may otherwise accrue to Banpu on its sale of our common stock. In addition, if Banpu were to pledge as collateral for its indebtedness the shares of our common stock held by it, and Banpu were to default under such indebtedness, the lenders thereunder could foreclose upon and sell such shares to satisfy Banpu’s obligations under such indebtedness.

Further, any acquiror or successor of all or a substantial number of Banpu’s shares of our common stock will be entitled to exercise Banpu’s voting control with respect to us. Such third party may have interests that conflict with those of our other stockholders. Any acquiror or successor to which Banpu transfers a controlling interest in us may attempt to cause us to revise or change our plans and strategies, as well as the agreements between Banpu and us described in this prospectus.

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Risks Related to the Offering and Our Common Stock

Our actual operating results and activities could differ materially from the guidance we have disclosed herein.

We have presented herein certain forecasted operating results, costs and activities, including, without limitation, our future expected drilling activity and production. Any such forward-looking guidance represents our management’s estimates as of the date hereof, is based upon a number of assumptions that are inherently uncertain and is subject to numerous business, political, economic, competitive, financial and regulatory risks, including the risks described under “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.” Many of these risks and uncertainties are beyond our control, such as declines in commodity prices and the speculative nature of estimating natural gas and NGL reserves and in projecting future rates of production. If any of these risks and uncertainties actually occur or the assumptions underlying our guidance are incorrect, our actual operating results, costs and activities may be materially and adversely different from our guidance. In addition, investors should also recognize that the reliability of any guidance diminishes the farther in the future that the data is forecast. In light of the foregoing, investors are urged to put our guidance in context and not to place undue reliance upon it.

We may not have sufficient available cash to pay any dividends on our common stock.

Holders of our common stock do not have a right to dividends on such shares unless declared or set aside for payment by our board of directors. Under Delaware law, cash dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from the corporation’s net profits for the then-current or the preceding fiscal year. Unless we operate profitably, our ability to pay dividends on our common stock would require the availability of adequate “surplus,” which is defined as the excess, if any, of net assets (total assets less total liabilities) over capital.

We may not have sufficient available cash to enable us to pay any dividends to our stockholders. The actual amount of available cash we will have to pay dividends will be reduced by the cost to fund acquisitions without issuing additional equity or debt, payments in respect of our debt instruments, other contractual obligations, operating expenses, general and administrative expenses, maintenance capital expenditures and reserves for future capital needs that our board of directors may determine are appropriate.

The payment of regular dividends on our common stock is subject to the discretion of our board of directors.

Our stockholders will have no contractual or other legal right to dividends. The payment of future dividends on our common stock will be at the discretion of our board of directors and any determination to pay dividends and the amount of any such dividends will depend on general economic and business conditions, our financial condition, capital requirements, results of operations, contractual limitations, legal, tax, regulatory and contractual restrictions and implications on the payment of dividends by us to our stockholders or by our subsidiaries to us, including the restrictions under our current and any future debt agreements, potential acquisition opportunities and the availability and desirability of financing alternatives, the need to service our indebtedness or other current and anticipated cash needs and any other factors our board of directors deem relevant. Events may occur, including a reduction in anticipated production volumes or realized prices or other events, which could materially impact the actual amount of any dividends we pay. Our board of directors will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of or increase in those reserves could result in a reduction in cash available for distribution to pay dividends on our common stock at anticipated levels. Accordingly, we may not be able to make, or may have to reduce or eliminate, the payment of dividends on our common stock, which could adversely affect the market price of our common stock. Investors are cautioned not to place undue reliance on the permanence of a dividend policy in making an investment decision.

The agreements governing our indebtedness impose restrictions on dividend payments.

The Term Loan Credit Agreement and the Revolving Credit Agreement contain, and any future debt agreement may contain, covenants that prohibit us from paying dividends on our common stock under certain circumstances. Both the Term Loan Credit Agreement and the Revolving Credit Agreement permit us to pay dividends to our stockholders only once each year and requires as a condition to any such dividend that (1) we have earned sufficient free cash flow (as defined in the Term Loan Credit Agreement), (2) our

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pro forma available cash is greater than $100.0 million and (3) our adjusted stockholders’ equity (as defined generally to mean our stockholders’ equity as determined in accordance with GAAP as of June 30 of the relevant year, adjusted to exclude certain unrealized earnout obligations and unrealized gains or losses resulting from hedging agreements and the application of the applicable accounting standard for the hedging instruments) is not less than $800.0 million. There can be no assurance that we will generate sufficient cash flow to permit us to pay dividends in compliance with the Term Loan Credit Agreement, the Revolving Credit Agreement or any other debt agreement.

Restrictions on distributions to us by our subsidiaries and affiliates under agreements governing their future indebtedness could limit our ability to pay dividends to holders of our common stock. These agreements contain financial tests and covenants that our subsidiaries and affiliates must satisfy prior to making distributions. If any of our subsidiaries or affiliates is unable to satisfy these restrictions or is otherwise in default under such agreements, it would be prohibited from making distributions to us that could, in turn, limit our ability to pay dividends to holders of our common stock.

The amount of our quarterly cash dividends, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business.

Investors who are looking for an investment that will pay regular and predictable quarterly dividends should not invest in our common stock. Our future business performance may be volatile and our cash flows may be unstable and we do not intend to maintain excess dividend coverage for the purpose of maintaining stability or growth in our dividends nor do we intend to reserve cash for dividends in future periods or incur debt to pay dividends. Because our dividends will be dependent upon the amount of cash we generate each quarter after payment of our fixed and variable expenses and after reserves for (i) debt service and other contractual obligations and fixed charges and (ii) future operating and capital needs, any future quarterly dividends paid to our stockholders will vary significantly from quarter to quarter, and may be zero, and our stockholders have no contractual or other legal right to dividends. See “Dividend Policy.”

Our board of directors will initially adopt a policy to pay dividends to our stockholders, which could limit our ability to grow and make acquisitions.

As a result of our dividend policy, we will have limited cash available to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions. As such, to the extent we are unable to finance growth externally, our dividend policy may significantly impair our ability to grow.

To the extent we issue additional shares of common stock in connection with any acquisitions or as in-kind dividends, the payment of dividends on those additional shares of common stock may increase the risk that we will be unable to maintain or increase our per share dividend level. The incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our stockholders.

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes- Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

Upon becoming a public company, we will be required to comply with new laws, regulations and requirements, certain corporate governance provisions of Sarbanes-Oxley Act, related regulations of the SEC and the requirements of the NYSE, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of our time and will significantly increase our costs and expenses. We will need to:

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institute a more comprehensive compliance function to test and conclude on the sufficiency of our internal control over financial reporting;

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comply with rules promulgated by the NYSE;

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prepare and distribute periodic public reports;

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•

establish new internal policies, such as those relating to insider trading; and

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involve and retain to a greater degree outside professionals in the above activities.

Furthermore, while we generally must comply with Section 404 of the Sarbanes-Oxley Act, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal control over financial reporting until our first annual report subsequent to our ceasing to be an “emerging growth company.” We may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal control over financial reporting until as late as our annual report for the year ending December 31, 2028. At any time, we may conclude that our internal controls, once tested, are not operating as designed or that the system of internal controls does not address all relevant financial statement risks. Once required to attest to the effectiveness of our internal control over financial reporting, our independent registered public accounting firm may issue a report that concludes it does not believe our internal control over financial reporting is effective. Compliance with Sarbanes-Oxley Act requirements may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we will be subject to significant regulatory oversight and reporting obligations under U.S. federal securities laws and the continuous scrutiny of securities analysts and investors. In addition, most members of our management team have limited experience managing a public company, interacting with public company investors, and complying with the increasingly complex laws pertaining to public companies. Our management team may not successfully or efficiently manage us as a public company. These new obligations and constituents require significant attention from our management team and could divert our management team’s attention away from the day-to-day management of our business, which could adversely affect our business, results of operations and financial condition.

Further, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

We have identified material weaknesses in our internal control over financial reporting and may identify additional material weaknesses in the future, or otherwise fail to maintain effective internal controls over financial reporting, which could result in a restatement of our financial statements or cause us to fail to meet our reporting obligations.

We have identified several material weaknesses in our internal control over financial reporting as of December 31, 2021, as described below. A “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

We did not design and maintain effective controls to communicate relevant information among departments to completely and accurately record and disclose transactions in the financial statements. This material weakness contributed to two additional material weaknesses in our internal controls. We did not design and maintain effective controls related to (i) the accounting for stock awards and common stock with certain put rights, including the value and classification of such arrangements, and (ii) the communication and evaluation of terms and conditions set forth in complex contracts, including certain of our commodity derivative contracts, relevant to our compliance with financial covenants and related disclosures.

Finally, we did not design and maintain effective controls related to the accounting for income taxes, which were not designed at a sufficient level of precision or rigor to prepare and review the tax rate reconciliation, return to provision, income tax provision, related income tax assets and liabilities, and disclosures in the consolidated financial statements, which also resulted in a material weakness in our internal control over financial reporting.

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The material weaknesses described above resulted in audit adjustments to share capital and other mezzanine equity accounts, liquidity disclosures, income tax benefit, income taxes payable to related party and deferred tax assets. Additionally, each of the material weaknesses described above could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.

We have begun to take steps towards remediating these material weaknesses primarily by designing and implementing additional internal controls, including those related to (i) the communication of relevant information across departments, (ii) the valuation and classification of stock awards and common stock with certain put rights, (iii) the communication and evaluation of terms and conditions included in complex contracts relevant to our compliance with financial covenants and related disclosures, and (iv) the preparation and review of the income tax rate reconciliation, return to provision, income tax provision, related income tax assets and liabilities, and income tax disclosures. Although we believe we are addressing the internal control deficiencies that led to the material weaknesses, the measures we have taken, and plan to take, may not be effective.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate control over financial reporting in the future, or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act.

We cannot assure you that we have identified all, or that we will not in the future have additional, material weaknesses. Material weaknesses may still exist when we report on the effectiveness of our internal control over financial reporting as required by reporting requirements under Section 404 of the Sarbanes-Oxley Act after the completion of this offering. If material weaknesses emerge related to financial reporting, we encounter difficulties in implementing or improving our internal controls or we otherwise fail to develop and maintain effective internal control over financial reporting, our reputation and operating results could be harmed, we could fail to meet our reporting obligations, or we may have a restatement of our financial statements. Ineffective internal control over financial reporting could also cause current and potential investors to lose confidence in our reported financial information, which would harm our business and likely have a negative effect on the trading price of our shares of common stock.

There is no existing market for our common stock, and we do not know if one will develop.

Prior to this offering, there has not been a public market for our common stock. We cannot predict the extent to which investor interest in the Company will lead to the development of an active trading market on the stock exchange on which we list our common stock or otherwise or how liquid that market might become. If an active trading market does not develop, anyone purchasing our common stock may have difficulty selling it. The initial public offering price for the common stock was determined by negotiations between us and the representatives of the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, purchasers of our common stock may be unable to sell it at prices equal to or greater than the price paid.

The following factors could affect our stock price:

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quarterly variations in our financial and operating results;

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public reaction to our press releases, our other public announcements and our filings with the SEC;

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strategic actions by our competitors;

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changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

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speculation in the press or investment community;

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the failure of research analysts to cover our common stock;

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sales of our common stock by us or our stockholders, or the perception that such sales may occur;

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•

changes in accounting principles, policies, guidance interpretations or standards;

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additions or departures of key management personnel;

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actions by our stockholders;

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general market conditions, including, among other things, fluctuations in commodity prices;

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domestic and international political, economic, legal and regulatory factors unrelated to our performance; and

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the realization of any risks described in this “Risk Factors” section.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

Our governing documents, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock. The existence of significant stockholders, such as Banpu, may have similar effects.

Some provisions of our governing documents could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

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providing for a classified board of directors;

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limitations on the removal of directors;

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limitations on the ability of our stockholders to call special meetings;

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establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;

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the requirement that the affirmative vote of the holders of at least 662∕3% in voting power of all the then-outstanding shares of our stock be obtained to amend and restate our existing bylaws or to remove directors;

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the requirement that the affirmative vote of the holders of at least 662∕3% in voting power of all the then-outstanding shares of our stock (or, if approved by at least 60% of our board of directors, a majority in voting power of all the then-outstanding shares of our stock) be obtained to amend our certificate of incorporation; and

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providing that the board of directors is expressly authorized to make, repeal, alter, amend and rescind our bylaws.

In addition, the existence of significant stockholders, such as Banpu, may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of the Company. Moreover, Banpu’s concentration of stock ownership in us may adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with a significant stockholder.

Investors in this offering will experience immediate and substantial dilution of $      per share.

Based on an assumed initial public offering price of $      per share (the midpoint of the price range set forth on the cover of this prospectus), purchasers of our common stock in this offering will experience an immediate and substantial dilution of $      per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of June 30, 2022 on a pro forma basis would be $      per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. “Dilution” contains additional information.

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Future sales of our common stock in the public market, or the perception that such sales may occur, could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may issue additional shares of common stock or convertible securities in subsequent public offerings. After the completion of this offering, assuming the underwriters’ option to purchase additional shares is fully exercised, we will have                 outstanding shares of common stock. This number includes                 shares of common stock that we are selling in this offering and         shares of common stock that we may sell in this offering if the underwriters’ option to purchase additional shares is fully exercised, which may be resold immediately in the public market. Immediately following the completion of this offering, Banpu will own       shares of common stock, representing approximately    % of our total outstanding common stock (or    % if the underwriters’ option to purchase additional shares is exercised in full) and management, directors and other employee and non-employee stockholders, collectively, will own        shares of common stock, representing approximately    % of our total outstanding common stock (or    % if the underwriters’ option to purchase additional shares is exercised in full). All such shares are restricted from immediate resale under the federal securities laws and all such shares are subject to the lock-up agreements between such parties and the underwriters described in “Underwriting” but may be sold into the market in the future.

Our Stockholders’ Agreement will provide BNAC and its affiliates with the right, in certain circumstances, to require us to register their shares of our common stock constituting registrable securities under the Securities Act for sale into the public markets at any time following the date that is six months after the consummation of this offering. “Shares Eligible for Future Sale” and “Certain Relationships and Related Party Transactions — Registration Rights” contain additional information regarding such rights.

In addition, in connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of                 shares of our common stock issued or reserved for issuance under our equity incentive plans. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition or shares owned by Banpu and such other stockholders), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

Our common stock will not be entitled to preemptive rights to buy shares from us. As a result, stockholders will not have the automatic ability to avoid dilution in their percentage ownership of us.

Terms of subsequent financings may adversely impact stockholder equity.

If we raise more equity capital from the sale of common stock, institutional or other investors may negotiate terms more favorable than the current prices of our common stock. If we issue debt securities, the holders of the debt would have a claim to our assets that would be prior to the rights of stockholders until the debt is paid. Interest on these debt securities would increase costs and could negatively impact our operating results.

In accordance with Delaware law and the provisions of our certificate of incorporation, we may issue one or more classes or series of preferred stock that ranks senior in right of dividends, liquidation or voting to our common stock. Preferred stock may have such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine, and the issuance of preferred stock would dilute the ownership of our existing stockholders. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock. The terms of any series of preferred stock may also reduce or eliminate the amount of cash available for payment of dividends

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to our holders of common stock or subordinate the claims of our holders of common stock to our assets in the event of our liquidation. Our common stock will not be subject to conversion, redemption or sinking fund provisions.

The representatives of the underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

We, Banpu and all of our directors and executive officers have entered into lock-up agreements with respect to their ownership of our common stock, pursuant to which we and they are subject to certain resale restrictions for a period of 180 days following the effectiveness date of the registration statement of which this prospectus forms a part. The representatives of the underwriters, at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then common stock will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital. “Underwriting” provides additional information regarding the lock-up agreements.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of the Company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover the Company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

Our certificate of incorporation will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our certificate of incorporation will provide that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by law, be the sole and exclusive forum for any (i) derivative action or proceeding brought on behalf of the Company, (ii) action asserting a claim of breach of a fiduciary duty owed by any director, officer or employee of the Company to the Company or our stockholders, (iii) action asserting a claim against the Company or any director or officer of the Company arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”) or our governing documents, or (iv) action asserting a claim against the Company or any director, officer or employee of the Company, which claim is governed by the internal affairs doctrine. Notwithstanding the foregoing sentence, the federal district courts of the United States of America shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under U.S. federal securities laws, including the Securities Act and the Exchange Act. This choice of forum may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our governing documents inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenue and losses, projected costs, prospects, plans and objectives of management and dividend policy are forward-looking statements. When used in this prospectus, words such as “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “seek,” “envision,” “forecast,” “target,” “predict,” “may,” “should,” “would,” “could,” “will,” the negative of these term and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors.” These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about, among other things:

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our business strategy;

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our reserves;

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

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our relationship with Banpu, including future agreements with Banpu;

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estimated natural gas, NGL and oil prices;

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our dividend policy;

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the timing and amount of future production of natural gas, NGL and oil;

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our hedging strategy and results;

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our drilling plans;

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competition and government regulation;

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legal, regulatory or environmental matters;

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marketing of natural gas, NGL and oil;

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business or leasehold acquisitions and integration of acquired businesses;

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our ability to develop existing prospects;

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costs of developing our properties and of conducting our operations;

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

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

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our CCUS business;

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our anticipated Scope 1, Scope 2 and Scope 3 emissions from our owned and operated upstream businesses and our plans to offset our Scope 1, Scope 2 and Scope 3 emissions in our owned and operated upstream business;

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the impact of the COVID-19 pandemic and its effects on our business and financial condition;

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general economic conditions;

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cost inflation;

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credit markets;

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our ability to service our indebtedness;

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•

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

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our future operating results;

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the remediation of our material weaknesses; and

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our plans, objectives, expectations and intentions.

The forward-looking statements included in this prospectus are based on current expectations and involve numerous risks and uncertainties, most of which are difficult or impossible to predict and many of which are beyond our control, incident to the exploration for and development, production and sale of natural gas, NGLs and oil. Assumptions relating to these forward-looking statements involve judgments, risks and uncertainties with respect to, among other things, market factors (including competition and inflation), market prices (including geographic basis differentials) of natural gas, NGLs and oil, results of future drilling and marketing activity, future production and costs (including availability of drilling and production equipment and services), legislative and regulatory initiatives, electronic, cyber or physical security breaches, drilling and other operating risks, environmental risks (including weather-related events), future business decisions, the uncertainty inherent in estimating natural gas, NGL and oil reserves and the other risks described under “Risk Factors.”

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.

Although we believe that the assumptions underlying these forward-looking statements are reasonable, should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, actual outcomes and our results and financial condition may differ materially from those indicated in any forward-looking statements. In light of the significant uncertainties inherent in these forward-looking statements, the inclusion of such information should not be regarded as a representation by us or any other person that our objectives and plans will be achieved.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

All forward-looking statements, expressed or implied, in this prospectus are based only on information currently available to us and speak only as of the date on which they are made. Except as otherwise required by applicable law, we disclaim any duty to publicly update any forward-looking statement, each of which is expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

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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).

Each $1.00 increase (decrease) in the assumed initial public offering price of $      per share (the midpoint of the price range set forth on the cover page of this prospectus) would increase (decrease) the net proceeds to us from this offering by $      million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting underwriting discounts and commissions and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. Each increase (decrease) of 1.0 million shares in the number of shares we are offering would increase (decrease) the net proceeds to us from this offering by $      million, assuming that the assumed initial public offering price of $      per share (the midpoint of the price range set forth on the cover page of this prospectus) remains the same, and after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

Of the net proceeds we receive from the sale of our common stock in this offering, we intend to use approximately $       million to fund the expansion of our CCUS business, $       million in contingent consideration payments to be paid in 2023 with respect to the Devon Barnett Acquisition (as described in Note 15 — Commitments and Contingencies to our audited consolidated financial statements included elsewhere in this prospectus) and the remainder for other general corporate purposes.

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DIVIDEND POLICY

We currently do not pay a fixed cash dividend to holders of our common stock. Although we will not be required by any law, our certificate of incorporation or our bylaws to pay dividends, at or prior to the closing of this offering, our board of directors will adopt a written policy pursuant to which we intend to pay to stockholders, subject to the factors described below, including the restrictions under the Term Loan Credit Agreement and the Revolving Credit Agreement, quarterly cash dividends and to consider the payment of additional special dividends from time to time.

Subject to the sole discretion of our board of directors and the considerations discussed below, we intend to pay dividends out of cash flows from operations to the extent available, and our stockholders have no contractual or other legal right to dividends.

Any determination to declare and pay a regular or special dividend, as well as the amount of any such dividends, will depend on our board of directors’ consideration of general economic and business conditions, our financial condition and results of operations, capital requirements, restrictions under our indebtedness, potential acquisition opportunities and other current and anticipated cash needs and any other factors our board of directors deems relevant. Events may occur, including a reduction in anticipated production volumes or realized prices or other events, which could materially impact the actual amount of any dividends we pay. In addition, our board of directors may be required to, or may elect to, reduce, or eliminate our dividends during periods of reduced prices or demand for oil and natural gas, among other reasons.

Our dividend policy may change from time to time, and there can be no assurance that we will declare any regular or special cash dividends at all or in any particular amounts.

Each of the Term Loan Credit Agreement and the Revolving Credit Agreement permits us to pay dividends to our stockholders only once each year and requires as a condition to any such dividend that (1) we have earned sufficient free cash flow (as defined in the Term Loan Credit Agreement and the Revolving Credit Agreement), (2) our pro forma available cash is greater than $100.0 million and (3) our adjusted stockholders’ equity (as defined generally to mean our stockholders’ equity as determined in accordance with GAAP as of June 30 of the relevant year, adjusted to exclude certain unrealized earnout obligations and unrealized gains or losses resulting from hedging agreements and the application of the applicable accounting standard for the hedging instruments) is not less than $800.0 million.

84

CAPITALIZATION

The following table shows our capitalization as of June 30, 2022:

•

on an actual basis; and

•

on an as adjusted basis, after giving effect to the sale of        shares of our common stock in this offering (which assumes that the underwriters do not exercise their option to purchase additional shares), at an assumed initial public offering price of $       per share (the midpoint of the price range set forth on the cover page of this prospectus) and our receipt of the estimated net proceeds of this offering and after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

The as adjusted information set forth in the table below is illustrative only and will adjust based on the actual initial public offering price and other terms of this offering determined when the initial public offering price is determined. You should read the following table together with “Prospectus Summary — Summary Historical Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Prospectus Summary — Summary Reserve, Production and Operating Data,” and our historical consolidated financial statements and the related notes thereto included elsewhere in this prospectus.

​	As of June 30, 2022
​	Actual			As Adjusted
​	(In thousands except share and per share data)
Cash and cash equivalents, including restricted cash(1)	​	$	186,634	​	$
Debt:	​	​	​	​	​	​
Notes payable to related party(2)	​	$	191,000	​	$
Term Loan Credit Agreement	​	​	570,000	​	​	​
Credit facilities	​	​	30,000	​	​	​
Total debt(3)	​	$	791,000	​	$
Mezzanine equity(4):	​	​	​	​	​	​
Common stock – minority ownership puttable shares	​	$	71,286	​	$	​
Equity-based compensation	​	​	81,577	​	​	​
Total mezzanine equity	​	$	152,863	​	$	​
Stockholders’ equity:	​	​	​	​	​	​
Common stock, par value $0.01 per share: 300,000,000 authorized shares, 116,861,364 shares issued and outstanding, actual; and         shares authorized,        shares issued and outstanding, as adjusted(5)	​	$	1,132	​	$
Treasury stock, shares at cost: 385,000 shares	​	​	(3,970)	​	​	​
Additional paid-in capital	​	​	883,766	​	​	​
Accumulated deficit	​	​	(179,393)	​	​	​
Total stockholders’ equity	​	$	701,535	​	$
Total capitalization	​	$	1,645,398	​	$	​

(1)

Includes approximately $17.5 million of restricted cash, which represents cash borrowed as of June 30, 2022 under the Term Loan Credit Agreement which can only be used for costs related to the Exxon Barnett Acquisition. We anticipate the restricted cash will be used for remaining transaction and integration costs related to the Exxon Barnett Acquisition.

85

(2)

Represents term loans under the $116 Million Loan Agreement and the $75 Million Loan Agreement (each as defined herein) with BNAC. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Loan Agreements and Credit Facilities.”

(3)

As of October 19, 2022, our debt consisted of (i) $75.0 million in aggregate principal amount under the Subordinated Intercompany Loan Agreements, (ii) $570.0 million in aggregate principal amount under the Term Loan Credit Agreement, which excludes $6.6 million of debt issuance costs, (iii) $45.0 million in aggregate principal amount under our OCBC Credit Facility, (iv) $10.0 million in aggregate principal amount under our SCB Credit Facility and (v) $45.0 million in aggregate principal amount under our Revolving Credit Agreement.

(4)

Holders of certain minority ownership shares of our common stock, shares of our common stock issued as stock compensation and shares of common stock purchased through our employee stock purchase program have the right, at their respective option, to require the Company to repurchase the shares upon the occurrence of certain events. As a result, the fair value of these common shares are recognized within mezzanine equity in our consolidated balance sheets. In connection with the closing of this offering, the put rights with respect to these shares will be terminated and the related shares of common stock will be reclassified as permanent equity.

(5)

The number of shares of our common stock issued and outstanding on an as adjusted basis assumes that the underwriters will not exercise their option to purchase additional shares. If the underwriters exercise in full their option to purchase additional shares, as adjusted cash and cash equivalents, additional paid-in capital, total stockholders’ equity, total capitalization and shares of common stock outstanding as of June 30, 2022 would have been $     , $     , $     , $     , and $     , respectively.

The number of shares of our common stock set forth in the table above excludes an aggregate of        additional shares of our common stock reserved for future awards pursuant to the 2022 Plan, including        shares of common stock that may be issued upon vesting of outstanding equity awards, and        shares of our common stock available for purchase by employees pursuant to the ESPP.

86

DILUTION

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of June 30, 2022 was $      million, or $      per share. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of shares of common stock that will be outstanding immediately prior to the closing of this offering. After giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as of June 30, 2022 would have been approximately $      million, or $      per share. This represents an immediate increase in the net tangible book value of $      per share to our existing stockholders and an immediate dilution (i.e., the difference between the initial public offering price per share of our common stock and the adjusted pro forma net tangible book value per share of our common stock after this offering) to new investors purchasing shares of common stock in this offering of $      per share.

The following table illustrates the per share dilution to new investors purchasing shares of common stock in this offering:

Assumed initial public offering price per share	​	​	$
Pro forma net tangible book value per share as of June 30, 2022	$		​	​
Increase in pro forma net tangible book value per share attributable to new investors in this offering	​	​	​	​
Less: As adjusted pro forma net tangible book value per share of common stock after giving effect to this offering	​	​	​	​
Dilution in pro forma net tangible book value per share to new investors from this offering	​	​	$	​

A $1.00 increase (decrease) in the assumed initial public offering price of $      per share (the midpoint of the price range set forth on the cover page of this prospectus), would increase (decrease) the as adjusted net tangible book value per share after this offering by $      per share and increase (decrease) the dilution in pro forma net tangible book value per share to new investors in this offering by $      per share, in each case assuming the number of shares of common stock offered by us, as set forth on the cover page of this prospectus, remains the same and less estimated underwriting discounts and commissions and estimated offering expenses payable by us (and if the underwriters exercise in full their option to purchase additional shares, the as adjusted net tangible book value per share would be $      per share, and the dilution in pro forma net tangible book value per share to new investors in this offering would be $      per share).

The above table and related discussion are based on the number of shares of our common stock to be outstanding as of the closing of this offering. The above table and related discussion exclude an aggregate of additional shares of our common stock reserved for future awards pursuant to the 2022 Plan and            additional shares reserved to be available for purchase by employees pursuant to the ESPP.

87

UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

On June 30, 2022, the Company closed the Exxon Barnett Acquisition pursuant to which it acquired certain natural gas upstream assets and associated midstream infrastructure in the Barnett (the “2022 Barnett Assets”) from XTO Energy, Inc. and Barnett Gathering LLC, subsidiaries of Exxon Mobil Corporation, for an adjusted cash purchase price of $627.5 million, plus additional contingent consideration of up to $50.0 million depending on future natural gas prices. In connection with the Exxon Barnett Acquisition, the Company entered into a Term Loan Credit Agreement with a syndicate of banks and Bangkok Bank Public Company Limited (New York Branch), as the administrative agent. On June 30, 2022, the Company borrowed $570.0 million of term loans under the Term Loan Credit Agreement to fund a portion of the purchase price and other costs and expenses associated with the Exxon Barnett Acquisition. Additionally, in March 2022, the Company borrowed $75.0 million under a Loan Agreement (the “$75 Million Loan Agreement”) with Banpu North America Corporation (“BNAC”), which owns 96.1% of the Company’s shares of common stock, to fund the deposit for the Exxon Barnett Acquisition.

The following unaudited pro forma condensed combined consolidated financial statements (the “pro forma financial statements”) present the combination of the historical condensed 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 (collectively the “Transaction”). 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 June 30, 2022, together with the related indebtedness under the Term Loan Credit Agreement and the $75 Million Loan Agreement, and no pro forma balance sheet is presented. The unaudited pro forma condensed combined consolidated statements of operations (the “pro forma statements of operations”) present the historical audited consolidated statements of operations of the Company for the year ended December 31, 2021 and the historical unaudited condensed consolidated statements of operations of the Company for the six months ended June 30, 2022, in each case, after giving effect to the Transaction as if it had been consummated on January 1, 2021.

The pro forma financial statements were prepared in accordance with Article 11 of Regulation S-X under the Securities Act. The unaudited pro forma adjustments reflecting the Exxon Barnett Acquisition have been prepared in accordance with the acquisition method of accounting in accordance with FASB ASC Topic 805, Business Combinations, which requires all assets acquired and liabilities assumed to be recorded at fair value at the acquisition date. The purchase price adjustments recorded on June 30, 2022 are preliminary and are subject to change as additional information becomes available and as additional analysis is performed. For more information on the fair value of assets acquired and liabilities assumed see “BKV Corporation Unaudited Condensed Consolidated Financial Statements.” Upon consummation of the Transaction, management did not identify any differences in accounting policies that would have a material impact on the pro forma financial statements.

Certain of the historical amounts with respect to the 2022 Barnett Assets have been reclassified to conform to the Company’s financial statement presentation.

Assumptions and estimates underlying the pro forma adjustments are described in the accompanying notes, which should be read in conjunction with the pro forma financial statements. In the Company’s opinion, all adjustments that are necessary to present fairly the pro forma information have been made.

The pro forma financial statements are provided for illustrative purposes only and are not intended to represent what the Company’s financial position or results of operations would have been had the Transaction occurred on the assumed date nor do they purport to project the future operating results or the financial position of the Company following the Transaction. The pro forma financial statements do not reflect projected synergies or future events that may occur after the Transaction, including, but not limited to, the anticipated realization of savings from potential operating efficiencies, asset dispositions, cost savings, or economies of scale that the Company may achieve as a result of the Transaction or the costs that may be necessary to incur in order to achieve such synergies or savings.

The pro forma adjustments reflecting the consummation of the Transaction are based on certain currently available information and certain assumptions and methodologies that the Company believes are

88

reasonable under the circumstances. The pro forma adjustments, which are described in the accompanying notes, may be revised as additional information becomes available and is evaluated. Therefore, it is likely that the actual results will differ from the pro forma adjustments and it is possible the difference may be material. The Company believes that its assumptions and methodologies provide a reasonable basis for presenting all of the significant effects of the Transaction based on information available to management at this time and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma condensed combined consolidated financial information.

Additionally, the Company cannot assure that it will not incur charges in excess of those included in the pro forma total consideration related to the Transaction or that the Company’s efforts to integrate the operations of the 2022 Barnett Assets will be successful.

The pro forma financial statements should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” as well as the Company’s 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 elsewhere in this prospectus. Historical and pro forma results are not necessarily indicative of results that may be expected for any future period.

89

BKV CORPORATION

UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED STATEMENT OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 2022
(in thousands, except per share amounts)

​

BKV Corporation Historical

2022 Barnett Assets Historical

Transaction Accounting Adjustments(1)

​

Financing Adjustments

​

Pro Forma Combined

​

Revenues and other operating income / Revenues

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas, NGL and oil sales

​

$

656,431

​

$

—

​

$

219,232

(aa)

​

$

—

​

​

$

875,663

​

Non-operated midstream revenues

​

​

3,344

​

​

—

​

​

3,621

(aa)

​

​

—

​

​

​

6,965

​

Derivative losses, net

​

​

(450,784)

​

​

—

​

​

—

​

​

​

—

​

​

​

(450,784)

​

Marketing revenues

​

​

5,328

​

​

—

​

​

—

​

​

​

—

​

​

​

5,328

​

Other

​

​

1,327

​

​

—

​

​

248

(aa)

​

​

—

​

​

​

1,575

​

Oil and condensate, gas and NGL sales

​

​

—

​

​

219,232

​

​

(219,232)

(aa)

​

​

—

​

​

​

—

​

Midstream operating revenues

​

​

—

​

​

3,621

​

​

(3,621)

(aa)

​

​

—

​

​

​

—

​

Other revenues

​

​

—

​

​

248

​

​

(248)

(aa)

​

​

—

​

​

​

—

​

Total revenues and other operating income / Total revenues

​

​

215,646

​

​

223,101

​

​

—

​

​

​

—

​

​

​

438,747

​

Operating expenses / Direct operating expenses

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Lease operating and workover

​

​

45,333

​

​

—

​

​

58,176

(aa)

​

​

—

​

​

​

103,509

​

Taxes other than income

​

​

41,001

​

​

—

​

​

10,696

(aa)

​

​

—

​

​

​

51,697

​

Gathering and transportation

​

​

98,756

​

​

—

​

​

25,321

(aa)

​

​

—

​

​

​

124,077

​

Accretion of asset retirement obligation

​

​

5,320

​

​

—

​

​

1,773

(dd)

​

​

—

​

​

​

7,093

​

Depreciation, depletion and amortization

​

​

36,800

​

​

—

​

​

24,642

(cc)

​

​

—

​

​

​

61,442

​

General and administrative

​

​

51,497

​

​

—

​

​

—

​

​

​

—

​

​

​

51,497

​

Accretion of right of use liabilities

​

​

135

​

​

—

​

​

—

​

​

​

—

​

​

​

135

​

Lease operating expense

​

​

—

​

​

47,456

​

​

(47,456)

(aa)

​

​

—

​

​

​

—

​

Overhead costs

​

​

—

​

​

10,720

​

​

(10,720)

(aa)

​

​

—

​

​

​

—

​

Cost of goods sold

​

​

—

​

​

25,321

​

​

(25,321)

(aa)

​

​

—

​

​

​

—

​

Production and property taxes

​

​

—

​

​

10,696

​

​

(10,696)

(aa)

​

​

—

​

​

​

—

​

Total operating expenses / Total direct operating expenses

​

​

278,842

​

​

94,193

​

​

26,415

​

​

​

—

​

​

​

399,450

​

Income (loss) from operations / Revenues in excess of direct operating expenses

​

​

(63,196)

​

​

128,908

​

​

(26,415)

​

​

​

—

​

​

​

39,297

​

Other income and expense

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Loss on contingent consideration liabilities

​

​

(31,915)

​

​

—

​

​

—

​

​

​

—

​

​

​

(31,915)

​

Interest expense

​

​

(6,698)

​

​

—

​

​

—

​

​

​

(21,891)

(ee)

​

​

(28,589)

​

Other income

​

​

516

​

​

—

​

​

—

​

​

​

—

​

​

​

516

​

Bargain purchase gain

​

​

163,653

​

​

—

​

​

—

​

​

​

—

​

​

​

163,653

​

Gain on settlement of litigation

​

​

16,866

​

​

—

​

​

—

​

​

​

—

​

​

​

16,866

​

Loss from equity affiliates

​

​

(23,958)

​

​

—

​

​

—

​

​

​

—

​

​

​

(23,958)

​

Interest income

​

​

128

​

​

—

​

​

—

​

​

​

—

​

​

​

128

​

Income (loss) from continuing operations before income taxes

​

​

55,396

​

​

128,908

​

​

(26,415)

​

​

​

(21,891)

​

​

​

135,998

​

Income tax benefit (expense)

​

​

24,903

​

​

—

​

​

(23,573)

(ff)

​

​

5,035

(gg)

​

​

6,365

​

Net income (loss) and comprehensive income (loss) attributable to BKV Corporation

​

​

80,299

​

​

128,908

​

​

(49,988)

​

​

​

(16,856)

​

​

​

142,363

​

Less accretion of preferred stock redemption value

​

​

—

​

​

—

​

​

—

​

​

​

—

​

​

​

—

​

Less preferred stock dividends

​

​

—

​

​

—

​

​

—

​

​

​

—

​

​

​

—

​

Less deemed dividend on redemption of preferred stock

​

​

—

​

​

—

​

​

—

​

​

​

—

​

​

​

—

​

Net income (loss) and comprehensive income (loss) attributable to common stockholders

​

$

80,299

​

$

128,908

​

$

(49,988)

​

​

$

(16,856)

​

​

$

142,363

​

Net income (loss) and comprehensive income (loss) per common share:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Basic

​

$

0.68

​

​

​

​

​

​

​

​

​

​

​

​

$

1.21

(hh)

Diluted

​

$

0.65

​

​

​

​

​

​

​

​

​

​

​

​

$

1.16

(hh)

Weighted average number of common shares outstanding:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Basic

​

​

117,310

​

​

​

​

​

​

​

​

​

​

​

​

​

117,310

​

Diluted

​

​

123,221

​

​

​

​

​

​

​

​

​

​

​

​

​

123,221

​

(1)

Upon consummation of the Transaction, management did not identify any differences in accounting policies that would have a material impact on the unaudited pro forma combined consolidated financial information.

90

BKV CORPORATION

UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2021
(in thousands, except per share amounts)

​

BKV Corporation Historical

2022 Barnett Assets Historical

Transaction Accounting Adjustments(1)

​

Financing Adjustments

​

Pro Forma Combined

​

Revenues and other operating income / Revenues

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas, NGL and oil sales

​

$

829,745

​

$

—

​

$

307,980

(aa)

​

$

—

​

​

$

1,137,725

​

Non-operated midstream revenues

​

​

6,917

​

​

—

​

​

6,244

(aa)

​

​

—

​

​

​

13,161

​

Derivative (losses) gains, net

​

​

(383,847)

​

​

—

​

​

—

​

​

​

—

​

​

​

(383,847)

​

Marketing revenues

​

​

52,616

​

​

—

​

​

—

​

​

​

—

​

​

​

52,616

​

Other

​

​

251

​

​

—

​

​

267

(aa)

​

​

—

​

​

​

518

​

Oil and condensate, gas and NGL sales

​

​

—

​

​

307,980

​

​

(307,980)

(aa)

​

​

—

​

​

​

—

​

Midstream operating revenues

​

​

—

​

​

6,244

​

​

(6,244)

(aa)

​

​

—

​

​

​

—

​

Other revenues

​

​

—

​

​

267

​

​

(267)

(aa)

​

​

—

​

​

​

—

​

Total revenues and other operating income / Total revenues

​

​

505,682

​

​

314,491

​

​

—

​

​

​

—

​

​

​

820,173

​

Operating expenses / Direct operating expenses

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Lease operating and workover

​

​

88,105

​

​

—

​

​

97,748

(aa)

​

​

—

​

​

​

185,853

​

Taxes other than income

​

​

45,650

​

​

—

​

​

21,667

(aa)

​

​

—

​

​

​

67,317

​

Gathering and transportation

​

​

173,587

​

​

—

​

​

49,795

(aa)

​

​

—

​

​

​

223,382

​

Accretion of asset retirement obligation

​

​

10,030

​

​

—

​

​

3,586

(dd)

​

​

—

​

​

​

13,616

​

Depreciation, depletion and amortization

​

​

81,986

​

​

—

​

​

59,732

(cc)

​

​

—

​

​

​

141,718

​

Exploration and impairment

​

​

34

​

​

—

​

​

—

​

​

​

—

​

​

​

34

​

General and administrative

​

​

85,740

​

​

—

​

​

6,800

(bb)

​

​

—

​

​

​

92,540

​

Accretion of right of use liabilities

​

​

227

​

​

—

​

​

—

​

​

​

—

​

​

​

227

​

Lease operating expense

​

​

—

​

​

76,922

​

​

(76,922)

(aa)

​

​

—

​

​

​

—

​

Overhead costs

​

​

—

​

​

20,826

​

​

(20,826)

(aa)

​

​

—

​

​

​

—

​

Cost of goods sold

​

​

—

​

​

49,795

​

​

(49,795)

(aa)

​

​

—

​

​

​

—

​

Production and property taxes

​

​

—

​

​

21,667

​

​

(21,667)

(aa)

​

​

—

​

​

​

—

​

Total operating expenses / Total direct operating expenses

​

​

485,359

​

​

169,210

​

​

70,118

​

​

​

—

​

​

​

724,687

​

Income (loss) from operations / Revenues in excess of direct operating expenses

​

​

20,323

​

​

145,281

​

​

(70,118)

​

​

​

—

​

​

​

95,486

​

Other income and expense

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

(Loss) gain on contingent consideration liabilities

​

​

(194,968)

​

​

—

​

​

—

​

​

​

—

​

​

​

(194,968)

​

Interest expense

​

​

(2,134)

​

​

—

​

​

—

​

​

​

(48,884)

(ee)

​

​

(51,018)

​

Other income

​

​

872

​

​

—

​

​

—

​

​

​

—

​

​

​

872

​

Income from equity affiliates

​

​

910

​

​

—

​

​

—

​

​

​

—

​

​

​

910

​

Interest income

​

​

8

​

​

—

​

​

—

​

​

​

—

​

​

​

8

​

Income (loss) from continuing operations before income taxes

​

​

(174,989)

​

​

145,281

​

​

(70,118)

​

​

​

(48,884)

​

​

​

(148,710)

​

Income tax benefit (expense)

​

​

40,526

​

​

—

​

​

(17,287)

(ff)

​

​

11,243

(gg)

​

​

34,482

​

Net income (loss) and comprehensive income (loss) attributable to BKV Corporation

​

​

(134,463)

​

​

145,281

​

​

(87,405)

​

​

​

(37,641)

​

​

​

(114,228)

​

Less accretion of preferred stock redemption value

​

​

(3,745)

​

​

—

​

​

—

​

​

​

—

​

​

​

(3,745)

​

Less preferred stock dividends

​

​

(9,900)

​

​

—

​

​

—

​

​

​

—

​

​

​

(9,900)

​

Less deemed dividend on redemption of preferred stock

​

​

(22,606)

​

​

—

​

​

—

​

​

​

—

​

​

​

(22,606)

​

Net income (loss) and comprehensive income (loss) attributable to common stockholders

​

$

(170,714)

​

$

145,281

​

$

(87,405)

​

​

$

(37,641)

​

​

$

(150,479)

​

Net income (loss) and comprehensive income (loss) per common share:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Basic

​

$

(1.46)

​

​

​

​

​

​

​

​

​

​

​

​

$

(1.29)

(hh)

Diluted

​

$

(1.46)

​

​

​

​

​

​

​

​

​

​

​

​

$

(1.29)

(hh)

Weighted average number of common shares outstanding:

​

​

​

​

​

​

​

​

Basic

​

​

116,904

​

​

​

​

​

​

​

​

​

​

​

​

​

116,904

​

Diluted

​

​

116,904

​

​

​

​

​

​

​

​

​

​

​

​

​

116,904

​

(1)

Upon consummation of the Transaction, management did not identify any differences in accounting policies that would have a material impact on the unaudited pro forma combined consolidated financial information.

91

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1.   Basis of Presentation

The accompanying pro forma financial information was prepared based on the historical condensed consolidated financial statements of the Company and the historical statements of revenues and direct operating expenses for the 2022 Barnett Assets acquired in the Exxon Barnett Acquisition. The pro forma financial statements were prepared in accordance with GAAP and Article 11 of Regulation S-X under the Securities Act. The Exxon Barnett Acquisition was consummated on June 30, 2022 and, therefore, the 2022 Barnett Assets are included in the historical balance sheet of the Company at fair value as of June 30, 2022, together with the related indebtedness under the Term Loan Credit Agreement and the $75 Million Loan Agreement, and no pro forma balance sheet is presented.

The estimated purchase price consideration (including contingent consideration) and the fair value of assets acquired and liabilities assumed, which are included in the historical balance sheet of the Company, are as follows (in thousands):

Cash	$	627,527
Contingent consideration	​	17,150
Total consideration	$	644,677
Assets acquired and liabilities assumed:	​	​
Inventory	​	150
Natural gas properties – developed	​	664,665
Midstream assets	​	254,813
Other property and equipment	​	8,907
Property taxes	​	(9,039)
Deferred tax liability	​	(49,789)
Revenues payable	​	(16,612)
Asset retirement obligations	​	(44,765)
Total identifiable net assets	$	808,330
Bargain purchase gain	$	(163,653)

The pro forma statements of operations present the historical audited consolidated statements of operations of the Company for the year ended December 31, 2021 and the historical unaudited condensed consolidated statements of operations for the six months ended June 30, 2022, in each case, after giving effect to the Transaction as if it had been consummated on January 1, 2021.

NOTE 2.   Adjustments to the Unaudited Pro Forma Condensed Combined Consolidated Statements of Operations

The pro forma adjustments reflected in the pro forma statements of operations are based on preliminary estimates and assumptions that are subject to change. The following adjustments have been reflected in the pro forma statements of operations:

(aa)

Certain reclassification adjustments have been made to conform historical direct revenues and operating expenses with respect to the 2022 Barnett Assets to the financial statement presentation method of the Company.

•

Reclassification of 2022 Barnett Assets historical Oil and condensate, gas and NGL sales to Natural gas, NGL and oil sales to conform with the Company’s presentation of upstream revenues.

•

Reclassification of 2022 Barnett Assets historical Midstream operating revenues to Non-operated midstream revenues to conform with the Company’s presentation of midstream revenues.

92

•

Reclassification of 2022 Barnett Assets historical Other revenues to Other to conform with the Company’s presentation of other revenues.

•

Reclassification of 2022 Barnett Assets historical Lease operating expense to Lease operating and workover to conform with the Company’s presentation of lease operating and workover expense.

•

Reclassification of 2022 Barnett Assets historical Overhead costs to Lease operating and workover to conform with the Company’s presentation of lease operating and workover expense.

•

Reclassification of 2022 Barnett Assets historical Cost of goods sold to Gathering and transportation expense to conform with the Company’s presentation of gathering and transportation expense.

•

Reclassification of 2022 Barnett Assets historical Production and property taxes to Taxes other than income to conform with the Company’s presentation of Taxes other than income.

Upon consummation of the Transaction, management did not identify any differences in accounting policies that would have a material impact on the pro forma statements of operations.

(bb)

Reflects the non-recurring transition services expense under the terms of the Transition Service Agreement, entered into between the Company and XTO Energy, Inc. in connection with the Exxon Barnett Acquisition. Under the terms of the Transition Services Agreement, XTO Energy Inc. will provide certain services to the Company to aid in the transitional period from July 1, 2022 through October 31, 2022. Services include marketing, accounting and tax, information systems, division orders/​ownership changes, compliance and land administration.

(cc)

Reflects the pro forma depreciation, depletion and amortization expense based on the preliminary purchase price allocation. The historical financial statements for the 2022 Barnett Assets did not include historical depreciation, depletion and amortization due to the abbreviated presentation. As a result, this adjustment reflects the full go forward expense related to these items based on the fair value of the assets acquired as of June 30, 2022 and the relevant remaining useful life of those assets.

Depletion for natural gas properties is calculated using the units of production method of accounting for oil and gas properties. Pro forma depletion expense for the year ended December 31, 2021 and the six months ended June 30, 2022 was $51.4 million and $20.5 million, respectively. Pro forma depletion expense for the year ended December 31, 2021 was calculated based on production volumes attributable to the natural gas properties in the 2022 Barnett Assets and the depletion rate reflecting the reserve volumes acquired.

Depreciation and amortization expense for other property and equipment is calculated using the straight line method. Pro forma depreciation and amortization expense for the year ended December 31, 2021 and the six months ended June 30, 2022 was $8.3 million and $4.1 million, respectively. The following table sets forth a listing of useful lives for other property and equipment:

​	Useful Life
Pipelines	40 years
Compressors	25 years
Buildings	39 years
Furniture, fixtures, equipment, vehicles and other	5 years
Computer hardware and software	3 – 5 years

(dd)

Reflects the pro forma accretion expense based on the preliminary purchase price allocation of the estimated fair value of the acquired proved natural gas properties included in the 2022 Barnett Assets. The present value of the estimated asset retirement obligation associated with the acquired natural gas producing properties as of June 30, 2022 is $44.8 million, which was calculated using an interest rate of 8.01%, inflation rate of 2.50% and the expected remaining useful life of each well, estimated as a range of 5 – 50 years.

(ee)

Reflects the impact of the interest expense, inclusive of debt issuance costs amortization, that would have been recognized as a result of the incurrence of $570.0 million in new debt under the Term Loan

93

Credit Agreement used to fund a portion of the purchase price for the Exxon Barnett Acquisition and other costs and expenses associated with the acquisition, as well as the issuance of the $75 Million Loan Agreement with BNAC used to fund the deposit on the Exxon Barnett Acquisition.

The term loans mature five years after their initial incurrence and require the prepayment of 20% of their original principal amount on each anniversary of their initial incurrence. Loans under the Term Loan Credit Agreement bear interest at six-month term SOFR plus a credit spread adjustment of 0.10%, plus 4.75% per annum. The interest rate used for pro forma purposes is 7.43%, based on the six-month term SOFR on June 22, 2022 (established prior to funding). Pursuant to the terms of the Term Loan Credit Agreement, the rate will be adjusted every six months. As a result, the actual interest rate could vary for the year ended December 31, 2021 and the six months ended June 30, 2022, and a one-eighth of a percent variance in the interest rate would cause a change in interest expense of approximately $0.7 million and $0.4 million, respectively.

The $75 Million Loan Agreement matures five years after the initial incurrence and requires repayment of 20% of the original principal amount on each anniversary of the initial incurrence. The $75 Million Loan Agreement bears interest at six-month term SOFR plus 5.25% per annum. The interest rate used for pro forma purposes is 5.30%, based on the six-month term SOFR on March 10, 2022 (established prior to funding). The actual interest rate could vary for the year ended December 31, 2021 and the six months ended June 30, 2022, and a one-eighth of a percent variance in the interest rate would cause a change in interest expense by an immaterial amount.

(in thousands)	Six Months Ended June 30, 2022			Year Ended December 31, 2021
Term Loan Credit Agreement	​	​	​	​	​	​
Interest expense calculated for the period	​	$	21,295	​	$	42,943
Less: Actual interest expense included in historical financial statements	​	​	(824)	​	​	—
Adjustment related to incremental interest expense(1)	​	$	20,471	​	$	42,943
$75 Million Loan Agreement	​	​	​	​	​	​
Interest expense calculated for the period	​	$	1,998	​	$	4,030
Less: Actual interest expense included in historical financial statements	​	​	(1,181)	​	​	—
Adjustment related to incremental interest expense	​	$	817	​	$	4,030

(1)

Excludes debt issuance costs amortization for the six months ended June 30, 2022 and year ended December 31, 2021 of $0.6 million and $1.9 million, respectively.

(ff)

Reflects the adjustment for the income tax provision for transaction accounting adjustments related to the six months ended June 30, 2022 and for the year ended December 31, 2021 of $23.6 million expense and $17.3 million expense, respectively. Income tax impacts of transaction accounting adjustments include adjustments to record depreciation, depletion and amortization (see adjustment (cc) above), accretion of asset retirement obligation (see adjustment (dd) above), and reflects estimated incremental income tax provision associated with the pro forma results of operations assuming the 2022 Barnett Asset’s earnings had been subject to federal and state income tax. The pro forma estimated blended statutory rate for the periods presented is 23.0%.

(gg)

Reflects the adjustment for the income tax provision for financing adjustments related to the six months ended June 30, 2022 and for the year ended December 31, 2021 of $5.0 million benefit and $11.2 million benefit, respectively. The pro forma estimated blended statutory rate used for the periods presented is 23.0%.

94

(hh)

The pro forma adjustments on the Company’s common stock and basic and diluted earnings per share are summarized below (in thousands except per share amounts):

​	Six Months Ended June 30, 2022			Year Ended December 31, 2021
Pro forma basic EPS	​			​
Numerator	​	​	​	​	​	​
Basic combined pro forma net income (loss) attributable to Company common stockholders	​	$	142,363	​	$	(150,479)
Denominator	​	​	​	​	​	​
Historical basic weighted average Company shares outstanding	​	​	117,310	​	​	116,904
Pro forma basic weighted average Company shares outstanding	​	​	117,310	​	​	116,904
Pro forma basic net income (loss) per share attributable to Company common stockholders	​	$	1.21	​	$	(1.29)
Pro forma diluted EPS	​	​	​	​	​	​
Numerator	​	​	​	​	​	​
Diluted combined pro forma net income (loss) attributable to Company common stockholders	​	$	142,363	​	$	(150,479)
Denominator	​	​	​	​	​	​
Historical diluted weighted average Company shares outstanding	​	​	123,221	​	​	116,904
Pro forma diluted weighted average Company shares outstanding	​	​	123,221	​	​	116,904
Pro forma diluted net income (loss) per share attributable to common Company stockholders	​	$	1.16	​	$	(1.29)

NOTE 3.   Supplemental Pro Forma Oil and Gas Reserves Information

Natural gas, NGL and oil reserve quantities

The Company’s estimates of total proved reserves at December 31, 2021 was based on studies performed by the Company’s internal engineering function, and Ryder Scott, the Company’s third-party reserve engineer. The estimates were computed using the 12-month average index price, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year. The estimates were prepared by the Company’s independent third party engineers, Ryder Scott. The process of estimating quantities of “proved” and “proved developed” natural gas, NGL and oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering, and economic data. The process also includes estimating the net cost of abandonment after salvage and was estimated and included for all properties for which an asset retirement obligation exists. The data may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data make these estimates generally less precise than other estimates included within the consolidated financial statements.

The estimates of proved natural gas, NGL and oil reserves from the Exxon Barnett Acquisition has been completed in accordance with professional engineering standards. The estimates also include the net cost of abandonment after salvage and was included for all properties for which an asset retirement obligation exists. The estimates of proved natural gas, NGL and oil reserves were prepared by the Company’s petroleum engineers for the year ended December 31, 2021. Those proved reserves estimates were calculated by adding back production (rolled back) and adjusting for pricing from a reserve report prepared by Ryder Scott, as of June 30, 2022.

95

The following tables present the estimated pro forma combined net proved developed and undeveloped natural gas, NGLs and oil reserves information as of December 31, 2021, along with a summary of changes in quantities of net remaining proved reserves during the year ended December 31, 2021.

The following estimated pro forma combined natural gas, NGLs and oil reserves information is not necessarily indicative of the results that might have occurred had the Transactions been completed on January 1, 2021 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected because of various factors, including those discussed in the section entitled “Risk Factors” within this prospectus.

Natural Gas, NGL and Oil Reserve Quantities

​	Natural Gas (MMcf)
​	BKV Corporation Historical		2022 Barnett Assets Historical		Pro Forma Combined
Balance December 31, 2020	​	1,985,532	​	661,897	​	2,647,429
Revision for previous estimates	​	828,360	​	359,153	​	1,187,513
Valuation revisions	​	—	​	—	​	—
Extensions and discoveries	​	645,338	​	—	​	645,338
Purchase of minerals in place	​	19,511	​	—	​	19,511
Improved recoveries	​	152,597	​	—	​	152,597
Production	​	(186,055)	​	(74,076)	​	(260,131)
Balance December 31, 2021	​	3,445,283	​	946,974	​	4,392,257
Proved developed reserves as of:	​	​	​	​	​	​
December 31, 2020	​	1,893,158	​	661,897	​	2,555,055
December 31, 2021	​	2,494,925	​	946,974	​	3,441,899
Proved undeveloped reserves as of:	​	​	​	​	​	​
December 31, 2020	​	92,374	​	—	​	92,374
December 31, 2021	​	950,358	​	—	​	950,358

​	NGL (MBbls)
​	BKV Corporation Historical		2022 Barnett Assets Historical		Pro Forma Combined
Balance December 31, 2020	​	107,234	​	12,827	​	120,061
Revision for previous estimates	​	45,234	​	6,807	​	52,041
Extensions and discoveries	​	13,722	​	—	​	13,722
Purchase of minerals in place	​	—	​	—	​	—
Improved recoveries	​	8,794	​	—	​	8,794
Production	​	(9,829)	​	(1,283)	​	(11,112)
Balance December 31, 2021	​	165,155	​	18,351	​	183,506
Proved developed reserves as of:	​	​	​	​	​	​
December 31, 2020	​	107,234	​	12,827	​	120,061
December 31, 2021	​	151,433	​	18,351	​	169,784
Proved undeveloped reserves as of:	​	​	​	​	​	​
December 31, 2020	​	—	​	—	​	—
December 31, 2021	​	58	​	—	​	58

96

​	Oil (MBbls)
​	BKV Corporation Historical		2022 Barnett Assets Historical		Pro Forma Combined
Balance December 31, 2020	​	723	​	125	​	848
Revision for previous estimates	​	258	​	77	​	335
Extensions and discoveries	​	58	​	—	​	58
Purchase of minerals in place	​	—	​	—	​	—
Improved recoveries	​	9	​	—	​	9
Production	​	(123)	​	(18)	​	(141)
Balance December 31, 2021	​	925	​	184	​	1,109
Proved developed reserves as of:	​	​	​	​	​	​
December 31, 2020	​	723	​	125	​	848
December 31, 2021	​	867	​	184	​	1,051
Proved undeveloped reserves as of:	​	​	​	​	​	​
December 31, 2020	​	—	​	—	​	—
December 31, 2021	​	13,722	​	—	​	13,722

2021 Activity

During the year ended December 31, 2021, the pro forma combined proved reserves increased by 1,808.5 Bcfe. The increase in proved reserves was primarily due to increasing commodity pricing improving economics, and additions to the drilling schedule for both proved developed and undeveloped reserves. The pro forma combined production for the year ended December 31, 2021 was 271.4 Bcfe.

Revisions of previous estimates primarily consisted of upward revisions to proved developed reserves and proved undeveloped reserves of 715.9 Bcfe and 611.6 Bcfe, respectively, as a result of higher average pricing during 2021 for natural gas, NGLs and oil. The remaining upward adjustment of 139.8 Bcfe relates to upward performance adjustments of 219.2 Bcfe offset by a downward revision of 79.4 Bcfe due to increased production costs.

Upon completing our evaluation of properties acquired through our Barnett Asset Acquisition, 550.1 Bcfe of proved undeveloped reserves was recognized for 123 gross (94.8 net) locations added to the Company’s revised drilling schedule during 2021. Additional extensions consisted of proved undeveloped reserves of 143.2 Bcfe related to 13.0 gross (9.6 net) locations in the Marcellus Basin recognized from acquired acreage and the revised 2021 drilling plan. Extensions related to proved developed reserves of 34.8 Bcfe consisted of 14 gross (5.9 net) newly drilled wells.

Improved recoveries consisted of 205.4 Bcfe of proved undeveloped reserves recognized as a result of the application of improved recovery techniques to producing wells during the year ended December 31, 2021.

Standardized Measure of Discounted Future Net Cash Flows

The following tables present the estimated pro forma discounted future net cash flows at December 31, 2021. The pro forma standardized measure information set forth below gives effect to the Transaction as if the Transaction had been completed on January 1, 2021. With respect to the disclosures below for BKV Corporation and the Exxon Barnett Acquisition, the amounts were determined by referencing the “Unaudited Supplemental Oil and Gas Disclosures” reported in BKV Corporation’s annual financial statements for the year ended December 31, 2021 and the ExxonMobil Barnett Assets statements of revenues and direct operating expenses and related notes, included in this prospectus. See “Where You Can Find More Information” within this prospectus. The calculations assume the continuation of existing economic, operating and contractual conditions at December 31, 2021.

Therefore, the following estimated pro forma standardized measure is not necessarily indicative of the results that might have occurred had the Transactions been completed on January 1, 2021 and is not intended

97

to be a projection of future results. Future results may vary significantly from the results reflected herein and because of various factors, including those discussed in the section entitled “Risk Factors” within this prospectus.

Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the year ended December 31, 2021 are as follows:

​	For the Year Ended December 31, 2021
(in thousands)	BKV Corporation Historical			2022 Barnett Assets Historical			Pro Forma Combined
Future cash inflows	​	$	15,029,839	​	$	2,724,244	​	$	17,754,083
Future production costs	​	​	(6,840,969)	​	​	(1,190,931)	​	​	(8,031,900)
Future development costs(1)	​	​	(1,051,911)	​	​	(121,966)	​	​	(1,173,877)
Income tax expense	​	​	(1,501,984)	​	​	(14,302)	​	​	(1,516,286)
Future net cash flows	​	​	5,634,975	​	​	1,397,045	​	​	7,032,020
10% annual discount for estimated timing of cash flows	​	​	(3,222,086)	​	​	(688,067)	​	​	(3,910,153)
Standardized measure of discounted future net cash flows related to proved reserves	​	$	2,412,889	​	$	708,978	​	$	3,121,867

(1)

Includes abandonment costs.

Sources of Change in Discounted Future Net Cash Flows

The changes in the pro forma standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the year ended December 31, 2021 are as follows:

​	For the Year Ended December 31, 2021
(in thousands)	BKV Corporation Historical			2022 Barnett Assets Historical			Pro Forma Combined
Beginning of period	​	$	510,410	​	$	26,375	​	$	536,785
Net change in sales and transfer prices and in production (lifting) costs related to future production	​	​	1,768,893	​	​	574,114	​	​	2,343,007
Changes in estimated future development costs	​	​	(393,235)	​	​	148	​	​	(393,087)
Sales and transfers of natural gas, NGLs and oil produced during the period	​	​	(522,403)	​	​	(188,565)	​	​	(710,968)
Net change due to extensions, discoveries and improved recovery	​	​	183,332	​	​	—	​	​	183,332
Purchase of minerals in place	​	​	19,050	​	​	—	​	​	19,050
Net change due to revisions in quantity estimates	​	​	1,266,086	​	​	278,939	​	​	1,545,025
Previously estimated development costs incurred during the period	​	​	60,406	​	​	—	​	​	60,406
Net change in future income taxes	​	​	(611,031)	​	​	(4,558)	​	​	(615,589)
Accretion of discount	​	​	56,096	​	​	2,815	​	​	58,911
Changes in timing and other	​	​	75,285	​	​	19,710	​	​	94,995
End of period	​	$	2,412,889	​	$	708,978	​	$	3,121,867

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our historical consolidated financial statements and related notes included elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expectations. “Cautionary Statement Regarding Forward-Looking Statements” and “Risk Factors” ​(included elsewhere in this prospectus) contain important information. We disclaim any duty to publicly update any forward-looking statements except as otherwise required by applicable law.

In this section, references to “BKV,” the “Company,” “we,” “us,” and “our” refer to BKV Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires. For more information on our organizational structure, see “Note 1 — General Information” to our historical consolidated financial statements included elsewhere in this prospectus.

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. 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, power generation and 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 seeking to establish arrangements to supply our natural gas production directly to the BKV-BPP Power Joint Venture. Our business is operated as one reportable segment.

Recent Developments

Barnett Zero CCUS Project with EnLink

On June 8, 2022, BKV dCarbon Ventures and EnLink reached a Phase I FID to develop our first CCUS project and entered into an agreement to dispose of, and geologically sequester, CO2 generated as a byproduct of the production of our natural gas in the Barnett and will utilize our newly acquired BKV Midstream assets. 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, which we expect to achieve an average injection rate of up to 185,000 tons of CO2 per year. We currently estimate the total project cost to us of the Barnett Zero Project to be between $20.0 and $22.0 million. We are targeting commencement of CO2 injection activities by the second half of 2023, subject to our ability to secure all required permits, at which point we expect this project to be one of the first permanent commercial CO2 disposal and sequestration projects to come online in the United States. We expect this project to offset our current Scope 1 and 2 annual emissions from our owned and operated upstream businesses by approximately 8%, bringing us closer to our goal of reaching net zero across Scope 1 and 2 upstream emissions by the end of 2025.

Exxon Barnett Acquisition

On June 30, 2022, we closed the acquisition (the “Exxon Barnett Acquisition”) of natural gas upstream and associated midstream infrastructure in the Barnett from XTO Energy, Inc. and Barnett Gathering LLC, subsidiaries of Exxon Mobil Corporation, for a total purchase price of $750.0 million, plus additional contingent consideration of up to $50.0 million depending on future natural gas prices. Pursuant to the Exxon Barnett Acquisition, we acquired approximately 175,000 total net acres that are approximately 99% held by production, primarily in Tarrant, Johnson and Parker counties, and additional smaller positions in Jack, Wise, Denton, Erath, Hood and Ellis counties, Texas. These upstream assets include low decline wells, ideal for delivering consistent cash flow, and high average working interests of approximately 94% in over 2,100 operated wells. The Exxon Barnett Acquisition also included approximately 778 miles of gathering pipelines and compression and processing midstream infrastructure with, as of June 30, 2022, over 450 MMcf/d of throughput capacity and approximately 26 MMcf/d of third-party production being gathered

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on the system. In connection with the Exxon Barnett Acquisition, we entered into the Term Loan Credit Agreement with a syndicate of banks and Bangkok Bank Public Company Limited (New York Branch), as the administrative agent. The Term Loan Credit Agreement includes up to $600.0 million of commitments for term loans to be used solely to fund a portion of the purchase price for the Exxon Barnett Acquisition and other costs and expenses associated with the acquisition. As of June 30, 2022, there was $570.0 million in aggregate principal amount outstanding under the Term Loan Credit Agreement. See “— Liquidity and Capital Resources — Loan Agreements and Credit Facilities — Term Loan Credit Agreement” for more information.

Amendment to Derivative Agreement

On August 4, 2022, we entered into an amendment to our ISDA Master Agreement with a counterparty to our derivative contracts pursuant to which we agreed to terminate or novate, at our election, at least $100.0 million of our derivative contracts. As of September 9, 2022, we terminated derivative contracts of $100.2 million with the counterparty to satisfy this requirement. In connection with such termination, we are required to make cash payments to the counterparty in an aggregate amount of $100.2 million, of which $30.0 million was paid in September 2022, an additional $30.0 million is due and payable before October 31, 2022 and the remaining $40.2 million must be paid by November 30, 2022. We intend to make the remaining payments with cash flows from operations. See “Note 14 —  Commitments and Contingencies’’ to our unaudited condensed consolidated financial statements included elsewhere in this prospectus for additional information regarding this agreement.

CCUS Project with Verde CO2

On August 22, 2022, we entered into a development agreement with Verde CO2 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. As of October 20, 2022, we have invested $8.3 million to Verde CO2 under the development agreement and we currently expect to invest up to $250.0 million over the next three years to equip efforts by BKVerde, a subsidiary of BKV dCarbon Ventures with the resources needed to efficiently identify and evaluate a pipeline of feasible CCUS projects, and to execute on those projects, which we expect to fund through cash flow from operations. This investment in CCUS evaluation and development aligns with our goal to reach net zero owned and operated upstream emissions across Scope 1 and 2 by the end of 2025.

Revolving Credit Agreement

On August 24, 2022, we entered into the Revolving Credit Agreement with Bangkok Bank Public Company Limited (New York Branch), as the administrative agent and sole initial lender. The Revolving Credit Agreement includes $100.0 million of commitments for unsecured revolving loans used for short-term working capital and operating needs. As of October 19, 2022, $45.0 million in aggregate principal amount was outstanding under the Revolving Credit Agreement. See “— Liquidity and Capital Resources — Loan Agreements and Credit Facilities — Revolving Credit Agreement” for more additional information regarding the Revolving Credit Agreement.

Cotton Cove CCUS Project

On October 18, 2022, BKV dCarbon Ventures reached a Phase I FID to develop our second CCUS project to dispose of, and geologically sequester, acid gas and CO2 generated as a byproduct of the production of our natural gas in the Barnett and will utilize our newly acquired BKV Midstream assets. This CCUS project, which we refer to as the Cotton Cove Project, will separate CO2 from our natural gas production in the Barnett. We estimate the Cotton Cove Project will geologically sequester up to 45,000 tons of CO2 per year initially, which we expect will increase to an average of up to 82,350 tons CO2 per year by the end of 2024 through ongoing well development in the area. We currently estimate the total project cost for the Cotton Cove Project to be between $14.0 and $24.0 million. We expect to own or hold the source, the capture, the

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transportation pipeline and the lease to the pore space with respect to this project. We are targeting commencement of CO2 injection activities by the first half 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 up to eight potential NGP projects that are in different phases of the appraisal and development process. As part of the Cotton Cove Project, we also expect to pilot, and then scale, post-combustion carbon capture technology that would allow us to sequester an additional 250,000 tons per year of captured CO2 from low concentration emissions from within our BKV Midstream operations. We expect that our technology applications will utilize compressor waste heat to reduce energy requirements and cost. We also expect to reduce the cost of low concentration transport and sequestration as the cost of the initial infrastructure build will have been incurred in connection with the high concentration anchor injection. We expect this project to initially offset our current Scope 1 and 2 annual emissions from our owned and operated upstream businesses by approximately 2%, bringing us closer to our goal of reaching net zero across our Scope 1 and 2 owned and operated upstream emissions by the end of 2025.

Operational and Financial Highlights

Below are some highlights of our operating and financial results for the six months ended June 30, 2022 and 2021 and the years ended December 31, 2021 and 2020:

•

Production of natural gas, NGLs, and oil was approximately 119.2 Bcfe and 123.3 Bcfe during the six months ended June 30, 2022 and 2021, respectively. Production of natural gas, NGLs, and oil was approximately 245.8 Bcfe and 111.7 Bcfe during the years ended December 31, 2021 and 2020, respectively.

•

Average realized product prices were $5.51 per Mcfe and $2.35 per Mcfe for the six months ended June 30, 2022 and 2021, respectively. For the years ended December 31, 2021 and 2020, respectively, average realized product prices were $3.38 per Mcfe and $1.03 per Mcfe.

•

For the six months ended June 30, 2022 and 2021, production revenues were $656.4 million and $289.3 million, respectively, and non-operated midstream revenues were $3.3 million and $4.0 million, respectively. For the years ended December 31, 2021 and 2020, production revenues were $829.7 million and $115.0 million, respectively, and non-operated midstream revenues were $6.9 million and $7.5 million respectively.

•

Lease operating expense was $44.1 million, or $0.37 per Mcfe, and $37.9 million, or $0.31 per Mcfe, for the six months ended June 30, 2022 and 2021, respectively. For the years ended December 31, 2021 and 2020, lease operating expense was $84.3 million, or $0.34 per Mcfe, and $30.1 million, or $0.27 per Mcfe, respectively.

•

Net income for the six months ended June 30, 2022 was $80.3 million and net loss for the six months ended June 30, 2021 was $129.5 million. Net loss for the years ended December 31, 2021 and 2020 was $134.5 million and $43.3 million, respectively.

•

Net cash provided by operating activities for the six months ended June 30, 2022 and 2021 was $160.8 million and $217.7 million, respectively. Net cash provided by operating activities for the year ended December 31, 2021 was $358.1 million, and net cash used in operating activities for the year ended December 31, 2020 was $7.4 million.

•

Adjusted EBITDAX was $254.6 million and $176.9 million for the six months ended June 30, 2022 and 2021, respectively. Adjusted EBITDAX was $281.4 million and $65.1 million for the years ended December 31, 2021 and 2020, respectively.

•

Adjusted Free Cash Flow was approximately $131.2 million and $122.7 million for the six months ended June 30, 2022 and 2021, respectively. Adjusted Free Cash Flow was approximately $165.1 million and $41.8 million for the years ended December 31, 2021 and 2020, respectively.

•

Net cash used in investing activities was $705.8 million for the six months ended June 30, 2022, $627.5 million of which was used to acquire assets in the Exxon Barnett Acquisition. The remaining $78.3 million is attributable primarily to development activities and investments in developed property and underdeveloped acreage. Net cash used in investing activities was $161.9 million for the

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year ended December 31, 2021, $88.4 million of which was used on the initial investment in the BKV-BPP Power Joint Venture. The remaining $73.5 million included $63.9 million attributable to development activities and $7.6 million for developed property and undeveloped acreage acquisition.

•

During the year ended December 31, 2021, we paid a dividend to common stockholders of $88.1 million, or $0.75 per share of our common stock. No dividends were paid during the six months ended June 30, 2022.

Adjusted EBITDAX and Adjusted Free Cash Flow are not financial measures calculated in accordance with accounting principles generally accepted in the United States of America (“GAAP”). See “Prospectus Summary — Summary Historical Financial Information — Non-GAAP Financial Measures” below for a description of each of these measures and a reconciliation of each of these measures to their most directly comparable GAAP measure.

Market Outlook

The natural gas and NGL industry is cyclical and commodity prices are highly volatile. According to the EIA, during the period from January 1, 2021 through June 30, 2022, the Henry Hub natural gas spot price reached a high of $23.86 per MMBtu on February 17, 2021 and a low of $2.43 per MMBtu on April 5, 2021. Since the Russia-Ukraine conflict first commenced, Henry Hub natural gas spot prices have trended higher, rising from $4.78 per MMBtu on February 24, 2022 to a high of $9.85 per MMBtu on August 22, 2022, according to the EIA.

We expect the natural gas and NGL markets will continue to be volatile in the future. Our revenue, profitability and future growth are highly dependent on the prices we receive for our natural gas and NGL production. See “Risk Factors — Risks Related to Our Upstream Business and Industry — The volatility of natural gas and NGL prices due to factors beyond our control may materially and adversely affect our business, financial condition or results of operations, and our ability to make required capital expenditures, meet our debt service obligations and other financial commitments and to pay dividends on our common stock.”

Although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021, which has continued into 2022, due to a substantial increase in the money supply, a stimulation focused fiscal policy, a significant rebound in consumer demand as COVID-19 restrictions were relaxed, the Russia-Ukraine war and worldwide supply chain disruptions resulting from the economic contraction caused by COVID-19 and lockdowns followed by a rapid recovery. Inflation rose from 5.4% in June 2021 to 7.0% in December 2021 to 8.5% in July 2022. Global, industry-wide supply chain disruptions have resulted in widespread shortages of labor, materials and services. Such shortages have resulted in our facing significant cost increases for labor, materials and services. We do not expect these shortages and cost increases to reverse in the short term. Typically, as prices for natural gas, NGLs and oil increase, so do associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to prices. We cannot predict the future inflation rate but to the extent inflation remains elevated, we may experience further cost increases in our operations, including costs for drill rigs, workover rigs, hydraulic fracturing fleets, tubulars and other well equipment, as well as increased labor costs. If we are unable to recover higher costs through higher commodity prices, our current revenue stream, estimates of future reserves, impairment assessments of natural gas and oil properties, and values of properties in purchase and sale transactions would all be significantly impacted. The recent increase to prices for natural gas, NGLs and oil have more than offset the inflationary related increases to our costs. However, we are monitoring the situation and assessing its impact on our business, including to our customers and our partners. These inflationary pressures are not expected to have a significant impact on our liquidity position when considered in isolation or when combined with the impact of rising interest rates on our variable rate debt. We expect to continue to achieve our business strategy by remaining vigilant in maintaining a disciplined financial strategy and in optimizing the value of our core business.

How We Evaluate Our Business

We use a variety of financial and operational metrics to assess performance of our operations, including:

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•

Adjusted EBITDAX;

•

Upstream Reinvestment Rate;

•

Adjusted Free Cash Flow;

•

Adjusted Free Cash Flow Margin;

•

Production Volume; and

•

Total Net Leverage Ratio.

Adjusted EBITDAX.   We define Adjusted EBITDAX as net income (loss) before (1) non-cash derivative gain (loss), (2) accretion of asset retirement obligation, (3) accretion of right of use liability, (4) depreciation, depletion, and amortization, (5) exploration and impairment expense, (6) (loss) gain on contingent consideration liabilities, (7) interest expense, (8) income tax benefit (expense), (9) equity-based compensation expense, (10) bargain purchase gains, (11) income from equity affiliates, (12) early settlement of derivative contracts and (13) 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 operation 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 operation from period to period and against our peers, without regard to our financing methods, corporate form or capital structure. See “Prospectus Summary — Summary Historical Financial Information — Non-GAAP Financial Measures” for a description of Adjusted EBITDAX and for a reconciliation of Adjusted EBITDAX to net loss, its most directly comparable GAAP measure.

Upstream Reinvestment Rate.   Upstream Reinvestment Rate for any period is 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. We use this metric to evaluate from period to period the efficient use of our upstream capital expenditures to maintain or grow our upstream production. We target an Upstream Reinvestment Rate of 40% or less to allow for funding of strategic initiatives. In addition, we target a Maintenance Reinvestment Rate of less than 30%.

Adjusted Free Cash Flow.   We define Adjusted Free Cash Flow as net cash provided by (used in) operating activities excluding changes in operating assets and liabilities, less total cash paid for capital expenditures (excluding leasehold costs and acquisitions). 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. See “Prospectus Summary — Summary Historical Financial Information — Non-GAAP Financial Measures” for a description of Adjusted Free Cash Flow and for a reconciliation of Adjusted Free Cash Flow to net loss and net cash provided by (used in) operating activities, its most directly comparable GAAP measures.

Adjusted Free Cash Flow Margin.   We define Adjusted Free Cash Flow Margin as the ratio of Adjusted Free Cash Flow for any period to total revenues, excluding derivative gains and losses, for such period. We use this metric to assess our liquidity relative to our revenues. Adjusted Free Cash Flow Margin illustrates the efficiency with which the Company generates Adjusted Free Cash Flow.

Production Volume.   Production Volume for any period is defined as the volume of natural gas, NGLs or oil we extract from our Barnett and NEPA natural gas properties. We use this metric to monitor the efficiency and effectiveness of our upstream operations.

Total Net Leverage Ratio.   Total Net Leverage Ratio is the ratio of our total debt less cash and cash equivalents to Adjusted EBITDAX. We use this metric to evaluate our total debt relative to our ability to generate cash through Adjusted EBITDAX. We target a Total Net Leverage Ratio of 1.0x or less to ensure adequate liquidity to meet debt obligations and a low debt burden to protect Adjusted Free Cash Flow. This

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metric also provides management with a benchmark of debt levels while considering growth opportunities and our ability to manage periods of commodity price volatility.

Factors that Affect Comparability of Our Results of Operations

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward primarily for the following reasons:

Acquisitions.   We intend to continue to grow our operations and financial results through strategic acquisitions like the Devon Barnett Acquisition and the Exxon Barnett Acquisition. Additionally, we may from time to time effect divestitures of certain of our non-core assets. As a result of our Devon Barnett Acquisition, the acquisition of Temple I by the BKV-BPP Power Joint Venture, as well as our recent Exxon Barnett Acquisition, our historical reserve, operating and financial data may not be comparable from period to period. For example, for the years ended December 31, 2021 and 2020, our total revenues were approximately $505.7 million and $143.3 million, respectively. As of June 30, 2022 and December 31, 2021, our total assets were approximately $2,642.4 million and $1,620.8 million, respectively, and our total liabilities were $1,788.0 million and $865.9 million, respectively. For the six months ended June 30, 2022 and 2021, our loss from BKV-BPP Power Joint Venture was approximately $24.0 million and zero, respectively. For the years ended December 31, 2021 and 2020, our income from BKV-BPP Power Joint Venture was approximately $0.9 million and zero, respectively.

Supply, demand, market risk and the impact on natural gas, NGLs and oil prices.   As discussed above in “— Market Outlook,” the natural gas and oil industry historically has been cyclical with highly volatile commodity prices. Natural gas and oil prices are subject to large fluctuations in response to relatively minor changes in the demand for natural gas, NGLs and oil. Prices are affected by current and expected supply and demand dynamics, including the market disruptions resulting from the Russian-Ukraine war, the impact of the COVID-19 pandemic and related erosion of demand for natural gas, NGLs and oil, U.S. supply growth driven by advances in drilling and completion technologies, and the delay of an agreement on production levels by members of OPEC and other oil producing countries, including Russia, resulting in increased supply in the global market. Other factors impacting supply and demand include weather conditions (including severe weather events), pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, supply chain quality and availability, strength of the U.S. dollar as well as other factors, the majority of which are outside of our control. These commodity prices are likely to remain volatile in the future.

Public company expenses.   We expect to incur incremental, non-recurring costs related to our transition to a publicly traded company, including the costs of this initial public offering and the costs associated with the initial implementation of our Sarbanes-Oxley Section 404 internal control implementation and testing. We also expect to incur additional significant and recurring expenses as a publicly traded corporation, including costs associated with the employment of additional personnel, compliance under the Exchange Act, annual and quarterly reports to common stockholders, registrar and transfer agent fees, national stock exchange fees, audit fees, legal fees, incremental director and officer liability insurance costs and director and officer compensation.

Winter Storm Uri.   Our marketing revenues consist of our portion of net profits earned through an agreement we have in place with a third party who operates a commodity trading book. In 2021, we received higher than normal marketing revenues due to the pricing volatility surrounding abnormal weather events. Although the agreement remains in effect, we consider such levels of marketing revenues to be unusual and may not recur in future periods.

Factors that Significantly Affect Our Financial Condition and Results of Operations

We derive almost all of our revenues from the sale of natural gas and NGLs produced from our interests in properties located in the Barnett and NEPA. Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Natural gas and NGL prices have historically been volatile and may fluctuate widely in the future due to a variety of factors, including but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace and geopolitical events such as wars

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or natural disasters. In the future, we will also be subject to fluctuations in commodity prices. Sustained periods of low natural gas prices could materially and adversely affect our financial condition, our results of operations, the quantities of natural gas and NGLs that we can economically produce and our ability to access capital.

From time to time, we utilize derivative contracts in connection with our natural gas operations to provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas and NGL production. The derivative contracts we enter into consist of swaps, producer collars and enhanced three-way collars, subject to master netting agreements with each individual counterparty. While these arrangements are structured to reduce our exposure to commodity price decreases, they can also limit the benefit we might otherwise receive from commodity price increases. For example, for the six months ended June 30, 2022 and 2021, we had derivative losses, net of approximately $450.8 million and $178.3 million, respectively. For the years ended December 31, 2021 and 2020, we had derivative losses, net of approximately $383.8 million, and derivative gains, net of approximately $20.8 million, respectively. We elected not to designate our current portfolio of commodity derivative contracts as hedges for accounting purposes. Therefore, changes in fair value of these derivative instruments are recognized in earnings. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk and Hedging Activities” for additional discussion of our commodity derivative contracts. Our results of operations, liquidity and financial condition would be negatively impacted if natural gas prices were to become depressed or decline materially from current levels, or there is otherwise an unexpected material impact on commodity prices, and we have experienced variances in our results of operations and financial condition due to our hedging transactions.

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

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

•

success in drilling new wells;

•

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

•

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

•

facility or equipment availability and unexpected downtime; and

•

delays imposed by or resulting from compliance with regulatory requirements.

Sources of Revenues

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

We sell natural gas, NGLs and oil at specific delivery points. To deliver our products, we may incur third party fees for gathering and transportation. Fees incurred prior to transfer of control are recorded as

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gathering and transportation expenses. Fees incurred after transfer of control are recognized as a reduction to our transaction price. Pricing of commodities is subject to supply and demand as well as to seasonal, political and other conditions that we generally cannot control. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Natural gas, NGL and oil sale revenues

Approximately 98.7% and 84.2% of our total revenues for the six months ended June 30, 2022 and 2021, respectively, were derived through the production and sale of natural gas, NGLs and oil. Approximately 93.3% and 93.8% of our total revenues, excluding net derivative (losses) gains, for the years ended December 31, 2021 and 2020, respectively, were derived through the production and sale of natural gas, NGLs and oil. Production of these resources occurs exclusively within the Barnett and NEPA. The following table presents the breakdown of our revenues from the production and sale of natural gas, NGLs and oil for periods presented:

​	Six Months Ended June 30,				Year Ended December 31,
​	2022		2021		2021		2020
Natural gas sales	​	74%	​	60%	​	72%	​	89%
NGL sales	​	25%	​	39%	​	27%	​	10%
Oil sales	​	1%	​	1%	​	1%	​	1%

Our revenues are influenced by production volumes as well as commodity prices. The following table presents our historical production volumes for the periods presented:

​	Six Months Ended June 30,				Year Ended December 31,
​	2022		2021		2021		2020
Production data	​	​	​	​	​		​
Natural gas (MMcf)	​	90,092	​	93,459	​	186,055	​	96,159
NGLs (MBbls)	​	4,800	​	4,914	​	9,829	​	2,565
Oil (MBbls)	​	54	​	67	​	123	​	29
Total volumes (MMcfe)	​	119,220	​	123,342	​	245,767	​	111,722
Average daily total volumes (MMcfe/d)	​	658.7	​	681.4	​	673.3	​	306.1

Non-operated midstream revenues, net

Approximately 0.5% and 1.2% of our total revenues, excluding derivative losses, net, for the six months ended June 30, 2022 and 2021, respectively, were generated from our approximate 29.4% non-operated interest in a midstream system operated by Repsol. For the years ended December 31, 2021 and 2020, these non-operated midstream revenues amounted to approximately 0.7% and 6.1% of our total revenues, excluding net derivative (losses) gains, respectively. Revenues from our non-operated interest are recognized when services are rendered based on quantities transported and measured according to the underlying contract.

Marketing revenues

Approximately 0.8% and 14.6% of our total revenues, excluding derivative losses, net, for the six months ended June 30, 2022 and 2021, respectively, and approximately 5.9% and zero of our total revenues, excluding net derivative (losses) gains, net, for the years ended December 31, 2021 and 2020, respectively, consists of our portion of net profits earned through an agreement with Concord Energy, LLC, the third-party marketer of all of our natural gas production. Pursuant to this arrangement, we receive a fixed percentage of all net income realized in the resale of our and other producers’ hydrocarbons. In February 2021, we received higher than normal marketing revenues due to the pricing volatility surrounding the events of Winter Storm Uri. Although the agreement remains in effect, we consider such levels of marketing revenues to be unusual and may not recur in future periods.

Other revenues

Other revenues consist of other miscellaneous revenue streams including the management fee from the BKV-BPP Power Joint Venture.

106

Realized commodity prices

Our results of operations are heavily influenced by commodity prices. Natural gas, NGL and oil prices have historically been volatile and are currently at near record-high levels. On December 31, 2021, the Henry Hub natural gas spot price was $3.82 per MMBtu, though during the period from January 1, 2021 through June 30, 2022, natural gas prices reached a high of $23.86 per MMBtu and a low of $2.43 per MMBtu. A future decline in commodity prices may adversely affect our business, financial condition or results of operations. Lower commodity prices may not only decrease our revenues, but also the amount of natural gas and oil that we can produce economically.

NYMEX Henry Hub, for gas prices, and NYMEX WTI, for oil prices, are widely used benchmarks for the pricing of natural gas and oil in the United States. The price we receive for our natural gas and oil production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. As such, our revenues are sensitive to the price of the underlying commodity to which they relate. The following is a comparison of average pricing excluding and including the effects of derivatives:

​	For the Six Months Ended June 30,						For the Year Ended December 31,
​	2022			2021			2021			2020
Average prices:	​	​	​	​	​	​	​	​	​	​	​	​
Natural gas (Mcf):	​	​	​	​	​	​	​	​	​	​	​	​
Average NYMEX Henry Hub Price	​	$	6.08	​	$	3.22	​	$	3.84	​	$	2.08
Average Natural Gas Realized Price (excluding derivatives)	​	$	5.41	​	$	1.86	​	$	3.21	​	$	1.06
Average Natural Gas Realized Price (including derivatives)	​	$	3.60	​	$	1.85	​	$	2.29	​	$	1.17
Differential to NYMEX Henry Hub	​	$	(0.67)	​	$	(1.36)	​	$	(0.63)	​	$	(1.02)
NGLs (Bbl):	​	​	​	​	​	​	​	​	​	​	​	​
Average NYMEX WTI Price	​	$	102.01	​	$	62.21	​	$	67.92	​	$	39.40
Average NGL Realized Price (excluding derivatives)	​	$	34.06	​	$	22.62	​	$	22.90	​	$	4.66
Average NGL Realized Price (including derivatives)	​	$	29.40	​	$	18.36	​	$	16.03	​	$	4.66
Differential to NYMEX WTI	​	$	(67.95)	​	$	(39.59)	​	$	(45.02)	​	$	(34.74)
Oil (Bbl):	​	​	​	​	​	​	​	​	​	​	​	​
Average NYMEX WTI Price	​	$	102.01	​	$	62.21	​	$	67.92	​	$	39.40
Average Oil Realized Price (excluding derivatives)	​	$	94.16	​	$	60.51	​	$	61.46	​	$	46.67
Average Oil Realized Price (including derivatives)	​	$	94.16	​	$	60.51	​	$	61.46	​	$	46.67
Differential to NYMEX WTI	​	$	(7.85)	​	$	(1.70)	​	$	(6.46)	​	$	7.27
High and low NYMEX prices:	​	​	​	​	​	​	​	​	​	​	​	​
Oil (Bbl):	​	​	​	​	​	​	​	​	​	​	​	​
High	​	$	123.64	​	$	74.21	​	$	84.65	​	$	63.27
Low	​	$	75.99	​	$	47.47	​	$	47.62	​	$	(37.63)
Natural gas (Mcf):	​	​	​	​	​	​	​	​	​	​	​	​
High	​	$	9.44	​	$	23.86	​	$	23.86	​	$	3.35
Low	​	$	3.73	​	$	2.43	​	$	2.43	​	$	1.48

Commodity Price Risk and Derivatives and Hedging Activities

The volatility of energy markets makes it extremely difficult to predict future natural gas, NGL and oil price movements with any certainty, and our results of operations and cash flows are impacted by changes in market prices for natural gas, NGLs and oil. Lower natural gas, NGL and oil prices may reduce the amount of natural gas and oil that we can produce economically. This may also result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production

107

estimates change or our exploration or development activities are curtailed, successful efforts accounting rules may require us to recognize impairment expense as a non-cash charge to earnings, and to the carrying value of our natural gas properties.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time to time we enter into derivative arrangements for our production. In most of our current positions, our hedging activity may also reduce our ability to benefit from increases in commodity prices. We will sustain losses to the extent our derivatives contract prices are lower than market prices, and conversely, we will recognize gains to the extent our derivatives contract prices are higher than market prices. The price we receive for sales of our natural gas, NGL, and oil is generally less than the NYMEX prices because of adjustments for basis, relative quality and other factors.

In the six months ended June 30, 2022, our derivative settlements decreased our natural gas revenue by $228.3 million and our NGL revenue by $22.4 million. In the six months ended June 30, 2021, our derivative settlements decreased our natural gas revenue by $1.1 million and decreased our NGL revenue by $20.9 million. In the year ended December 31, 2021, our derivative settlements decreased our natural gas revenue by $170.2 million and our NGL revenue by $67.6 million. In the year ended December 31, 2020, our derivative settlements increased natural gas revenue by $10.4 million.

The following table summarizes our outstanding natural gas and NGL derivative positions as of June 30, 2022. Prices to be realized for hedged production will be less than these NYMEX prices because of location, quality and other adjustments.

Instrument

MMBTU

Weighted Average Price (USD)

Weighted Average Price Sub Floor

Weighted Average Price Floor

Weighted Average Price Ceiling

Weighted Average Price Sub Ceiling

Fair Value as of June 30, 2022 (In thousands)

2022

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Swap

​

33,349,000

​

$

4.33

​

​

​

​

​

​

​

​

​

​

​

​

​

$

(39,053)

Enhanced three-way collars

​

21,430,000

​

​

​

​

$

2.51

​

$

2.54

​

$

3.08

​

$

3.17

​

$

(108,025)

Collars

​

5,415,000

​

​

​

​

​

​

​

$

2.84

​

$

3.69

​

​

​

​

$

(11,189)

2023

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Swap

​

54,812,000

​

$

3.91

​

​

​

​

​

​

​

​

​

​

​

​

​

$

(35,182)

Enhanced three-way collars

​

8,350,000

​

​

​

​

​

​

​

$

2.45

​

$

3.15

​

$

3.15

​

$

(24,571)

Collars

​

50,100,000

​

​

​

​

​

​

​

$

2.85

​

$

3.75

​

​

​

​

$

(51,368)

The following table represents natural gas liquids commodity derivatives for contracts expiring throughout the year ending December 31, 2022 and 2023 based on the applicable index listed below:

Instrument	Commodity Reference Price	Volumes		Weighted Average Price (USD)			Fair Value at June 30, 2022 (In thousands)
2022	​	​	​	​	​	​	​	​	​
Swaps	OPIS Purity Ethane Mont Belvieu	​	75,339,600	​	$	0.35	​	$	(8,764)
Swaps	OPIS IsoButane Mont Belvieu Non-TET	​	1,932,000	​	$	0.99	​	$	(964)
Collars	OPIS IsoButane Mont Belvieu Non-TET	​	4,636,800	​	$	1.34	​	$	(138)
Swaps	OPIS Normal Butane Mont Belvieu Non-TET	​	3,864,000	​	$	0.98	​	$	(1,642)
Collars	OPIS Normal Butane Mont Belvieu Non-TET	​	7,467,600	​	$	1.40	​	$	(68)
Swaps	OPIS Pentane Mont Belvieu Non-TET	​	3,864,000	​	$	1.46	​	$	(1,936)
Collars	OPIS Pentane Mont Belvieu Non-TET	​	11,331,600	​	$	1.99	​	$	76
Swaps	OPIS Propane Mont Belvieu Non-TET	​	11,592,000	​	$	0.86	​	$	(3,973)
Collars	OPIS Propane Mont Belvieu Non-TET	​	31,164,000	​	$	1.22	​	$	108
2023	​	​	​	​	​	​	​	​	​

108

Instrument	Commodity Reference Price	Volumes		Weighted Average Price (USD)			Fair Value at June 30, 2022 (In thousands)
Swap	OPIS Purity Ethane Mont Belvieu	​	38,325,000	​	$	0.23	​	$	(4,307)
Swap	OPIS IsoButane Mont Belvieu Non-TET	​	3,832,500	​	$	0.80	​	$	(1,610)
Swap	OPIS Normal Butane Mont Belvieu Non-TET	​	3,832,500	​	$	0.80	​	$	(1,475)
Swap	OPIS Pentane Mont Belvieu Non-TET	​	7,665,000	​	$	1.28	​	$	(4,109)
Swap	OPIS Propane Mont Belvieu Non-TET	​	22,995,000	​	$	0.72	​	$	(6,778)

Principal Components of Cost Structure

Lease operating and workover

Lease operating and workover expenses reflect the costs incurred to maintain our production. Lease operating expenses represent the costs incurred for field employee salaries, saltwater disposal, repairs and maintenance, and other standard operating expenses. Workover expenses include those costs incurred to perform more substantial maintenance or remedial treatments on a well to restore or enhance production. Cost levels for certain of these expenses vary based on the volume of production, among other factors.

Taxes other than income

Taxes other than income consist of production taxes, severance taxes, impact fees and ad valorem taxes. Production and severance taxes are paid on produced natural gas and oil based on a percentage of the market value or sales prices of the natural gas and oil or at fixed per-unit rates established by state authorities. Impact fees are based on drilling activities and natural gas market prices. We pay ad valorem taxes based on the value of our reserves as well as the value of property and equipment.

Gathering and transportation

Gathering and transportation expenses are incurred in connection with the natural gas, NGL and oil gathering and transportation contracts we enter into with third parties. Pursuant to these contracts, third parties agree to deliver the natural gas, NGLs and oil we produce to our customers for a fee. The fees incurred prior to control transfer are classified as gathering and transportation expenses (in the Barnett) on the consolidated statement of operations, whereas any fees incurred after transfer of control are included as a reduction of the associated revenues (in NEPA).

Accretion of asset retirement obligations

Accretion of asset retirement obligations reflects the expense related to accretion of our asset retirement obligations. Our obligations are accreted using the interest method over the period from initial measurement to the expected timing of settlement and are measured using our credit-adjusted risk-free rate applied when the liability was initially measured.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization reflects the systematic expensing of the costs capitalized in connection with our costs to acquire, explore and develop natural gas, NGLs and oil. We use the successful efforts method of accounting for natural gas producing activities. Accordingly, we capitalize all costs associated with our acquisition, drilling, development, and retirement efforts and all successful exploration efforts and allocate these costs using the units of production method. Depreciation of midstream assets and other property and equipment is computed over an asset’s estimated useful life using a straight-line basis.

Exploration and impairment

Exploration costs are costs related to unsuccessful leasing efforts, as well as geological and geophysical costs, including seismic costs, costs of unsuccessful exploratory dry holes and costs of other exploratory activities. Impairment costs include impairment and costs associated with leases expirations, impairment of

109

design and initial costs related to pads that are no longer planned to be placed into service and impairment of proved properties due to lower future commodity prices. We charge impairment expense for expired or soon-to-be expired leases when we determine they are impaired based on factors such as remaining lease terms, reservoir performance, commodity price outlooks and future plans to develop the acreage. We also record impairment charges for proved properties on a geological reservoir basis when events or changes in circumstances indicate that a property’s carrying amount may not be recoverable.

General and administrative

General and administrative expenses typically represent costs for payroll and benefits for our work force, equity-based compensation expense, integration support, consulting fees, costs incurred to maintain our headquarters, and costs incurred for various legal proceedings which arise through the normal course of business, among others.

Accretion of right of use liabilities

For any contract deemed to include a leased asset, such as compressors and other equipment used in our upstream operations, that asset is capitalized on the balance sheet as a right of use asset and a corresponding lease liability is recorded at the present value of the known future minimum payments of the contract using a discount rate on the date of commencement. Accretion of right of use liabilities reflects the periodic accretion expense associated with the increase in the present value of the lease liability over the life of the underlying lease.

(Loss) gain on contingent consideration liabilities

In October 2020, we acquired Devon Energy’s Barnett assets pursuant to a purchase agreement that included an earnout obligation pursuant to which we agreed to make certain contingent consideration payments based on future prices of natural gas. As of June 30, 2022, we have paid Devon Energy $65.0 million in contingent consideration payments. These contingent consideration payments are stated at fair value on our consolidated balance sheet, with changes in fair value recorded in the consolidated statement of operations.

Interest expense

We finance a portion of our capital expenditures, working capital requirements and acquisitions with borrowings under the Subordinated Intercompany Loan Agreements and the Term Loan Credit Agreement. As a result, we incur interest expense that is affected by both fluctuations in interest rates under our credit facilities and our financing decisions. We have not historically utilized interest rate swaps to mitigate fluctuations in interest rates.

Income tax benefit (expense)

We are subject to state and U.S. federal income taxes. The difference between our financial statement income tax expense and our U.S. federal income tax liability is primarily due to the differences in the tax and financial statement treatment of natural gas properties and the deferral of unsettled commodity derivative gains and losses for tax purposes until they are settled. We also pay certain state income or franchise taxes where state income or franchise taxes are determined on a basis other than income. We record deferred income tax expense to the extent our deferred tax liabilities exceed our deferred tax assets.

In the future, we expect we will be able to realize an additional income tax benefit from Section 45Q tax credits. For facilities placed in service on or after February 9, 2018 and before January 1, 2023, Section 45Q of the Code generally provides the capturing parties a tax credit that escalates until 2026, when it reaches $50 per ton for CO2 directly stored in geologic formations, annually escalating for inflation thereafter. For facilities placed in service after December 31, 2022, the credit amount is increased to $85 per ton, subject to satisfaction or non-application of certain prevailing wage and apprenticeship requirements (or $17 per ton if such prevailing wage and apprenticeship requirements are not satisfied), with adjustments for inflation after 2026. In either case, Section 45Q tax credits are available for a 12-year period for qualifying facilities that begin construction before January 1, 2033.

110

Results of Operations

The following tables present selected financial and operating information for the periods presented:

​	Six Months Ended June 30,
(In thousands)	2022			2021
Revenues and other operating income	​	​	​	​	​	​
Natural gas, NGL and oil sales	​	$	656,431	​	$	289,342
Non-operated midstream revenues	​	​	3,344	​	​	3,972
Derivative losses, net	​	​	(450,784)	​	​	(178,275)
Marketing revenues	​	​	5,328	​	​	50,296
Other	​	​	1,327	​	​	—
Total revenues and other operating income	​	​	215,646	​	​	165,335
Operating expenses	​	​	​	​	​	​
Lease operating and workover	​	​	45,333	​	​	40,515
Taxes other than income	​	​	41,001	​	​	16,697
Gathering and transportation	​	​	98,756	​	​	76,756
Accretion of asset retirement obligations	​	​	5,320	​	​	4,904
Depreciation, depletion, and amortization	​	​	36,800	​	​	40,842
Exploration and impairment	​	​	—	​	​	34
General and administrative	​	​	51,497	​	​	37,988
Accretion of right of use liabilities	​	​	135	​	​	106
Total operating expenses	​	​	278,842	​	​	217,842
(Loss) income from operations	​	​	(63,196)	​	​	(52,507)
Other income and expense	​	​	​	​	​	​
Loss on contingent consideration liabilities	​	​	(31,915)	​	​	(115,345)
Interest expense	​	​	(6,698)	​	​	(314)
Other income	​	​	516	​	​	62
Bargain purchase gain	​	​	163,653	​	​	—
Gain on settlement of litigation	​	​	16,866	​	​	—
Loss from equity affiliates	​	​	(23,958)	​	​	—
Interest income	​	​	128	​	​	2
Income (loss) before income taxes	​	​	55,396	​	​	(168,102)
Income tax benefit (expense)	​	​	24,903	​	​	38,648
Net income (loss) and comprehensive income (loss) attributable to BKV Corporation	​	$	80,299	​	$	(129,454)
Less accretion of preferred stock to redemption value	​	​	—	​	​	(2,336)
Less preferred stock dividends	​	​	—	​	​	(9,900)
Less deemed dividend on redemption of preferred stock	​	​	—	​	​	(1,353)
Net income (loss) and comprehensive income (loss) attributable to common stockholders	​	$	80,299	​	$	(143,043)

111

​	Year Ended December 31,
(In thousands)	2021			2020
Revenues and other operating income	​	​	​	​	​	​
Natural gas sales	​	$	597,050	​	$	101,758
NGL sales	​	​	225,135	​	​	11,952
Oil sales	​	​	7,560	​	​	1,333
Non-operated midstream revenues, net	​	​	6,917	​	​	7,458
Derivative (losses) gains, net	​	​	(383,847)	​	​	20,755
Marketing revenues	​	​	52,616	​	​	—
Other	​	​	251	​	​	33
Total revenues and other operating income	​	​	505,682	​	​	143,289
Operating expenses	​	​	​	​	​	​
Lease operating and workover	​	​	88,105	​	​	31,260
Taxes other than income	​	​	45,650	​	​	5,151
Gathering and transportation	​	​	173,587	​	​	—
Accretion of asset retirement obligations	​	​	10,030	​	​	3,211
Depreciation, depletion, and amortization	​	​	81,986	​	​	83,388
Exploration and impairment	​	​	34	​	​	560
General and administrative	​	​	85,740	​	​	29,442
Accretion of right of use liabilities	​	​	227	​	​	184
Total operating expenses	​	​	485,359	​	​	153,196
(Loss) income from operations	​	​	20,323	​	​	(9,907)
Other income and expense	​	​	​	​	​	​
(Loss) gain on contingent consideration liabilities	​	​	(194,968)	​	​	7,135
Interest expense	​	​	(2,134)	​	​	(1,713)
Other income	​	​	872	​	​	—
Income (loss) from equity affiliates	​	​	910	​	​	—
Interest income	​	​	8	​	​	121
Income (loss) before income taxes	​	​	(174,989)	​	​	(4,364)
Income tax benefit (expense)	​	​	40,526	​	​	(38,982)
Net income (loss) and comprehensive income (loss) attributable to BKV Corporation	​	$	(134,463)	​	$	(43,346)
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) and comprehensive income (loss) attributable to common stockholders	​	$	(170,714)	​	$	(43,806)

112

Comparison of the Six Months Ended June 30, 2022 and 2021

Operating revenues

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

​	Six Months Ended June 30,						​	​	​	​	​
(In thousands)	2022			2021			$ Change			% Change
Revenues	​	​	​	​	​	​	​	​	​	​	​
Natural gas revenues	​	$	487,813	​	$	174,120	​	$	313,693	​	180%
NGL revenues	​	​	163,498	​	​	111,166	​	​	52,332	​	47%
Oil revenues	​	​	5,120	​	​	4,056	​	​	1,064	​	26%
Non-operated midstream revenues, net	​	​	3,344	​	​	3,972	​	​	(628)	​	(16)%
Derivative (losses) gains, net	​	​	(450,784)	​	​	(178,275)	​	​	(272,509)	​	153%
Marketing revenues	​	​	5,328	​	​	50,296	​	​	(44,968)	​	(89)%
Other	​	​	1,327	​	​	—	​	​	1,327	​	*
Total revenues and other operating income	​	$	215,646	​	$	165,335	​	​	​	​	​

*

Percentage not meaningful

Natural gas revenues

Our natural gas revenues increased by approximately $313.7 million to $487.8 million for the six months ended June 30, 2022 from $174.1 million for the six months ended June 30, 2021. Lower production volumes during the six months ended June 30, 2022 contributed a $6.3 million decrease in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period-end average price). This decrease was more than offset by the impact of commodity price increases, excluding the effects of derivative settlements. which contributed a $320.0 million increase in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes).

NGL revenues

Our NGL revenues increased by approximately $52.3 million to $163.5 million for the six months ended June 30, 2022 from $111.2 million for the six months ended June 30, 2021. Lower production volumes during the six months ended June 30, 2022 accounted for a $2.6 million decrease in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period-end average price). This decrease was more than offset by the impact of commodity price increases, excluding the effects of derivative settlements, which accounted for an approximate $54.9 million increase in period-over-period revenues (calculated as the change in the period-to-period average price times current year production volumes).

Oil revenues

Our oil revenues increased by approximately $1.1 million to $5.1 million for the six months ended June 30, 2022 from $4.1 million for the six months ended June 30, 2021. Lower production volumes during the six months ended June 30, 2022 accounted for a $0.8 million decrease in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period-end average price). This decrease was more than offset by the impact of commodity price increases, excluding the effects of derivative settlements, which accounted for an approximate $1.8 million increase in period-over-period revenues (calculated as the change in the period-to-period average price times current year production volumes).

113

Non-operated midstream revenues, net

Our non-operated midstream revenues decreased by approximately $0.6 million, or 16%, to $3.3 million for the six months ended June 30, 2022 from $4.0 million for the six months ended June 30, 2021. This decrease was primarily due to decreases in the associated production of natural gas properties the midstream assets support.

Derivative (losses) gains, net

For the six months ended June 30, 2022, we had a loss on derivative contracts of $450.8 million compared to a loss on derivative contracts of $178.3 million for the six months ended June 30, 2021. The loss for the six months ended June 30, 2022 is attributable to increases in underlying commodity prices and volatility in energy markets, which resulted in higher realized and unrealized losses on derivative contracts.

Marketing revenues

Our marketing revenues decreased by approximately $45.0 million, to $5.3 million for the six months ended June 30, 2022 from $50.3 million for the six months ended June 30, 2021. These revenues are generated in connection with our agreement with Concord Energy, LLC, the third-party marketer of all of our natural gas production. Pursuant to this arrangement, we receive a fixed percentage of all net income realized in the resale of our and other producers’ hydrocarbons. In February 2021, we received higher than normal marketing revenues due to the pricing volatility surrounding the events of Winter Storm Uri. Although the agreement remains in effect, we consider such levels of marketing revenues to be unusual and may not recur in future periods.

Other revenues

We generate a portion of our revenues from other sources including surface and midstream operations. Our midstream and surface operations primarily support our own exploration and production operations, with revenues generated primarily from fees charged for surface and midstream services, including transportation, freshwater sourcing and disposal, and other services to us and our affiliates and, to a lesser extent, third parties. Our other revenues were approximately $1.3 million for the six months ended June 30, 2022 as compared to a negligible amount for the six months ended June 30, 2021.

Operating Expenses

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

​	Six Months Ended June 30,						​	​	​	​	​
(In thousands, other than percentages and average costs)	2022			2021			$ Change			% Change
Operating Expense	​	​	​	​	​	​	​	​	​	​	​
Lease operating and workover	​	$	45,333	​	$	40,515	​	$	4,818	​	12%
Taxes other than income	​	​	41,001	​	​	16,697	​	​	24,304	​	*
Gathering and transportation costs	​	​	98,756	​	​	76,756	​	​	22,000	​	29%
Accretion of asset retirement obligations	​	​	5,320	​	​	4,904	​	​	416	​	8%
Depreciation, depletion, and amortization	​	​	36,800	​	​	40,842	​	​	(4,042)	​	(10)%
Exploration and impairment	​	​	—	​	​	34	​	​	(34)	​	*
General and administrative	​	​	51,497	​	​	37,988	​	​	13,509	​	36%
Accretion of right of use liabilities	​	​	135	​	​	106	​	​	29	​	27%
Total operating expense	​	$	278,842	​	$	217,842	​	​	​	​	​

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​	Six Months Ended June 30,						​	​	​	​	​
(In thousands, other than percentages and average costs)	2022			2021			$ Change			% Change
Average Costs per Mcfe	​	​	​	​	​	​	​	​	​	​	​
Lease operating and workover	​	$	0.38	​	$	0.33	​	$	0.05	​	15%
Taxes other than income	​	$	0.34	​	$	0.14	​	$	0.20	​	*
Gathering and transportation costs	​	$	0.83	​	$	0.62	​	$	0.21	​	34%
Accretion of asset retirement obligations	​	$	0.04	​	$	0.04	​	$	—	​	*
Depreciation, depletion, and amortization	​	$	0.31	​	$	0.33	​	$	(0.02)	​	(6)%
Exploration and impairment	​	$	—	​	$	—	​	$	—	​	*
General and administrative	​	$	0.43	​	$	0.31	​	$	0.12	​	39%
Accretion of right of use liabilities	​	$	—	​	$	—	​	$	—	​	*
Total	​	$	2.33	​	$	1.77	​	​	​	​	​

*

Percentage not meaningful

Lease operating and workover

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

​	Six Months Ended June 30,												​	​	​	​	​
​	2022						2021						$ Change			% Change
(In thousands, other than percentages and average costs)	Amount			Per Mcfe			Amount			Per Mcfe			​	​	​	​	​
Lease operating expenses	​	$	44,091	​	$	0.37	​	$	37,907	​	$	0.31	​	$	6,184	​	16%
Workover expenses	​	​	1,242	​	$	0.01	​	​	2,608	​	$	0.02	​	​	(1,366)	​	(52)%
Total lease operating and workover expense	​	$	45,333	​	$	0.38	​	$	40,515	​	$	0.33	​	$	4,818	​	12%

Lease operating and workover expenses were $45.3 million, or $0.38 per Mcfe, for the six months ended June 30, 2022, which was an increase of $4.8 million, or 12%, from $40.5 million, or $0.33 per Mcfe, for the six months ended June 30, 2021. The increase in lease operating and workover during the first six months of 2022 compared to the same period in 2021 was primarily driven by a $2.8 million increase in field employee salaries, a $1.1 million increase in disposal costs, and approximately $0.9 million of individually immaterial net increases in other direct production costs incurred in connection with our operations at the 2020 Barnett Properties.

Taxes other than income

Taxes other than income were $41.0 million, or $0.34 per Mcfe for the six months ended June 30, 2022, which was an increase of $24.3 million from $16.7 million, or $0.14 per Mcfe, for the six months ended June 30, 2021. The increase in taxes other than income for the six months ended June 30, 2022 compared to the same period in 2021 was due primarily to increased natural gas and NGL production taxes associated with our operations at the 2020 Barnett Properties. These 2020 Barnett Properties are subject to certain ad valorem and severance taxes which are not applicable to our NEPA natural gas properties.

Gathering and transportation

Gathering and transportation expenses were $98.8 million, or $0.83 per Mcfe, for the six months ended June 30, 2022, which was an increase of $22.0 million, from $76.8 million for the six months ended June 30, 2021. The increase in gathering and transportation expenses for the six months ended June 30, 2022 compared to the same period in 2021 was due to gathering and transportation contracts entered into for our 2020 Barnett Properties during the second half of the year ended December 31, 2021. Pursuant to these contracts, fees for gathering and transportation for our Barnett natural gas are incurred prior to transfer

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of control of our natural gas production. The fees for gathering and transportation for our legacy NEPA natural gas are incurred subsequent to transfer of control and thus are included in revenues.

Accretion of asset retirement obligations

Accretion of asset retirement obligations was $5.3 million, or $0.04 per Mcfe, for the six months ended June 30, 2022, which was an increase of $0.4 million, or 8%, from $4.9 million, or $0.04 per Mcfe, for the six months ended June 30, 2021. This increase in accretion of asset retirement obligations for the six months ended June 30, 2022 compared to the same period in 2021 was due to additional accretion of the asset retirement obligations attributed to the 2020 Barnett Properties.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization was $36.8 million, or $0.31 per Mcfe, for the six months ended June 30, 2022, which was a decrease of $4.0 million, or approximately 10%, from $40.8 million, or $0.33 per Mcfe, for the six months ended June 30, 2021. The decrease in depreciation, depletion, and amortization for the six months ended June 30, 2022 on a per Mcfe basis compared to the same period in 2021 was due to an increase in proved reserves, lowering our depletion rate.

Exploration and impairment

Exploration and impairment expenses were zero and $0.03 million for the six months ended June 30, 2022 and 2021, respectively. This decrease in exploration and impairment expenses was due to slightly higher geological and geophysical costs in 2021 related to a completion program in NEPA which began in fiscal year 2020 and continued into 2021 but did not recur in 2022. There were no dry hole costs or impairment expenses incurred in either period.

General and administrative

General and administrative expenses were $51.5 million, or $0.43 per Mcfe,for the six months ended June 30, 2022, which was an increase of $13.5 million, or 36%, from $38.0 million, or $0.31 per Mcfe, for the six months ended June 30, 2021. The increase in general and administrative expenses for the six months ended June 30, 2022 compared to the same period in 2021 was primarily due to the $11.7 million increase in professional service expenses for the six months ended June 30, 2022 relative to those incurred for the same period ended in 2021. Also contributing to this increase was $9.4 million of increased equity-based compensation expense for the six months ended June 30, 2022 compared to the same period in 2021 for our equity-based compensation. Offsetting these increases is a $7.3 million decrease in administrative and IT consulting expenses and approximately $0.2 million of individually immaterial net decreases in other general and administrative expenses.

Other Income and Expenses

Bargain purchase gain.   Bargain purchase gain increased to $163.7 million for the six months ended June 30, 2022 from zero for the six months ended June 30, 2021. The 2022 Exxon Barnett Acquisition resulted in a bargain purchase gain, which was primarily caused by the increase in commodity pricing from the date the acquisition was originally negotiated through the closing date. Because the value of the purchase consideration transferred was less than the fair value of the assets acquired and liabilities assumed as of the closing date of the Exxon Barnett Acquisition, we recognized a bargain purchase gain for the difference.

(Loss) gain on contingent consideration liabilities.   We recognized a loss on contingent consideration liabilities accruing as an earnout under the agreement for the Devon Barnett Acquisition of $31.9 million during the six months ended June 30, 2022, which was a decrease of $83.4 million from $115.3 million for the six months ended June 30, 2021. This fluctuation is due to increases in forward curve commodity pricing for natural gas (NYMEX) and oil (WTI) assumptions used in the Monte Carlo simulations increasing the fair market value during the six months ended June 30, 2022 relative to the same period in 2021. The increase in the liabilities is reflected as the (loss) gain on contingent liabilities line of the income statement.

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Gain on settlement of litigation.   Gain on settlement of litigation increased to $16.9 million for the six months ended June 30, 2022 from zero for the six months ended June 30, 2021 due to the settlement of a dispute between us and an operator related to a midstream gathering system. We agreed to settle with the operator in February 2022, receiving $35.0 million in the settlement. Of the $35.0 million received, $18.1 million was deemed the collection of accounts receivable. The remaining $16.9 million has been recognized as a gain on settlement of litigation on our consolidated statement of operations.

Interest expense.   Interest expense was $6.7 million for the six months ended June 30, 2022, which was an increase of $6.4 million from $0.3 million for the six months ended June 30, 2021. The increase in interest expense for the six months ended June 30, 2022 was driven by our increased outstanding debt balances as of June 30, 2022 relative to the outstanding debt balance as of June 30, 2021.

Income tax benefit.   Income tax benefit was $24.9 million for the six months ended June 30, 2022, which was a change of $13.7 million from an income tax benefit of $38.6 million for the six months ended June 30, 2021. The period-over-period change was due primarily to the recording of deferred tax assets created by the increase of our commodity derivative liabilities during the six months ended June 30, 2022.

Loss from equity affiliates.   Loss from equity affiliates was approximately $24.0 million for the six months ended June 30, 2022, which was a change from zero for the six months ended June 30, 2021. Loss from equity affiliates is related to our investment in, and our proportionate share in the losses of, the BKV-BPP Power Joint Venture, which we entered into in November 2021.

Comparison of the Years Ended December 31, 2021 and 2020

Operating Revenues

Our operating revenues include revenues from the sale of natural gas, NGLs and oil, non-operated midstream revenues, gains and loss on our derivative contracts, marketing revenues, and other revenues. The following table provides information on our revenues:

​	Year Ended December 31,
(In thousands)	2021			2020			$ Change			% Change
Revenues	​	​	​	​	​	​	​	​	​	​	​
Natural gas revenues	​	$	597,050	​	$	101,758	​	$	495,292	​	*
NGL revenues	​	​	225,135	​	​	11,952	​	​	213,183	​	*
Oil revenues	​	​	7,560	​	​	1,333	​	​	6,227	​	*
Non-operated midstream revenues, net	​	​	6,917	​	​	7,458	​	​	(541)	​	(7)%
Derivative (losses) gains, net	​	​	(383,847)	​	​	20,755	​	​	(404,602)	​	*
Marketing revenues	​	​	52,616	​	​	—	​	​	52,616	​	*
Other	​	​	251	​	​	33	​	​	218	​	*
Total revenues and other operating income	​	$	505,682	​	$	143,289	​	​	​	​	​

*

Percentage not meaningful

Natural gas revenues

Our natural gas revenues increased by approximately $495.3 million to $597.1 million for the year ended December 31, 2021 from $101.8 million for the year ended December 31, 2020. Higher production volumes during the year ended December 31, 2021 accounted for a $95.1 million increase in year-over-year revenues (calculated as the change in year-to-year volumes times the prior year average price), due to an increase driven by inclusion of a full year of production from our 2020 Barnett Assets during the year ended December 31, 2021. Changes in commodity prices, excluding the effects of derivative settlements, accounted for an approximate $400.2 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

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NGL revenues

Our NGL revenues increased by approximately $213.2 million to $225.1 million for the year ended December 31, 2021 from $12.0 million for the year ended December 31, 2020. Higher production volumes during the year ended December 31, 2021 accounted for a $33.8 million increase in year-over-year revenues (calculated as the change in year-to-year volumes times the prior year average price), due to an increase driven by inclusion of a full year of production from our 2020 Barnett Assets during the year ended December 31, 2021. Changes in commodity prices, excluding the effects of derivative settlements, accounted for an approximate $179.4 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Oil revenues

Our oil revenues increased by approximately $6.2 million to $7.6 million for the year ended December 31, 2021 from $1.3 million for the year ended December 31, 2020. Higher production volumes during the year ended December 31, 2021 accounted for a $4.4 million increase in year-over-year revenues (calculated as the change in year-to-year volumes times the prior year average price), due to an increase driven by inclusion of a full year of production from our 2020 Barnett Assets during the year ended December 31, 2021. Changes in commodity prices, excluding the effects of derivative settlements, accounted for an approximate $1.8 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Non-operated midstream revenues, net

Our non-operated midstream revenues decreased by approximately $0.5 million, or 7%, to $6.9 million for the year ended December 31, 2021 from $7.5 million for the year ended December 31, 2020. This decrease was primarily due to decreases in the associated production of natural gas properties the midstream assets support.

Derivative (losses) gains, net

For the year ended December 31, 2021, we had a loss on derivative contracts of $383.8 million compared with a gain on derivative contracts of $20.8 million for the year ended December 31, 2020. The loss in 2021 is attributable to increases in underlying commodity prices, which resulted in higher realized and unrealized losses on derivative contracts.

Marketing revenues

Our marketing revenues increased by approximately $52.6 million, to $52.6 million for the year ended December 31, 2021 from zero for the year ended December 31, 2020. Our marketing revenues are derived under our marketing agreement with a third party pursuant to which we receive a fixed percentage of all net income realized in the resale of our and other producers’ hydrocarbons. The increase in marketing revenues was primarily due to the pricing volatility surrounding the events of Winter Storm Uri, which resulted in $48.7 million of revenues for the year ended December 31, 2021.

Other revenues

We generate a portion of our revenues from other sources including surface and midstream operations. Our midstream and surface operations primarily support our own exploration and production operations, with revenues generated primarily from fees charged for surface and midstream services, including transportation, freshwater sourcing and disposal and other services to us and our affiliates and, to a lesser extent, third parties. Our other revenues were approximately $0.3 million for the year ended December 31, 2021 as compared to a negligible amount for the year ended December 31, 2020. The increase was minimal year over year.

Operating Expenses

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

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​	Year Ended December 31,
(In thousands)	2021			2020			$ Change			% Change
Operating Expense	​	​	​	​	​	​	​	​	​	​	​
Lease operating and workover	​	$	88,105	​	$	31,260	​	$	56,845	​	182%
Taxes other than income	​	​	45,650	​	​	5,151	​	​	40,499	​	*
Gathering and transportation costs	​	​	173,587	​	​	—	​	​	173,587	​	*
Accretion of asset retirement obligations	​	​	10,030	​	​	3,211	​	​	6,818	​	212%
Depreciation, depletion, and amortization	​	​	81,986	​	​	83,388	​	​	(1,402)	​	(2)%
Exploration and impairment	​	​	34	​	​	560	​	​	(526)	​	(94)%
General and administrative	​	​	85,740	​	​	29,442	​	​	56,298	​	191%
Accretion of right of use liabilities	​	​	227	​	​	184	​	​	43	​	23%
Total operating expense	​	$	485,359	​	$	153,196	​	​	​	​	​
Average Costs per Mcfe	​	​	​	​	​	​	​	​	​	​	​
Lease operating and workover	​	$	0.36	​	$	0.28	​	$	0.08	​	28%
Taxes other than income	​	$	0.19	​	$	0.05	​	$	0.14	​	*
Gathering and transportation costs	​	$	0.71	​	$	—	​	$	0.71	​	*
Accretion of asset retirement obligations	​	$	0.04	​	$	0.03	​	$	0.01	​	42%
Depreciation, depletion, and amortization	​	$	0.33	​	$	0.75	​	$	(0.41)	​	(55)%
Exploration and impairment	​	$	—	​	$	0.01	​	$	—	​	(97)%
General and administrative	​	$	0.35	​	$	0.26	​	$	0.09	​	32%
Accretion of right of use liabilities	​	$	—	​	$	—	​	$	—	​	(44)%
Total	​	$	1.98	​	$	1.38	​	​	​	​	​

*

Percentage not meaningful

Lease operating and workover

The following table summarizes our components of lease operating expenses for the years ended December 31, 2021 and 2020:

​

Year Ended December 31,

Change

​

2021

2020

Dollars

Percentage

​

Amount

Per Mcfe

Amount

Per Mcfe

​

(In thousands)

​

​

​

(In thousands)

​

​

​

(In thousands)

​

​

Lease operating expenses

​

$

84,303

​

$

0.34

​

$

30,130

​

$

0.27

​

$

54,173

​

179%

Workover expenses

​

​

3,802

​

​

0.02

​

​

1,130

​

​

0.01

​

​

2,672

​

236%

Total lease operating and workover expense

​

$

88,105

​

$

0.36

​

$

31,260

​

$

0.28

​

$

56,845

​

182%

Lease operating and workover expenses were $88.1 million, or $0.36 per Mcfe, for the year ended December 31, 2021, which was an increase of $56.8 million, or 182%, from $31.3 million, or $0.28 per Mcfe, for the year ended December 31, 2020. The increase in lease operating and workover during 2021 compared to 2020 was due to the acquisition of our Barnett natural gas properties that we acquired in the October 2020 Devon Barnett Acquisition (the “2020 Barnett Properties”), which are included for the full year ended December 31, 2021, compared to three months during the year ended December 31, 2020.

Taxes other than income

Taxes other than income were $45.7 million, or $0.19 per Mcfe, for the year ended December 31, 2021, which was an increase of $40.5 million from $5.2 million, or $0.05 per Mcfe, for the year ended December 31,

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2020. The increase in taxes during 2021 compared to 2020 was due to our acquisition of the 2020 Barnett Properties, which are included for the full year ended December 31, 2021, compared to three months during the year ended December 31, 2020. These 2020 Barnett Properties are subject to certain ad valorem and severance taxes which are not applicable to our NEPA natural gas properties.

Gathering and transportation

Gathering and transportation expenses were $173.6 million, or $0.71 per Mcfe, for the year ended December 31, 2021, which was an increase of $173.6 million, from zero for the year ended December 31, 2020. The increase in gathering and transportation during 2021 compared to 2020 was due to new contracts entered into for our 2020 Barnett Properties during the year ended December 31, 2021. Pursuant to these new contracts, fees for gathering and transportation for our Barnett natural gas are incurred prior to transfer of control of our natural gas production. The fees for gathering and transportation for our legacy NEPA natural gas are incurred subsequent to transfer of control and thus are included in revenues.

Accretion of asset retirement obligations

Accretion of asset retirement obligations was $10.0 million, or $0.04 per Mcfe, for the year ended December 31, 2021, which was an increase of $6.8 million, or 212%, from $3.2 million, or $0.03 per Mcfe, for the year ended December 31, 2020. The increase in accretion of asset retirement obligations during 2021 compared to 2020 was due to additional accretion associated with the additional asset retirement obligations associated with the 2020 Barnett Properties.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization was $82.0 million, or $0.33 per Mcfe, for the year ended December 31, 2021, which was a decrease of $1.4 million, or 2%, from $83.4 million, or $0.75 per Mcfe, for the year ended December 31, 2020. The decrease in depreciation, depletion, and amortization during 2021 on a per Mcfe basis compared to 2020 was due to an increase in proved reserves, lowering our depletion rate.

Exploration and impairment

Exploration and impairment expenses were $0.03 million, or less than $0.01 per Mcfe, for the year ended December 31, 2021, which was a decrease of $0.5 million, or 94%, from $0.6 million, or $0.01 per Mcfe, for the year ended December 31, 2020. The decrease in exploration and impairment during 2021 compared to 2020 was due to higher geological and geophysical costs in 2020 related to a completion program in NEPA during 2020 that did not recur in 2021. There were no dry hole costs or impairment expenses incurred in either period.

General and administrative

General and administrative expenses were $85.7 million, or $0.35 per Mcfe, for the year ended December 31, 2021, which was an increase of $56.3 million, or 191%, from $29.4 million, or $0.26 per Mcfe, for the year ended December 31, 2020. The increase in general and administrative during 2021 compared to 2020 was primarily due to equity-based compensation expense for our equity-based compensation plan introduced during the year ended December 31, 2021, and integration costs related to the Devon Barnett Acquisition incurred during the year ended December 31, 2021 after the conclusion of our transition services agreement with Devon Energy.

Other income and expenses

(Loss) gain on contingent consideration liabilities.   We recognized a loss on contingent consideration liabilities of $195.0 million for the year ended December 31, 2021, which was an increase of $202.1 million from a $7.1 million gain for the year ended December 31, 2020. This fluctuation is due to increases in forward curve commodity pricing for natural gas (NYMEX) and oil (WTI) assumptions used in the Monte Carlo simulations increasing the fair market value as of December 31, 2021 as compared to December 31, 2020. The increase in the liabilities is reflected as the (loss) gain on contingent consideration liabilities line of the

120

income statement. These contingent consideration liabilities were incurred pursuant to the terms of an earnout provision under the Devon Barnett Acquisition purchase agreement.

Interest expense.   Interest expense was $2.1 million for the year ended December 31, 2021, which was an increase of $0.4 million, or 25%, from $1.7 million for the year ended December 31, 2020. The change in interest expense during 2021 compared to 2020 was due to the outstanding balances on our loans with BNAC the year ended December 31, 2021 exceeding the outstanding balances during the year ended December 31, 2020.

Income tax benefit (expense).   Income tax benefit was $40.5 million for the year ended December 31, 2021, which was a change of $79.5 million, or 204%, from an income tax expense of $39.0 million for the year ended December 31, 2020. The change to an income tax benefit during 2021 from income tax expense in 2020 was due to the recording of deferred tax assets created by the increase on our commodity derivative liabilities and contingent consideration during the year ended December 31, 2021.

Income from equity affiliates.   Income from equity affiliates was approximately $0.9 million for the year ended December 31, 2021, which was an increase from zero for the year ended December 31, 2020. Income from equity affiliates is related to the management fees received from the BKV-BPP Power Joint Venture and represents the entire increase from the prior year, as we entered into the BKV-BPP Power Joint Venture in 2021.

Liquidity and Capital Resources

Capital Commitments

Our primary needs for cash are to fund our upstream development, midstream, power and CCUS projects, fund operations and capital expenditures, fund acquisitions, fund asset retirement obligations, cover any debt interest or minimum volume commitment obligations, paydown debt, and return capital to stockholders. Our primary uses of cash during 2021 and 2020 were to fund our Devon Barnett Acquisition, our BKV-BPP Power Joint Venture and the development of our natural gas properties. We also used operating cash flows for the payment of a special dividend to our common stockholders, operating costs, and general and administrative costs. The primary use of the cash received from BNAC was to fund the redemption of our outstanding preferred stock.

During the six months ended June 30, 2022, capital expenditures for development of natural gas properties were $77.3 million. During the year ended December 31, 2021, capital expenditures for development of natural gas properties were $63.9 million. Capital expenditures for our operated properties are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for natural gas and NGLs, the availability of equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We will continue to monitor commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.

Our adjusted capital budget for 2022 is approximately $266.0 million, of which we had expended approximately $78.1 million as of June 30, 2022.

Our operating leases consist of leases for office space and compressors. We do not have finance leases. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Instead, the short-term leases are recognized in expenses on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms generally being one year, which are not recognized as part of the lease right-of-use (ROU) assets or liabilities as they are not reasonably certain to be exercised. The exercise of lease renewal options is at our discretion.

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As of December 31, 2021, our undiscounted minimum cash payment obligations for operating lease liabilities are as follows (in thousands):

2022	$	11,241
2023	​	947
2024	​	959
2025	​	972
2026	​	848
Thereafter	​	1,664
Total undiscounted future lease payments	$	16,631
Present value adjustment	​	(1,226)
Net operating lease liabilities	$	15,405

On August 4, 2022, we entered an amendment to our ISDA Master Agreement with a counterparty to our derivative contracts pursuant to which we agreed to terminate or novate, at our election, at least $100.0 million of our derivative contracts with the counterparty. As of September 9, 2022, we terminated derivative contracts of $100.2 million with the counterparty to satisfy this requirement. In connection with such termination, we are required to make cash payments to the counterparty in an aggregate amount of $100.2 million, of which $30.0 million was paid in September 2022, an additional $30.0 million is due and payable before October 31, 2022 and the remaining $40.2 million must be paid by November 30, 2022. We intend to make the remaining payments with cash flows from operations, inclusive of our recent Exxon Barnett Acquisition. See “Note 14  — Commitments and Contingencies” to our unaudited condensed consolidated financial statements included elsewhere in this prospectus for additional information regarding this agreement.

Capital Resources

Historically our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations and loans with our majority stockholder, BNAC. We also enter into derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty and stability to our cash flows. We currently believe that we will be able to fully fund our 2022 capital budget with cash on hand and cash flows from operations. The following table summarizes our cash flows for the six months ended June 30, 2022 and 2021, as well as the years ended December 31, 2021, and 2020 (in thousands):

​	Six Months Ended June 30,						Year Ended December 31,
​	2022			2021			2021			2020
Net cash provided by (used in) operating activities	​	$	160,758	​	$	217,686	​	$	358,133	​	$	(7,405)
Net cash (used in) investing activities	​	​	(705,791)	​	​	(14,164)	​	​	(161,858)	​	​	(513,992)
Net cash provided by (used in) financing activities	​	​	597,000	​	​	(130,820)	​	​	(79,053)	​	​	442,723
Net increase (decrease) in cash and cash equivalents	​	$	51,967	​	$	72,702	​	$	117,222	​	$	(78,674)

Cash flows provided by (used in) operating activities.   Net cash provided by operating activities was $160.8 million for the six months ended June 30, 2022, compared to $217.7 million of net cash provided by operating activities for the six months ended June 30, 2021. Net cash provided by operating activities decreased in 2022 primarily due to our net income position as of June 30, 2022 versus our loss position as of June 30, 2021, cash paid for settlement of contingent consideration, increased loss from equity affiliates, increases in commodity prices before and after the effects of settled commodity derivatives, and increased equity-based compensation expense.

Net cash provided by operating activities was $358.1 million for the year ended December 31, 2021, compared to $7.4 million of net cash used in operating activities for the year ended December 31, 2020. Net

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cash provided by operating activities increased in 2021 primarily due to increases natural gas and NGL volumes produced, increases in commodity prices both before and after the effects of settled commodity derivatives, changes in the fair values of derivative and contingent consideration liability balances, and decreased cash utilized for working capital.

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

Cash flows used in investing activities.   Net cash used in investing activities increased from $14.2 million for the six months ended June 30, 2021 to $705.8 million for the six months ended June 30, 2022. Driving $627.5 million of this increase is our acquisition of certain operated and non-operated interests in proved reserves and certain midstream support assets in the Exxon Barnett Acquisition. Approximately $77.3 million of the year-to-date cash outflow for the six months ended June 30, 2022 is due to our increased expenditures in development of natural gas properties and investments in other property and equipment.

Net cash used in investing activities decreased from $514.0 million for the year ended December 31, 2020 to $161.9 million for the year ended December 31, 2021. The primary driver of the decreased cash outflow in 2021 relative to 2020 was our decreased investment in natural gas properties for production purposes in 2021. In 2021, we invested approximately $2.5 million in properties while in 2020, we invested approximately $501.7 million.

Contributing to the $161.9 million cash outflow in 2021 was our initial investment in BKV-BPP Power. In November of 2021, BKV-BPP Power purchased an operational power plant in Texas. The remaining activity in 2021 included $63.9 million attributable to development activities and $7.6 million for developed property and undeveloped acreage acquisition. Development activities have and are anticipated to continue to be funded through cash flows from operations.

Cash flows provided by (used in) financing activities.   Net cash provided by financing activities changed from a $130.8 million outflow for the six months ended June 30, 2021 to a $597.0 million inflow for the six months ended June 30, 2022. The primary driver of the current period inflow is the $570.0 million of borrowings under the Term Loan Credit Agreement dated June 16, 2022. We also received $75.0 million of proceeds in connection with a related party note payable, which was offset by $50.0 million of repayments to the related party, $60.0 million of advances received in connection with the Company's credit facility, which was offset by $30.0 million of repayments on said facility, and $19.7 million of payments of contingent consideration. The remaining $8.3 million of the fluctuation consists primarily of debt issuance cost payments and net share settlements.

Net cash used in financing activities was $79.1 million for the year ended December 31, 2021, compared to net cash flows provided by financing activities of $442.7 million for the year ended December 31, 2020. During the year ended December 31, 2021, we paid dividends to common stock stockholders of $88.1 million and dividends to preferred stockholders of $10.3 million. The Company elected to exercise its redemption option on all outstanding shares of preferred stock and the associated shares of common stock for $122.4 million, and puttable minority interest shares of common stock for $2.8 million. In addition, the Company issued common stock through the 2022 ESPP (as defined herein) and received proceeds of $3.2 million from shares sold under the ESPP. These cash outflows are partially offset by $166.0 million of proceeds received under the term loans from BNAC.

Working Capital

As of June 30, 2022, we had cash and cash equivalents of $169.2 million and restricted cash of $17.5 million, compared to $90.1 million of cash and cash equivalents and zero restricted cash as of June 30, 2021. Our net working capital deficit was $399.1 million as of June 30, 2022, compared to a deficit of $107.5 million as of June 30, 2021.

As of December 31, 2021, we had a cash and cash equivalents balance of $134.7 million, compared to $17.4 million as of December 31, 2020, and a net working capital deficit of $269.0 million as of December 31,

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2021, compared to a net working capital surplus of $70.4 million as of December 31, 2020. As of December 31, 2021, our working capital deficit included $166.0 million of term loans under the $116 Million Loan Agreement and the $50 Million Loan Agreement that were due to BNAC by December 31, 2022.

Our working capital fluctuates based on the timing of cash collections on accounts receivable and payments on accounts payable. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. As of June 30, 2022, we had a working capital deficit of $399.1 million, largely driven by our current derivative liabilities of $242.3 million, current portion of long-term debt of $141.9 million, and contingent consideration payable of $62.5 million. The payments relating to the contingent consideration and term loans are due in January and June of 2023, respectively. We intend to make these payments with cash flows from operations and availability under existing and newly entered into debt facilities. The current derivative liabilities will settle monthly during the twelve-month period ending June 30, 2023 in conjunction with the corresponding commodity sales, other than the $100.2 million cash payment to the counterparty to certain of our derivative contracts discussed below. We intend to use the proceeds from the corresponding commodity sales to pay the settlements of the derivative liabilities. As of December 31, 2021, we had a working capital deficit of $269.0 million primarily driven by our term loans with BNAC of $166.0 million under the $116 Million Loan Agreement and the $50 Million Loan Agreement, contingent consideration payable of $65.0 million, and derivative settlements payable of $91.2 million. Due to our derivative positions, outstanding loans to BNAC and our business being capital intensive, we may incur working capital deficits in the future.

On August 4, 2022, we entered into an amendment to our ISDA Master Agreement with the counterparty to certain of our derivative contracts pursuant to which we agreed to terminate or novate, at our election, at least $100.0 million of our derivative contracts. As of September 9, 2022, we terminated derivative contracts of $100.2 million with the counterparty to satisfy this requirement. In connection with such termination, we are required to make cash payments to the counterparty in an aggregate amount of $100.2 million, of which $30.0 million was paid in September 2022, an additional $30.0 million is due and payable before October 31, 2022 and the remaining $40.2 million must be paid by November 30, 2022. We intend to make the remaining payments with cash flows from operations. See “Note 14  — Commitments and Contingencies” to our unaudited condensed consolidated financial statements included elsewhere in this prospectus for additional information regarding this agreement.

On September 14, 2022, we received an advance of (i) $45.0 million in aggregate principal amount under our OCBC Credit Facility and (ii) $75.0 million in aggregate principal amount under our Revolving Credit Agreement.

We believe our cash flow from operations, cash on hand and borrowings under our Revolving Credit Facilities will provide sufficient liquidity to fund our operations, capital expenditures, interest expense and debt repayments and commodity derivatives that are expected to settle during the next 12 months.

We expect that our pace of development, production volumes, commodity prices and differentials to NYMEX prices for our oil and natural gas production will be the largest variables affecting our working capital.

Loan Agreements and Credit Facilities

Intercompany Loan Agreements

On December 17, 2019, BKV O&G entered into a Loan Agreement (the “$10 Million Loan Agreement”) with BNAC, a related party, which allowed for a single drawdown in the amount of $10.0 million. On June 23, 2020, we entered into a novation agreement with BKV O&G and BNAC, which transferred all of BKV O&G’s rights and obligations under the $10 Million Loan Agreement to us. Also on June 23, 2020, we entered into a First Amendment to the Loan Agreement (the “First Amendment to $10 Million Loan Agreement”). On July 1, 2020, we borrowed $10.0 million thereunder for working capital purposes. The First Amendment to $10 Million Loan Agreement bore interest at a rate calculated monthly based on the outstanding principal balance as of the first of the month at the rate no less than the cost of funding of BNAC. Interest was payable on a monthly basis. During the year ended December 31, 2020, we paid $0.2 million in interest on

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the loan, and on December 31, 2020, we repaid $5.0 million of the outstanding principal amount of the loan. During the year ended December 31, 2021, we paid $0.1 million in interest on the loan and repaid the remaining outstanding principal amount of the loan in full. The First Amendment to $10 Million Loan Agreement terminated on June 20, 2021.

On September 28, 2020, we borrowed $119.0 million under a Loan Agreement (the “$119 Million Loan Agreement”) with BNAC to partially fund the Devon Barnett Acquisition and for working capital. The $119 Million Loan Agreement bore interest at six-month LIBOR plus 5.25% per annum and was payable on a semi-annual basis. During the year ended December 31, 2020, we paid $1.5 million in interest on the loan, and on December 16, 2020, we repaid $100.0 million of the original outstanding principal amount of the loan. During the year ended December 31, 2021, we paid $0.2 million in interest on the loan, and on March 15, 2021, we repaid the remaining outstanding principal amount of the loan in full. The $119 Million Loan Agreement terminated concurrently with repayment of the remaining principal amount.

On November 8, 2021, we borrowed $50.0 million under a Loan Agreement (the “$50 Million Loan Agreement”) with BNAC. On January 11, 2022, we repaid $15.0 million of the outstanding principal amount of the loan. On June 1, 2022, we paid $1.3 million in interest on the loan and repaid the remaining $35.0 million of the outstanding principal amount of the loan in full. The $50 Million Loan Agreement terminated concurrently with repayment of the remaining principal amount.

Subordinated Intercompany Loan Agreements

On October 14, 2021, we borrowed $116.0 million under a Loan Agreement (the “$116 Million Loan Agreement”) with BNAC to redeem all of the outstanding preferred and common stock of the company owned by OCM BKV Holdings, LLC, an affiliate of Oaktree Capital Management L.P. Following such redemption, we do not have any issued and outstanding preferred stock. As of December 31, 2021, the full $116.0 million balance of the loan remained outstanding. On June 15, 2022, we entered into an Amended and Restated Loan Agreement (the “$116 Million A&R Loan Agreement”), which amended and restated the $116 Million Loan Agreement to, among other things, subordinate the $116.0 million term loan owed to BNAC thereunder to the term loans we borrowed under the Term Loan Credit Agreement. On August 24, 2022, BNAC entered into a Subordination Agreement with Bangkok Public Company, Limited, New York Branch, which subordinated the $116.0 million term loan owed to BNAC to the revolving loans at any time outstanding under the Revolving Credit Agreement (the "August 2022 Subordination Agreement").

On March 10, 2022, we borrowed $75.0 million under a Loan Agreement (the “$75 Million Loan Agreement”) with BNAC to fund the deposit for the Exxon Barnett Acquisition. On June 15, 2022, we entered into an Amended and Restated Loan Agreement (the “$75 Million A&R Loan Agreement” and, together with the $116 Million A&R Loan Agreement, the “Subordinated Intercompany Loan Agreements”), which amended and restated the $75 Million Loan Agreement to, among other things, subordinate the $75.0 million term loan owed to BNAC thereunder to the term loans we borrowed under the Term Loan Credit Agreement. The August 2022 Subordination Agreement provides for the subordination of the $75.0 million term loan owed to BNAC thereunder to the revolving loans at any time outstanding under the Revolving Credit Agreement.

Our payment obligations under the Subordinated Intercompany Loan Agreements are unsecured and subordinated to our payment obligations under the Term Loan Credit Agreement and the Revolving Credit Agreement. The Subordinated Intercompany Loan Agreements bear interest at one-year term SOFR plus 5.25%. Interest on the term loans is payable annually, and the loans are repayable on December 31, 2027, in each case unless such payment is prohibited by the subordination terms of the Term Loan Credit Agreement. Subject to such subordination provisions, we are permitted to prepay the term loans at any time, with no prepayment premium.

The Subordinated Intercompany Loan Agreements include covenants that, among other things, prohibit us or any of our subsidiaries from merging, incurring liens or incurring any additional indebtedness or guarantees without consent from the lender. The Subordinated Intercompany Loan Agreements include financial covenants that require us to: (1) maintain a net worth (as defined in the Subordinated Intercompany Loan Agreements, but generally meaning total assets minus total liabilities) of at least $800.0 million at all times; and (2) not permit our trailing twelve month net borrowings to EBITDAX (as defined) in the

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Subordinated Intercompany Loan Agreements, but generally meaning the ratio of debt (minus cash) to earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses) ratio to exceed 3.0 to 1.0 at any time. We are in compliance with all associated covenants under the $116 Million Loan Agreement and the $75 Million Loan Agreement as of June 30, 2022.

Term Loan Credit Agreement

On June 16, 2022, we entered into a Credit Agreement (the “Term Loan Credit Agreement”) with a syndicate of banks and Bangkok Bank Public Company Limited (New York Branch), as the administrative agent. The Term Loan Credit Agreement includes $600.0 million of commitments for term loans used solely to fund a portion of the purchase price for the Exxon Barnett Acquisition. On June 30, 2022, we borrowed $570.0 million of term loans under the Term Loan Credit Agreement to partially fund the Exxon Barnett Acquisition.

The term loans mature five years after their initial incurrence and require the prepayment of 20% of their original principal amount on each anniversary of their initial incurrence. Mandatory prepayments are required for casualty losses and asset dispositions in amounts equal to the net proceeds we receive in connection with such casualty loss or asset disposition above an aggregate $25.0 million during the term of the facility. In addition, we are required to prepay the term loans with any cash proceeds we receive from Banpu to cure a financial covenant default. The term loans are subject to a prepayment premium of 2.0% for optional prepayments, mandatory prepayments due to asset dispositions, and certain other mandatory prepayments.

The obligations under the Term Loan Credit Agreement are unsecured and guaranteed on an unsecured basis by all of our current and future subsidiaries. Loans under the Term Loan Credit Agreement bear interest at six-month term SOFR plus a credit spread adjustment of 0.10%, plus 4.75% per annum. Interest is payable on the last day of each interest period and at maturity. We are obligated to pay certain fees to the lenders and administrative agent under the Term Loan Credit Agreement, including commitment fees until the term loans are funded or the commitments are terminated.

The term loans were funded upon the closing of the Exxon Barnett Acquisition and satisfaction of other customary conditions.

In addition to customary reporting requirements for similarly situated companies, we are required to provide to the administrative agent, and receive its approval of, our annual budget and, commencing with the quarter ending March 31, 2023, each quarterly cash forecast for the succeeding 12-month period.

The Term Loan Credit Agreement contains various restrictive covenants that, among other things, limit our ability and the ability of our subsidiaries to: incur indebtedness (with an exception allowing us to incur, subject to certain limitations and after this initial public offering, up to $200.0 million of unsecured debt for working capital purposes); incur liens; acquire or merge with any other company; sell assets or equity interests of our subsidiaries; make investments (other than direct investments in oil and gas properties and other assets in permitted lines of business); pay dividends or make other restricted payments (see “Dividend Policy” and the next paragraph for further information regarding the permitted dividends under the Term Loan Credit Agreement); change our lines of business; enter into speculative hedge agreements; enter into transactions with affiliates; own any subsidiary that is not organized in the United States; prepay any debt under the Subordinated Intercompany Loan Agreements; engage in certain marketing activities; and allow, on a net basis, gas imbalances, take-or-pay or other prepayments with respect to our proved oil and gas properties.

The Term Loan Credit Agreement permits us to pay dividends to our stockholders only once each year, and requires as a condition to any such dividend that (1) we have earned sufficient free cash flow (as defined in the Term Loan Credit Agreement), (2) our pro forma available cash is greater than $100.0 million, and (3) our adjusted stockholders’ equity (as defined generally to mean our stockholders’ equity as determined in accordance with GAAP as of June 30 of the relevant year, adjusted to exclude certain unrealized earnout obligations and unrealized gains or losses resulting from hedging agreements and the application of the applicable accounting standard for the hedging instruments) is not less than $800.0 million.

Beginning with the fiscal quarter ending June 30, 2023, the Term Loan Credit Agreement will require us to always hedge not less than 50% of projected production from our proved developed producing reserves

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for the following 12 months and not less than 25% of the projected production from our proved developed producing reserves for the period beginning 13 months after the measurement date and ending 24 months after such date.

The Term Loan Credit Agreement also includes financial covenants that require us to maintain:

•

on a semi-annual basis, a minimum asset coverage ratio (as defined in the Term Loan Credit Agreement, but generally meaning the ratio of the PV-10 value of our proved oil and gas properties to our funded debt) of 2.00 to 1.00;

•

on a quarterly basis, a maximum net leverage ratio (as defined in the Term Loan Credit Agreement, but generally meaning the ratio of total funded debt, minus available cash of up to $100.0 million, to our earnings before interest, taxes, depreciation, depletion and amortization) of 2.50 to 1.00; and

•

on a quarterly basis, a minimum fixed charge coverage ratio (as defined in the Term Loan Credit Agreement, but generally meaning the ratio of our earnings before interest, taxes, depreciation, depletion and amortization to certain fixed charges) of 1.30 to 1.00.

The Term Loan Credit Agreement includes customary equity cure rights that will enable us, in Banpu’s sole discretion, to cure certain breaches of the maximum net leverage ratio covenant or the minimum fixed charge coverage ratio covenant.

The Term Loan Credit Agreement generally includes customary events of default for a syndicated credit facility, some of which allow for an opportunity to cure. In addition, the Term Loan Credit Agreement includes an event of default if there is a material adverse change in our business. If, after this initial public offering, Banpu and its wholly owned subsidiaries cease to own at least 51% of our equity interests, or if any such holder allows 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. If an event of default relating to bankruptcy or other insolvency events occurs, the term loans will immediately become due and payable; if any other event of default exists, the administrative agent or the requisite lenders will be permitted to accelerate the maturity of the term loans.

Revolving Credit Facilities

We are party to a $55.0 million uncommitted credit facility with Oversea-Chinese Banking Corporation Limited, which includes a $25.0 million sublimit for the issuance of standby letters of credit (the “OCBC Credit Facility”). As of October 19, 2022, $45.0 million in aggregate principal amount was outstanding under the OCBC Credit Facility. We are also party to a $25.0 million uncommitted credit facility with Standard Chartered Bank, which includes a $15.0 million sublimit for revolving loans (the “SCB Credit Facility” and, together with the OCBC Credit Facility, the “Revolving Credit Facilities”). As of October 19, 2022, $10.0 million in aggregate principal amount was outstanding under the SCB Credit Facility. We use the Revolving Credit Facilities for letters of credit and working capital purposes.

The Revolving Credit Facilities are uncommitted, such that the lender is not obligated to honor any request for a loan or the issuance of a letter of credit thereunder. Our obligations under the Revolving Credit Facilities are repayable upon demand by the applicable lender. The interest rates and fees under the Revolving Credit Facilities can be changed by the applicable lender in its discretion. Certain of our subsidiaries are co-borrowers or guarantors of our obligations under the Revolving Credit Facilities. The obligations under the Revolving Credit Facilities are unsecured.

Revolving Credit Agreement

On August 24, 2022, we entered into the Revolving Credit Agreement with Bangkok Bank Public Company Limited (New York Branch), as the administrative agent and sole initial lender. The Revolving Credit Agreement includes $100.0 million of commitments for unsecured revolving loans used for short-term working capital and operating needs. As of October 19, 2022, $45.0 million in aggregate principal amount was outstanding under the Revolving Credit Agreement.

The revolving loans may be borrowed, repaid and reborrowed during the term of the Revolving Credit Agreement. The Revolving Credit Agreement will mature on September 30, 2027. Mandatory prepayments

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are required at any time the principal amount of outstanding revolving loans exceeds our receivables from the sales of hydrocarbons produced from our oil and gas properties. In addition, we are required to prepay the revolving loans with any cash proceeds we receive from Banpu to cure a financial covenant default to the extent such cash proceeds are in excess of the amount required to be prepaid under the Term Loan Credit Agreement.

The obligations under the Revolving Credit Agreement are unsecured and guaranteed on an unsecured basis by all of our current and future subsidiaries. Loans under the Revolving Credit Agreement bear interest at one, three or six-month term SOFR plus a credit spread adjustment of 0.10%, plus 4.75% per annum. Interest is payable on the last day of each interest period and at maturity. We are obligated to pay certain fees to the lenders and administrative agent under the Revolving Credit Agreement, including commitment fees on the average daily amount of the undrawn portion of the commitments.

Availability of the revolving loans is limited in amount and conditioned upon the administrative agent’s and lenders’ receipt and satisfaction with certain deliverables, including, among other things,

•

receipt by the Administrative Agent of a certificate from us (i) certifying that the amounts owing to the applicable Payees (as such term is defined in the Revolving Credit Agreement, but generally, the payees of obligations incurred by us) have been paid to the respective Payees prior to the date of such borrowing, (ii) certifying and providing calculations that the requested borrowing does not exceed 110% of the sum of (x) amounts owed to such Payees and (y) Specified Royalty Payments (defined as royalty payments to be made by us or any of our subsidiaries to Payees after the date of such proposed borrowing but on or prior to the last day of the month in which such proposed borrowing occurs) and (iii) certifying that we will pay to the applicable Payees any Specified Royalty Payments prior to the last day of the month in which such borrowing occurs;

•

receipt by the Administrative Agent of all documents and/or invoices to be paid by us from the requested borrowing in an amount equal to at least 90% of the requested borrowing; and

•

receipt by the Administrative Agent of a certificate from us certifying (1) as to the estimated receivables from the sales of hydrocarbons from our oil and gas properties on the date of such borrowing and (2) that the amount of item (1) exceeds the sum of the principal amount of all outstanding revolving loans and the aggregate principal amount of the requested borrowing.

In addition to customary reporting requirements for similarly situated companies, we are required to provide to the administrative agent, not later than thirty (30) days prior to the end of each fiscal year, a copy of a cash flow projection for each month in the following fiscal year and not later than 20 days after the end of each month, a summary of actual cash flow for such month.

The Revolving Credit Agreement contains various restrictive covenants that, among other things, limit our ability and the ability of our subsidiaries to: incur indebtedness (with an exception allowing us to incur, subject to certain limitations and after this initial public offering, up to $200.0 million of unsecured debt (including amounts under the Revolving Credit Agreement) for working capital purposes); incur liens; acquire or merge with any other company; sell assets or equity interests of our subsidiaries; make investments (other than investments in oil and gas properties and other assets in permitted lines of business); pay dividends or make other restricted payments (see “Dividend Policy” and the next paragraph for further information regarding the permitted dividends under the Revolving Credit Agreement); change our lines of business; enter into speculative hedge agreements; enter into transactions with affiliates; own any subsidiary that is not organized in the United States; prepay any debt under the Subordinated Intercompany Loan Agreements; engage in certain marketing activities; and allow, on a net basis, gas imbalances, take-or-pay or other prepayments with respect to our proved oil and gas properties.

The Revolving Credit Agreement permits us to pay dividends to our stockholders only once each year and requires as a condition to any such dividend that (1) we have earned sufficient free cash flow (as defined in the Revolving Credit Agreement), (2) our pro forma available cash is greater than $100.0 million and (3) our adjusted stockholders’ equity (as defined generally to mean our stockholders’ equity as determined in accordance with GAAP as of June 30 of the relevant year, adjusted to exclude certain unrealized earnout obligations and unrealized gains or losses resulting from hedging agreements and the application of the applicable accounting standard for the hedging instruments) is not less than $800.0 million.

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Beginning with the fiscal quarter ending June 30, 2023, the Revolving Credit Agreement will require us to always hedge not less than 50% of projected production from our proved developed producing reserves for the following 12 months and not less than 25% of the projected production from our proved developed producing reserves for the period beginning 13 months after the measurement date and ending 24 months after such date.

The Revolving Credit Agreement also includes financial covenants that require us to maintain:

•

on a semi-annual basis, a minimum asset coverage ratio (as defined in the Revolving Credit Agreement, but generally meaning the ratio of the PV-10 value of our proved oil and gas properties to our funded debt) of 2.00 to 1.00;

•

on a quarterly basis, a maximum net leverage ratio (as defined in the Revolving Credit Agreement, but generally meaning the ratio of total funded debt, minus available cash of up to $100.0 million, to our earnings before interest, taxes, depreciation, depletion and amortization) of 2.50 to 1.00; and

•

on a quarterly basis, a minimum fixed charge coverage ratio (as defined in the Revolving Credit Agreement, but generally meaning the ratio of our earnings before interest, taxes, depreciation, depletion and amortization to certain fixed charges) of 1.30 to 1.00.

The Revolving Credit Agreement includes customary equity cure rights that will enable us, in Banpu’s sole discretion, to cure certain breaches of the maximum net leverage ratio covenant or the minimum fixed charge coverage ratio covenant.

The Revolving Credit Agreement generally includes customary events of default for a syndicated credit facility, some of which allow for an opportunity to cure. In addition, the Revolving Credit Agreement includes an event of default if there is a material adverse change in our business. If, after this initial public offering, Banpu and its wholly owned subsidiaries cease to own at least 51% of our equity interests, or if any such holder allows any lien to exist on our equity interests that they own, such event will be an event of default under the Revolving Credit Agreement. If an event of default relating to bankruptcy or other insolvency events occurs, the revolving loans will immediately become due and payable; if any other event of default exists, the administrative agent or the requisite lenders will be permitted to accelerate the maturity of the revolving loans.

BKV-BPP Power Joint Venture

Under the terms of the Limited Liability Agreement of the BKV-BPP Power, we do not have the ability to unilaterally cause BKV-BPP Power to make distributions. As of June 30, 2022 and December 31, 2021, no distributions have been made by BKV-BPP Power. In addition, we may be required to make additional capital contributions to fund items approved in the annual budget or other matters approved by the board of BKV-BPP Power. Such additional capital contributions, which are not subject to any limit on the potential amount required, would reduce the amount of cash otherwise available for dividend payments by us on our common stock or require us to incur additional indebtedness. However, any additional capital contributions must be approved by a majority of BKV-BPP Power’s eight member board of directors, four of which are appointed by us and four of which are appointed by BPPUS. See “Certain Relationships and Related Party Transactions — BKV-BPP Power Limited Liability Company Agreement.” Also see “Risk Factors — Risks Related to Our Power Generation Business — We operate our power generation business through a joint venture which we do not control.”

Internal Controls and Procedures

As an emerging growth company, we are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act, and therefore are not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual

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assessment of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act until the year following our first annual report required to be filed with the SEC. We will not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls over financial reporting until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act.

Material Weakness in Internal Control Over Financial Reporting

We have identified several material weaknesses in our internal control over financial reporting as of December 31, 2021, as described below. A “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. See “Risk Factors — Risks Related to the Offering and Our Common Stock — We have identified material weaknesses in our internal control over financial reporting and may identify additional material weaknesses in the future, or otherwise fail to maintain effective internal controls over financial reporting, which could result in a restatement of our financial statements or cause us to fail to meet our reporting obligations.”

We did not design and maintain effective controls to communicate relevant information among departments to completely and accurately record and disclose transactions in the financial statements. This material weakness contributed to two additional material weaknesses in our internal controls. We did not design and maintain effective controls related to (i) the accounting for stock awards and common stock with certain put rights, including the value and classification of such arrangements; and (ii) the communication and evaluation of terms and conditions set forth in complex contracts, including certain of our commodity derivative contracts, relevant to our compliance with financial covenants and related disclosures.

Finally, we did not design and maintain effective controls related to the accounting for income taxes, which were not designed at a sufficient level of precision or rigor to prepare and review the tax rate reconciliation, return to provision, income tax provision, related income tax assets and liabilities, and disclosures in the consolidated financial statements, which also resulted in a material weakness in our internal control over financial reporting.

The material weaknesses described above resulted in audit adjustments to share capital and other mezzanine equity accounts, liquidity disclosures, income tax benefit, income taxes payable to related party and deferred tax assets. Additionally, each of the material weaknesses described above could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.

We have begun to take steps towards remediating these material weaknesses primarily by designing and implementing additional internal controls, including those related to (i) the communication of relevant information across departments, (ii) the valuation and classification of stock awards and common stock with certain put rights, (iii) the communication and evaluation of terms and conditions included in complex contracts relevant to our compliance with financial covenants and related disclosures, and (iv) the preparation and review of the income tax rate reconciliation, return to provision, income tax provision, related income tax assets and liabilities, and income tax disclosures. Although we believe we are addressing the internal control deficiencies that led to the material weaknesses, the measures we have taken, and plan to take, may not be effective.

Off-Balance Sheet Arrangements

As of June 30, 2022 and December 31, 2021 and 2020, we did not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

Management’s discussion and analysis of our financial condition and results of operations are based upon our historical consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements in conformity with GAAP requires us to make estimates and

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assumptions that affect the reported amounts of certain assets, liabilities and related disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The following critical accounting policies relate to the more significant estimates and assumptions used in preparing the historical consolidated financial statements.

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

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

The processes we use to estimate quantities of proved and unproved developed natural gas reserves and their values, future production rates, and future development costs are highly complex and requires significant subjectivity and estimation in the evaluation of available geological, engineering and economic data. The accuracy of any reserves estimate is a function of the quality of data available and of engineering and geological interpretation. The data used in developing reserve estimates may change significantly over time as a result of numerous factors, including but not limited to evolving production history, additional development activity, and continual reassessment of the viability of production under varying economic conditions. Although we take every reasonable effort to ensure our reserve estimates are representative of our actual reserves — for example, by involving independent reserve engineers in the assessment of the estimates — the subjective decisions and variances in the data available could give rise to revisions that could materially impact the accompanying historical consolidated financial statements.

Impairment of Natural Gas Properties

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

Revenue Recognition

We generate the majority of our revenues through the production and sale of natural gas and NGLs. The majority of these sales contracts are short term in duration and the associated revenue is recognized once control of the distinct good identified in the contract transfers to the customer at the delivery point specified within the contract. We must use a level of estimation in determining the initial amount of revenue to recognize in connection with the sale of natural gas and NGLs. Specifically, we must estimate the per-unit prices associated with a sales order, as they are variable and based on commodity pricing. Additionally, we must estimate the sales volumes using company-measured volume readings. We subsequently true up estimated revenue to actual revenue upon receipt of actual prices and volumes from our purchasers, which for natural gas and NGL sales occurs within one month of product delivery. Historically, differences between

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estimated revenue and actual revenue have not been material but have potential to be in the instance our price or volume estimates are inaccurate.

We also generate revenues through our non-operated midstream interests. Midstream revenues are recognized when services are rendered based on the stated contractual rates and the volumes of product transported and measured in accordance with the underlying contract. We must estimate the volume of products transported using third-party data in determining the initial amount of revenue to recognize. We subsequently adjust estimated revenue to actual revenue upon receipt of actual volume data from the operator, which is typically within three months of completion of product transportation. Historically, differences between estimated revenue and actual revenue have not been material but have potential to be in the instance our volume estimates are inaccurate.

Derivative Instruments

We enter into commodity derivative instruments to reduce the effect of price volatility on a portion of our future natural gas and NGL production. Derivative instruments are with counterparties of high credit quality and are subject to master netting agreements, and accordingly, the risk of nonperformance by the counterparties is low. However, these activities may prevent us from realizing the full benefits of price increases above the levels of the derivative instruments on a portion of our future natural gas and NGL production.

The accounting for the fair value of a derivative and changes thereto depends on the intended use of the derivative and the resulting designation. We have not designated any of our derivative contracts as fair value or cash flow hedges for accounting purposes and therefore we do not apply hedge accounting to the commodity derivative instruments. Rather, the changes in fair value are recognized in the consolidated statements of operations as net realized and unrealized gains and losses on derivative instruments in the period of change.

Acquisitions

We account for business combinations in accordance with ASC Topic 805, Business Combinations. Pursuant to the guidance, we allocate the aggregate purchase consideration transferred to affect the business combination to the assets acquired and liabilities assumed based on their fair values as of the acquisition date. Any excess or shortage of the purchase price over the fair value of the assets acquired and liabilities assumed is recognized as goodwill or a gain on bargain purchase, respectively. The amount of goodwill or gain on bargain purchase recorded in a business combination can vary significantly depending on the fair value allocated to the assets acquired and liabilities assumed. Further, in many cases, the valuation of these assets and liabilities requires use of various estimates and assumptions and the exercise of significant judgment about future events.

In transactions where substantially all the gross assets acquired are concentrated in a single identifiable asset or group of similar identifiable assets, the acquisition is treated as an asset acquisition rather than a business combination. We account for asset acquisitions using a purchase price allocation through which the total transaction value is determined by aggregating the base purchase price, certain closing adjustments, and contingent consideration, if any. The total transaction value is then allocated to the acquired assets on a pro rata basis based on their fair values. The determination of fair values of assets acquired requires the Company to make estimates and select valuation techniques, both of which require the exercise of management judgment.

The contingent consideration first reported in the year ended December 31, 2020 was generated from the Devon Barnett Acquisition. The fair value of the contingent consideration as of December 31, 2021 and 2020 represents management’s best estimate if a third party were paid to assume the contingency. The fair value was determined using forecasted monthly Henry Hub prices, WTI prices and the application of Monte Carlo simulations. This contingency, including the settlement, is described further in “Note 15 — Commitments and Contingencies” to our historical consolidated financial statements included elsewhere in this prospectus. Future results of operations for any quarterly or annual period could be materially affected by changes in our assumptions.

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Equity-based Compensation

Pursuant to the BKV Corporation 2021 Long Term Incentive Plan (the “2021 Plan”), time-vested restricted stock units (“TRSUs”) and performance-vested restricted stock units (“PRSUs”) may be granted to eligible participants. In each of January 2021 and 2022, we made annual grants of TRSUs under the 2021 Plan. The 2021 Plan will be terminated by the board of directors in connection with this offering and no further awards will be made thereunder. We recognize compensation cost related to these equity-based awards in the consolidated financial statements on a straight-line basis based on estimated grant date fair value, as if all four tranches of the TRSUs were granted at once, rather than being granted on an annual basis over four years. Under the 2021 Plan, if a participant’s employment is terminated for any reason other than the participant’s resignation or, if a participant’s employment is terminated due to his or her voluntary resignation and more than 36 months has passed since the participant’s first grant of an incentive award under the 2021 Plan, in each case where the Company had not repurchased the participant’s shares of common stock acquired under the 2021 Plan, the participant will have the right to elect to sell such shares back to the Company at an amount equal to the fair market value of the shares at the time the election to sell was made. In November 2021, this put right was amended so that it could not be exercised for at least 181 days following the date the participant’s award vests and a “Sell Fund Purchase Program” was implemented whereby, if specifically provided for in an award agreement, participants have the ability to tender shares for repurchase by the Company.

The TRSUs we are authorized to grant include service conditions and the PRSUs we are authorized to grant include service conditions, market performance conditions, and non-market performance conditions. In January 2021, we anticipated that we would have made four annual grants of TRSUs under the 2021 Plan in each of 2021, 2022, 2023 and 2024, subject to continued employment, the continuation of the 2021 Plan and other factors; however, there was and is no obligation to make any future grants and any such grants would require approval by our board of directors. Although the TRSUs anticipated to be granted in each of 2022, 2023 and 2024 were not actually granted to the participants when their initial TRSU award was granted, for accounting purposes, the grant date fair value of the anticipated (but not yet granted) TRSUs was determined, based on the service condition and utilizing the fair market value of common stock on the date the 2021 TRSUs were granted. The grant date fair value of the PRSUs was determined based on the service conditions, market performance conditions, and non-market performance conditions of the award on the grant and utilizing the fair market value of common stock on the grant date and Monte Carlo simulations, as well as probability assessments relative to the satisfaction of non-market performance conditions. In connection with the change to the put right to implement the 181-day holding period after vesting, an additional charge was recognized with respect to both the TRSUs and PRSUs, given that the fair market value of the common stock on the date of modification had increased from the fair market value on the original grant date.

Compensation cost is recognized ratably on a straight-line basis over the applicable service period. Forfeitures are estimated and recognized over the applicable service period and are re-evaluated at the end of each reporting period. We expect to recognize the forfeitures of the 2023 and 2024 anticipated TRSUs in connection with this offering and the subsequent termination of the 2021 Plan.

We believe that our board of directors, with input from management and the support of third-party valuations, has the relevant experience and expertise to determine the fair value of our common stock. Given the absence of a public trading market of our common stock, and in accordance with the American Institute of Certified Public Accountants Practice Aid, Valuation of Privately-Held Company Equity Securities Issued as Compensation, numerous objective and subjective factors were considered when determining the best estimate of the fair value of our common stock at each grant date. These factors include:

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the lack of marketability of our common stock;

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our operating and financial performance;

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current business conditions and projections;

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hiring of key personnel and the experience of our management;

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the history of the Company;

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the market performance of comparable publicly traded companies; and

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U.S. and global capital market conditions.

In valuing our common stock, the fair value of our business was determined using various valuation methods, including combinations of income and market approaches with input from management. The income approach estimates value based on the expectation of future cash flows that a company will generate. These future cash flows are discounted to their present values using a discount rate that is derived from an analysis of the cost of capital of comparable publicly traded companies in our industry or engaged in similar business operations as of each valuation date and is adjusted to reflect the risks inherent in our cash flows. The market approach estimates value based on a comparison of the subject company to comparable public companies engaged in similar business operations. From the comparable companies, a representative market value multiple is determined and then applied to the subject company’s financial forecasts to estimate the value of the subject company.

Application of these approaches and methodologies involves the use of estimates, judgments, and assumptions that are highly complex and subjective, such as those regarding our expected future revenue, expenses, and future cash flows, discount rates, market multiples, the selection of comparable public companies, and the probability of and timing associated with possible future events. Changes in any or all of these estimates and assumptions or the relationships between those assumptions impact our valuations as of each valuation date and may have a material impact on the valuation of our common stock.

Once our stock is publicly traded, the fair value of each share of underlying common stock will be determined based on the closing price as reported on the date of grant on the primary stock exchange on which our common stock is traded.

Impairment of Goodwill

Goodwill represents the excess of the cost of an acquisition over the fair value of the net assets acquired through the Corporatization Event described in “Note 19 — Corporatization Event” to our historical consolidated financial statements included elsewhere in this prospectus. Impairment may occur if the reporting unit’s carrying value exceeds its fair value. Due to the nature of the goodwill arising from the acquisition of Kalnin Ventures, as is described further in “Note 19 — Corporatization Event,” the Company’s goodwill is tested at the reporting unit level, which for the Company is at the consolidated level due to the Company having one identifiable operating segment or reporting unit. Under the provisions of ASC Topic 350 Intangibles — Goodwill and Other, we perform an impairment test for goodwill at least annually or when events and circumstances indicate the carrying value may not be recoverable. In performing the required impairment tests, we have the option to first assess qualitative factors to determine if it is necessary to perform a quantitative assessment for goodwill impairment. If the qualitative assessment concludes that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying value, a quantitative assessment is performed.

Our quantitative assessment utilizes present value (discounted cash flow) methods to determine the fair value of the reporting units with goodwill. Determining fair value using discounted cash flows requires considerable judgment and is sensitive to changes in underlying assumptions and market factors. Key assumptions relate to revenue growth, projected operating income growth, terminal values, and discount rates. If current expectations of future growth rates and margins are not met, or if market factors outside of the Company’s control, such as factors impacting the applicable discount rate, or economic or political conditions in key markets change significantly, then goodwill allocated to the reporting unit may be impaired. Management determined there were no circumstances indicating the carrying value may not be recoverable during the years ended December 31, 2021 and 2020. There have been no impairments recorded related to goodwill as the results of the annual quantitative impairment test indicated the fair value of the assets of the group to be greater than the carrying value as of December 31, 2021 and 2020.

Litigation and Environmental Contingencies

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

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

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

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

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

Recent Accounting Pronouncements

See “Note 2 — Summary of Significant Accounting Policies” to our historical consolidated financial statements included elsewhere in this prospectus for more information about recent accounting pronouncements, the timing of their adoption, and our assessment, to the extent we have made one, of their potential impact on our financial condition and our results of operations.

Quantitative and Qualitative Disclosure About Market Risk

Commodity Price Risk and Hedging Activities

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

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

Our financial hedging activities are intended to support natural gas and NGLs prices at targeted levels and to manage our exposure to natural gas and NGLs price fluctuations. These contracts may include commodity price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty, producer collars that set a floor and ceiling price for the hedged production, enhanced three-way collars that set a floor and ceiling price for the hedged production with the potential for hedged volumes doubling above the ceiling price, or basis differential swaps. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity. The derivative contracts outstanding as of June 30, 2022 and December 31, 2021 consisted of consisted of swaps, producer collars and enhanced three-way collars, subject to master netting agreements with each individual counterparty.

As of June 30, 2022 and December 31, 2021, we had in place natural gas swaps, producer collars, and enhanced three-way collars covering portions of our projected production through 2023. Our commodity hedge position as of December 31, 2021 is summarized in “Note 5 — Derivative Financial Instruments” to our historical consolidated financial statements included elsewhere in this prospectus.

We may enter into hedge contracts with a term greater than 24 months, and for no longer than 36 months, for up to 60% of our estimated production for the current year, 50% and 25% for the subsequent years, respectively. A $0.10 per Mcf decrease in NYMEX would have resulted in a $7.0 million increase in natural

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gas hedge revenues for the six months ended June 30, 2022. A $1.00 decrease per Bbl of each NGL purity product price would have resulted in a $1.9 million increase in NGL hedge revenues for the six months ended June 30, 2022. A $0.10 per Mcf decrease in NYMEX would have resulted in a $16.1 million increase in natural gas hedge revenues for the year ended December 31, 2021. A $1.00 decrease per Bbl of each NGL purity product price would have resulted in a $5.3 million increase in NGL hedge revenues for the year ended December 31, 2021.

Additionally, to reduce its exposure to fluctuations in the market price of electricity and natural gas, BKV-BPP Power enters into financially settled HRCOs, which are contracts for the financial purchase and sale of power based on a floating price of natural gas at a predetermined location using a predetermined conversion factor, or heat rate, required to turn the fuel input into electricity. BKV-BPP Power is exposed to basis risk in its operations when its derivative contracts settle financially and it delivers physical electricity on different terms. For example, if BKV-BPP Power enters into an HRCO, it hedges its electricity production based on an agreed price for that electricity, but physical electricity must be delivered to delivery points in the market it serves. BKV-BPP Power is exposed to basis risk between the hub price specified in the HRCO and the price that it receives for the sales of physical electricity. BKV-BPP Power attempts to hedge basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the quantities that it requires. BKV-BPP Power’s hedging activities do not provide it with protection for all of its basis risk and could result in economic losses and liabilities, which could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, cash flows and ability to pay dividends on our common stock. Additionally, by using derivative instruments to economically hedge exposure to changes in power prices, we could limit the benefit we would receive from increases in the power prices, which could have an adverse effect on our financial condition. For example, as of June 30, 2022, we had unrealized losses of approximately $54.9 million on two HRCOs as a result of increased power pricing. In the event BKV-BPP Power is not able to satisfy its obligations under the HRCO, it must purchase power at prevailing market price to satisfy the HRCO. Likewise, increases in power pricing could limit the benefit we receive under HRCOs and result in losses. Either such event could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations, cash flows and ability to pay dividends on our common stock.

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

Mark-to-market adjustments of derivative instruments cause earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled or monetized prior to settlement. We expect continued volatility in the fair value of our derivative instruments. Our cash flows are only impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty. As of June 30, 2022, the estimated fair value of our commodity derivative instruments was a net liability of $305.0 million, comprised of current and non-current liabilities. As of June 30, 2021, the estimated fair value of our commodity derivative instruments was a net liability of $145.9 million, comprised of current and non-current liabilities. As of December 31, 2021, the estimated fair value of our commodity derivative instruments was a net liability of $104.8 million, comprised of current and noncurrent assets and liabilities. As of December 31, 2020, the estimated fair value of our commodity derivative instruments was a net asset of $10.3 million, comprised of current and noncurrent assets and noncurrent liabilities.

By removing price volatility from a portion of our expected production through December 2023, we have mitigated, but not eliminated, the potential negative effects of changing prices on our operating cash flows for those periods. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

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Counterparty Credit Risk

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

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

In addition, we utilize an unaffiliated third party to market all of our natural gas production to various purchasers, which consist of credit-worthy counterparties, including utilities, LNG producers, industrial consumers, major corporations and super majors, in our industry. We rely on the credit worthiness of such third party marketer, who collects directly from the purchasers and remits to us the total of all amounts collected on our behalf less their fee for making such sales. See “Business — Customers and Product Marketing” and “Risk Factors — Risks Related to Our Upstream Business and Industry — A substantial percentage of our natural gas and NGL production is gathered, processed, and transported by a single third party and all of our natural gas production is marketed by a single third party.”

Interest Rate Risks

As of June 30, 2022, our primary exposure to interest rate risk results from our outstanding related party borrowings with BNAC, the Term Loan Credit Agreement and the Revolving Credit Facilities, which have floating interest rates. As of June 30, 2022, we had outstanding borrowings with BNAC of $191.0 million, $30.0 million outstanding borrowings on our OCBC Credit Facility, and an additional $570.0 million outstanding borrowings under the Term Loan Credit Agreement. The average annualized interest rate incurred on our outstanding borrowings during the six months ended June 30, 2022 was approximately 5.59%. We estimate that a 1.0% increase in the applicable average interest rates for the six months ended June 30, 2022 would have resulted in an immaterial increase in interest expense.

As of December 31, 2021, we had outstanding borrowings with BNAC of $166.0 million under the $116 Million Loan Agreement and the $50 Million Loan Agreement. As of December 31, 2021, we had no outstanding borrowings under the OCBC Credit Facility. The average annualized interest rate incurred on the BNAC borrowings during the year ended December 31, 2021 was approximately 5.4%. We estimate that a 1.0% increase in the applicable average interest rates for the year ended December 31, 2021 would have resulted in an immaterial increase in interest expense.

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INDUSTRY

We primarily 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. The company was founded on acquiring and producing natural gas and we have expanded into a total of four business lines: natural gas production, natural gas gathering, processing and transportation, power generation and CCUS. We formally launched our CCUS business, BKV dCarbon Ventures, in March 2022, reached Phase I FID on our first high concentration CCUS project in the Barnett in June 2022 with EnLink, which we refer to as the Barnett Zero Project, and reached Phase I FID on our second CCUS project, which we refer to as the Cotton Cove Project. We intend to continue to develop our CCUS business. CCUS projects and the sector generally are in their early stages and continue to evolve since the 2015 Paris Climate Agreement (the “Paris Agreement”) drew global commitment to delivering a net-zero emission economy.

Our CCUS business and all of our CCUS projects are in the early stages of development. Further, we have not executed any definitive agreements with respect to any of the potential CCUS projects in our project pipeline. In addition, the development of our CCUS business is expected to require material capital investments and the commercial viability of our CCUS projects depends, in part, on certain financial and tax incentives provided by the U.S. federal government. Our ability to establish large scale CCUS projects is subject to numerous risks and uncertainties, and we may be unable to execute on some or all of these projects on terms acceptable to us or at all. For more information about the risks involved in our CCUS business, see “Risk Factors — Risks Related to Our CCUS Business.” In addition, we continue to evaluate the potential expansion of our integrated energy platform into retail power connectivity, while monitoring the potential impact the LNG industry may have on our business.

Carbon Capture, Utilization and Sequestration

CCUS involves the capture of CO2 emissions and the processing of such emissions for reuse or permanent storage in subsurface geological formations, and is recognized as a primary means of reducing CO2 emissions from large-scale energy and industry sources.

To advance the objectives outlined in the Paris Agreement, the United States released goals in 2021 that included delivering a net-zero emission economy by no later than 2050 (and 2035 for the electric power sector). According to the Global CCS Institute, the global CCUS industry must grow by more than a factor of 100 by the year 2050 to achieve Paris Agreement climate targets, equating to approximately 70 to 100 new facilities per year. As of September 2021, approximately 37 Mtpa of capture capacity is operational worldwide across 27 facilities, with an additional approximately 111 Mtpa planned in various development stages across 106 facilities. According to Global CCS Institute’s Global Status of CCS 2021 (“Global Status of CCS 2021”), achieving long-term emissions targets will require installed CCUS capacity to increase to over 5,600 Mtpa by 2050 and an estimated capital investment of $655 billion to $1.280 trillion by 2050.

In Energy Technology Perspectives 2020, published by the International Energy Agency (“IEA”), the IEA estimated 80% of industrial facilities and power plants accounting for 85% of emissions are located within 100 kilometers of a potential storage site.

To stimulate investment in CCUS, the US Energy Act of 2020 provided over $6 billion for CCUS research and development programs, and in 2021, the U.S. Treasury and the Internal Revenue Service (“IRS”) issued critical guidance on Section 45Q tax credits for carbon capture and storage, expanding its applications to a wider range of CCUS activities. In addition, the Inflation Reduction Act of 2022, which was signed into law on August 16, 2022, provides significant incentives for CCUS investment.

The current CCUS industry can be described as highly fragmented with a wide range of technologies and processes being evaluated for long-term viability across the value chain including capture, separation, compression, liquefaction, transportation, storage and utilization. According to Global Status of CCS 2021, in the U.S. Midwest and Mid-Continent regions, several CCUS networks have been created to provide shared transportation and storage solutions, benefiting smaller projects that lack vertical integration.

Power Generation

The United States electricity market starts with utility-scale generators that generate electricity from fossil fuels, nuclear energy and renewable energy. Utility scale plants and other renewable energy sources sell

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electricity to the wholesale market, including electric utility companies, competitive power providers and electricity marketers, who then sell electricity to retail end-users.

The power industry consists of a variety of companies that are engaged in the generation or distribution of power, with most electric utility companies relying on natural gas to generate a portion of their power. According to the IEA, overall demand for electricity decreased during the initial phases of COVID-19, but has since increased as lockdowns subsided and manufacturing activities re-bounded. According to the IEA, global electricity demand rose by 6% in 2021 and is expected to rise by 2.4% in 2022.

In the near future, demand for retail electricity is expected to grow modestly, driven by increased consumption from commercial and industrial customers recovering from the pandemic. As of summer 2022, the IEA expects total U.S. retail sales of electricity to end-use customers to be 0.4% higher than summer 2021, and retail sales to the industrial sector to be 2.8% higher than summer 2021. Short-term demand for electricity can vary with weather conditions and economic shocks, which increases unpredictability. Because long-term demand depends on economic growth and efficiency improvements, the growth of the national economy directly impacts U.S. power consumption.

The sources for U.S. electricity have increasingly consisted of natural gas and renewable energy sources. While coal and nuclear energy sources have been declining, natural gas and renewable sources have been expanding their share of total electricity generation in the United States. According to the IEA, in 2021, natural gas grew to account for the largest share of total utility-scale electricity generating capacity in the United States at 38%, followed by renewables at 27%. According to the IEA, the share of natural gas-based electricity generation more than tripled from 12% in 1990 to 38% in 2021. Given the multi-year highs in natural gas procurement pricing and supply chain constraints, capital spending budgets and customer affordability concerns are expected to increase.

Liquified Natural Gas

LNG is natural gas in its liquid phase after being super-cooled to -260°F. LNG is primarily used to store and transport gas between markets that have limited natural gas pipeline connectivity. Once natural gas is delivered to an LNG facility, the gas is liquified and shrunken to approximately 1/600th of its original volume. Then, the LNG is loaded onto carriers that have large cryogenic tanks onboard for oceanic transport. At receiving terminals, the LNG is transitioned back into its original gaseous state. From there, the regassified gas is either stored or transported via pipeline to end-consumers like power plants, industrial facilities, and residential communities.

In the wake of the Russian invasion of Ukraine, Europe is diversifying its natural gas supply towards LNG alternatives because, according to the IEA, close to 40% of total EU gas demand is sourced from Russia. According to the IEA, the United States has exported 74% of its LNG to Europe though the first four months of 2022, representing more than double the 2021 average of 34%. According to the IEA and FERC, because U.S. LNG utilizations are at all-time highs at 91%, an additional 4 Bcf/d capacity is currently under construction, and another 27 Bcf/d in capacity has been approved by FERC. Current market dynamics have poised LNG for expansion, particularly in the U.S. Gulf Coast, where approximately 90% of the U.S. LNG build is slated, according to FERC. The Barnett region is approximately 300 miles from the Gulf Coast LNG market. Producers are capitalizing on these dynamics by entering into supply agreements that provide a take-or-pay style fixed liquefaction fee for the LNG facility and efficient access to the global gas markets. Upstream producers with exposure to international LNG natural gas prices are expected to provide a baseline of pricing support for Texas and Louisiana-based natural gas producers with pipeline connectivity to the Gulf Coast.

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BUSINESS

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. 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 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.

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 ESG 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 and in 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 capital expenditure program, enhance stockholder value and support future acquisitions across our four business lines 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 September 30, 2022, our total acreage position was approximately 505,000 net acres, 99% of which was held by production. As of September 30, 2022, our net daily production (after giving effect to the Exxon Barnett Acquisition) averaged 864 MMcfe/d, consisting of approximately 79% natural gas and approximately 21% NGLs. As of September 30, 2022, our total proved reserves of 6,332 Bcfe had an estimated 7% 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 508 horizontal locations and approximately 1,700 refracture (“refrac”) candidates. Based on current commodity prices, the capital investment required to hold production flat year-over-year is less than approximately 30% of our annual Adjusted EBITDAX. Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP. See “— Summary Historical 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 the 2020 Barnett Assets from Devon Energy. On June 30, 2022, we further scaled our Barnett position by acquiring approximately 175,000 net acres, 2,100 operated wells and related upstream, midstream and other assets in the Exxon Barnett Acquisition. As of September 30, 2022, our Barnett acreage position was approximately 468,000 net acres, which is approximately 99% held by production. Our average daily Barnett production of approximately 731 MMcfe/d for the nine months ended September 30, 2022 consisted of 75% natural gas and 25% NGLs. We had an average working interest in our operated wells in the Barnett of approximately 96.8% as of September 30, 2022 and an Effective NRI in the Barnett of approximately 80.37%.

We are the largest natural gas producer by gross operated volume in the Barnett. Based on information published by the TRRC, the chart below illustrates our gross operated production volumes in the Barnett (including the Exxon Barnett Acquisition), which represent approximately 29% of the total Barnett production, and nearly double that of the next largest producer in the Barnett for the month of March 2022.

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We entered NEPA in 2016 and have subsequently scaled our position through 12 acquisitions. As of September 30, 2022, our acreage position was approximately 37,000 net acres, which is approximately 94% held by production. Our average net daily production of 133 MMcfe/d for the nine months ended September 30, 2022 consisted entirely of natural gas. We had an average working interest in our operated wells in NEPA of 89%, as of September 30, 2022.

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, as of September 30, 2022, approximately 220 MMcf/d of our gross production (approximately 29% 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 September 30, 2022, we had an approximate 29.4% non-operated ownership interest in a midstream system, which is operated by subsidiaries of 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 Temple I, a newly-constructed, modern combined cycle gas and steam turbine power plant 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 has an annual average power generation capacity of 755 MW and delivers power to customers on the ERCOT power network in Texas. Temple I is among the most efficient generators supplying power to ERCOT, with a baseload design heat rate of approximately 6,950 Btu/kWh, which is well below the ERCOT CCGT average. Temple I’s modern technology enables it to respond to rapidly changing market signals in real time by minimizing congestion risk and ensuring the highest operational readiness during the time when electricity consumption peaks (in winter and summer), making it 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 Temple I and its firm intrastate natural gas storage service at the Bammel storage facility. Supplying our own natural gas to Temple I will 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. We intend to continue to build out our power generation business through opportunistic acquisitions of power generation assets and eventually to expand into retail power, which would enable us to ultimately provide net zero wellhead-to-household energy to the end-consumer.

Carbon Capture, Utilization and Sequestration

We are committed to capturing CO2 that is separated from natural gas power generation and compression and from various industrial and natural gas processing CO2 sources, and then compressing and injecting the CO2 into underground injection control (“UIC”) wells. We have been evaluating project opportunities and developing our CCUS business for over 20 months. 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

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and timely execution of our business plans, we will begin generating positive CCUS business revenue via tax credits and other tax benefits by the end of 2023, and we expect to begin generating positive Adjusted EBITDAX in 2025.

We seek to execute CCUS projects with attractive standalone economics for high, medium and low CO2 concentration streams that contribute to our goal of the full elimination and/or offset of the Scope 1 and 2 emissions in our owned and operated upstream businesses by the end of 2025.

In March 2022, we formally launched our CCUS business with the establishment of BKV dCarbon Ventures and in June 2022, we reached a Phase I final investment decision (“FID”) on 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, which we expect to achieve an average injection rate of up to 185,000 tons of CO2 per year. We estimate this initial CCUS project will represent more than 8% of our estimated Scope 1 and 2 emissions from our owned and operated upstream businesses, with the first injection scheduled for the second half of 2023. Following commencement of commercial operations of our project with EnLink, we intend to use this project as a prototype for modular projects that can be repeated and quickly scaled.

On October 18, 2022, BKV dCarbon Ventures reached a Phase I FID to develop our second CCUS project to dispose of, and geologically sequester, acid gas and CO2 generated as a byproduct of the production of our natural gas in the Barnett and will utilize our newly acquired BKV Midstream assets. This CCUS project, which we refer to as the Cotton Cove Project, will separate CO2 from our natural gas production in the Barnett. We estimate the Cotton Cove Project will geologically sequester up to 45,000 tons of CO2 per year initially, which we expect will increase to an average of up to 82,350 tons CO2 per year by the end of 2024 through ongoing well development in the area. We currently estimate the total project cost for the Cotton Cove Project to be between $14.0 and $24.0 million. We expect to own or hold the source, the capture, the transportation pipeline and the lease to the pore space with respect to this project. We are targeting commencement of CO2 injection activities by the first half 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 up to eight potential NGP projects that are in different phases of the appraisal and development process. As part of the Cotton Cove Project, we also expect to pilot, and then scale, post-combustion carbon capture technology that would allow us to sequester an additional 250,000 tons per year of captured CO2 from low concentration emissions from within our BKV Midstream operations. We expect that our technology applications will utilize compressor waste heat to reduce energy requirements and cost. We also expect to reduce the cost of low concentration transport and sequestration as the cost of the initial infrastructure build will have been incurred in connection with the high concentration anchor injection. We expect this project to initially offset our current Scope 1 and 2 annual emissions from our owned and operated upstream businesses by approximately 2%, bringing us closer to our goal of reaching net zero across our Scope 1 and 2 owned and operated upstream emissions by the end of 2025.

Further, in August 2022, we entered into a development agreement with Verde CO2 CCS, LLC (“Verde CO2”), an independent carbon capture and sequestration developer and operator, to identify, evaluate and develop additional 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 and aligns with our goal to reach net zero owned and operated upstream emissions across Scope 1 and 2 by the end of 2025. As of October 20, 2022, we have invested $8.3 million to Verde CO2 under the development agreement and we currently expect to invest up to $250.0 million over the next three years to fund efforts by BKVerde, LLC (“BKVerde”), a subsidiary of BKV dCarbon Ventures, to efficiently identify and evaluate a pipeline of feasible CCUS projects, and to execute on those projects. We expect to fund BKVerde through cash flow from BKV operations. See “— Recent Developments — CCUS Project Development with Verde CO2.”

We are currently evaluating and discussing with third parties three to ten additional CCUS projects (inclusive of the projects with Verde CO2). Assuming we reach FID with respect to each of these projects, we would expect to develop and complete each of these projects during the next several years based on economics supported by the carbon tax credits available under Section 45Q of the Code (the “Section 45Q tax credits”). For three of these potential CCUS projects, we expect to reach FID within three to six

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months. We believe these projects could generate an aggregate of up to 4.5 Mtpy CO2e in carbon capture and sequestration on a total capital investment of approximately $520.0 million (inclusive of the investment with Verde CO2). We also are currently evaluating an additional seven potential CCUS projects with respect to which we have begun commercial discussions with third parties. Although each of these potential projects are in different stages of the evaluation process and we have not reached FID or entered into any agreements with respect to any of them, if these potential CCUS projects, together with the Barnett Zero Project and the Cotton Cove Project, are ultimately completed, based on our current estimates we believe these potential projects represent a project pipeline of nearly 30 Mtpy CO2e of carbon capture and sequestration, with the largest potential CCUS project representing approximately 8 Mtpy CO2e and the smallest representing approximately 0.8 Mtpy CO2e. The aggregate number of metric tons of CO2 represented by these potential projects would represent nearly twice the aggregate size of our current Scope 1, 2 and 3 emissions from our owned and operated upstream businesses, which we estimate to be approximately 16.1 Mtpy CO2e as of September 30, 2022. See “— Path to Net Zero Emissions” below for a description of how we estimate our Scope 3 emissions.

We estimate the aggregate cost to us to offset all of our Scope 3 emissions through at least some of these ten identified potential projects, to be between approximately $1.3 billion and $1.8 billion over the next seven to ten years. We expect to fund these costs through our cash flows from operations, as well as a variety of 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 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. In addition, we anticipate that some of the project costs will be borne by third party investors in these projects, including emitters, landowners and other stakeholders.

As we strive to become a leader in CCUS, our steering committee 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.

Our CCUS business and all of our CCUS projects are in the early stages of development, and we have not executed any definitive agreements with respect to our identified potential projects. In addition, the development of our CCUS business is expected to require material capital investments, and the commercial viability of our CCUS projects depends, in part, 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 the majority of the Section 45Q tax credits, the details of which have not yet been released and are to be included in future guidance. Our ability to establish large scale CCUS projects is subject to numerous risks and uncertainties, including 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 on the timeline we anticipate, on terms acceptable to us or at all. For more information about the risks involved in our CCUS business, see “Risk Factors — Risks Related to Our CCUS Business.”

Path to Net Zero Emissions

We estimate that our owned and operated upstream Scope 1 and 2 emissions were 2.2 Mtpy CO2e as of September 30, 2022. Our estimates are based on information with respect to our operated assets in the Barnett and NEPA through fiscal year 2021 and reported by BKV for the Subpart W requirements of the EPA and supplemented with additional inventories that are not required to be reported into Subpart W, as well as 2020 Subpart W emission information submitted by XTO Energy, Inc. for the assets acquired in the Exxon Barnett Acquisition. We will further evaluate these estimates as a part of our combined Subpart W submittal for calendar year 2022 and will factor in additional inventory efforts performed during 2022. These estimates fluctuate throughout the year and will be updated on an annual basis to reflect any changes in inventory, production throughput, and emissions reduction retrofits or equipment modifications.

We estimate that our owned and operated upstream Scope 3 emissions were 13.9 Mtpy CO2e as of September 30, 2022. Our Scope 3 GHG emissions are currently estimated in accordance with IPIECA’s

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“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 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 emissions are estimated at an approximated year-end production volume of 900 million standard cubic feet net equivalent per day of gas, 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 million standard cubic feet net equivalent per day towards combustion as the end use, applying suitable combustion emission factors from the EPA, and using AR4 GWPs, Scope 3 emission from our owned and operated upstream operations are estimated to be approximately 13.9 Mtpy CO2e. We currently leverage third party consultants to develop, estimate and review the Scope 3 emissions.

The charts below reflect (i) our owned and operated upstream Scope 1 and 2 emissions as of September 30, 2022, including Scope 1 and 2 emissions estimates from the Exxon Barnett Acquisition, and (ii) our owned and operated upstream Scope 3 emissions as of September 30, 2022, including Scope 3 emissions estimates from 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 end of 2030, in each case, for our owned and operated upstream businesses. We intend to achieve these goals through our “Pad of the Future” emissions reductions, emissions and leak surveys, and installing solar power and executing CCUS projects.

(1)

Scope 1 and 2 calculated emissions are based on 545 MMscfd production volume for 2021 BKV Subpart W in the Barnett, 167 MMscfd production volume for 2021 BKV Subpart W in NEPA, and 352 MMscfd production volume with respect to the acquired Exxon Barnett assets based on 2020 Subpart W submissions.

(2)

Emissions surveys to accomplish a one-two month leakage 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 545 MMscf/d production volume for 2021 BKV Subpart W in the Barnett, 167 MMscf/d production volume for 2021 BKV Subpart W in NEPA, and 352 MMscf/d production volume with respect to the acquired Exxon Barnett assets based on 2020 Subpart W submissions.

(2)

Emissions surveys to accomplish a one-to-two month leakage 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 900 MMscfe/d (approximately 730 MMscf/d of gas and 28,000 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 produced is assumed to be combusted for fuel. Scope 3 emissions estimation methodology is therefore considered to be conservative.

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 September 30, 2022, we had implemented elements of our “Pad of the Future” on approximately 2,200 of our existing wells, thereby eliminating an aggregate of approximately 0.51 Mtpy CO2e in GHG emissions from commencement in the fourth quarter of 2021 through such date. 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 by the end of 2025 for an aggregate estimated cost of $36.9 million. Once this expansion is completed, we expect to eliminate an aggregate 1.40 Mtpy CO2e, or approximately 64%, of our currently estimated annual Scope 1 and 2 owned and operated upstream emissions.

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 the second quarter of 2023. 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 enough

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SRECs that, when combined with our leak detection and repair emissions monitoring program, is expected to eliminate or offset approximately 0.18 Mtpy CO2e in GHG emissions.

Further, we believe our total pipeline of potential CCUS projects, together with the Barnett Zero Project and the Cotton Cove Project, will offset more than the remaining 0.61 Mtpy CO2e, or approximately 28%, of our currently estimated annual Scope 1 and 2 owned and operated emissions, by the end of 2025. 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 13.9 Mtpy CO2e as of September 30, 2022. We believe we can achieve this goal if certain of the ten identified potential CCUS projects in our project pipeline are completed upon terms that we believe are obtainable. In addition to these identified projects, we expect to continue to identify and evaluate additional CCUS projects, some of which are already in a preliminary screening stage.

Although we believe our current path to net zero will be sufficient to reduce emissions related to our existing production, the future growth of our natural gas production, midstream and power assets will result in additional CO2e emissions. We believe our approach to reducing the emissions of our direct operations is repeatable and scalable and that 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 eliminate and/or offset any such future emissions in connection with our continued growth.

Our CCUS business and all of our CCUS projects are in the early stages of development, and we have not executed any definitive agreements with respect to our identified potential projects. In addition, the development of our CCUS business is expected to require material capital investments, and the commercial viability of our CCUS projects depends, in part, 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 the majority of the Section 45Q tax credits, the details of which have not yet been released and are to be included in future guidance. Our ability to establish large scale CCUS projects is subject to numerous risks and uncertainties, including 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 on the timeline we anticipate, on terms acceptable to us or at all. For more information about the risks involved in our CCUS business, see “Risk Factors — Risks Related to Our CCUS Business.”

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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Deliver robust returns to stockholders.   We intend to prioritize delivering strong returns to our stockholders through our dividend policy and focus on creating stockholder value. See “Dividend Policy.” 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. The payment of any future dividends on our common stock will be at the discretion of our board of directors and may vary significantly from quarter to quarter and may be zero. Any determination to pay dividends and the amount of any such dividends will depend on, among other factors, the restrictions under our Term Loan Credit Agreement and the Revolving Credit Agreement, as described under “Dividend Policy.” See “Risk Factors — Risks Related to the Offering and Our Common Stock.”

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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-powered instruments on existing pads, combined with emission and leak surveys, reduces our GHG emissions by 72%, based on current Scope 1 and 2 emissions from production in our owned and operated natural gas upstream business. Our Pad of the Future

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application also improves pad efficiencies and operating revenue. As of the year ended December 31, 2021, employing technology and operational excellence, we reduced our lease operating costs in the Barnett by 14% since October 2020, and in NEPA by 26% since January 2019, based on prior 12-month rolling averages. Additionally, our refrac and long lateral drill programs have allowed us to organically grow our reserves base. As of September 30, 2022, our Barnett refrac program has added 491 Bcfe of proved reserves since its inception in early 2021, with an estimated 1.1 Tcfe net proved, probable and possible (“3P”) reserves at less than an average $0.70/Mcfe finding and development costs during 2021. 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 reserve recovery and economics from legacy Barnett wells. Our Barnett new well drilling program has added 1.1 Tcfe of proved reserves since our entry into the Barnett with a total estimate of approximately 2.1 Tcfe 3P reserves. By combining these 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 in our owned and operated upstream businesses and captures margin across the value chain.

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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, 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, 2022. 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 30% and an Upstream Reinvestment Rate of less than 40%. We are focused on our goal of maintaining a conservative financial profile, with a long-term leverage target of less than 1.0x Total Net Leverage Ratio. 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 below 1.0x 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 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 our “Pad of the Future” emissions reductions program, emissions 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 direct operations, CCUS for third parties has become a core focus of our business plan. We expect to represent a meaningful portion of our budgeted capital expenditures going forward as we advance our long-term goal of eliminating and/or 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

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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.

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 468,000 net acres, with an approximately 80.37% 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% year-over-year average base decline rate over the next 10 years as of September 30, 2022. 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.

•

Lower emissions energy production.   We are focused on achieving Scope 1 and 2, net zero operational emissions from our owned and operated upstream production of natural gas by the end of 2025. We believe we have a comprehensive ESG program, which is overseen and directed by an executive ESG steering committee. In 2021, we certified our entire NEPA production and, in 2022, we certified 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 NEPA and Barnett natural gas production as Responsibly Sourced Gas (“RSG”), which we believe could command a premium in the marketplace. In the future, we intend to expand beyond RSG, with aspirations for fully carbon neutral gas sales through net zero Scope 3 from our owned and operated upstream businesses, which we expect can be achieved beginning in the fourth quarter of 2023 with initial gas sales volumes and continuing through the early 2030s to encompass all gas sales volumes. Additionally, we have a plan to achieve net zero Scope 1 and 2 emissions by the end of 2025 based on our “Pad of the Future” emissions reductions, emissions surveys, installing solar power and executing CCUS projects. We believe BKV dCarbon Ventures will be able to capture and sequester over one million metric tons of CO2 per year by the end of 2025, which exceeds the balance of our current Scope 1 and 2 emissions required to achieve net zero upstream emissions, and will additionally enable initial sales of some fully carbon neutral gas volumes.

•

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 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.

•

Well capitalized and conservative balance sheet.   As of June 30, 2022, we had a Total Net Leverage Ratio of 1.21x. Following the completion of this offering, we intend to continue to maintain a strong balance sheet and fund our operations predominantly with internally generated cash flows. We

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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.

•

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

Barnett Zero CCUS Project with EnLink

On June 8, 2022, BKV dCarbon Ventures and EnLink reached a Phase I FID to develop our first CCUS project and entered into an agreement to dispose of, and geologically sequester, CO2 generated as a byproduct of the production of our natural gas in the Barnett and will utilize our newly acquired BKV Midstream assets. This CCUS project, which we refer to as the Barnett Zero Project, will separate CO2from substantially all of our EnLink-gathered natural gas production, which we expect to achieve an average injection rate of up to 185,000 tons of CO2 per year. We currently estimate the total project cost to us of the Barnett Zero Project to be between $20.0 and $22.0 million. We are targeting commencement of CO2 injection activities by the second half of 2023, subject to our ability to secure all required permits, at which point we expect this project to be one of the first permanent commercial CO2 disposal and sequestration projects to come online in the United States. We expect this project to offset our current Scope 1 and 2 annual emissions from our owned and operated upstream businesses by approximately 8%, bringing us closer to our goal of reaching net zero across Scope 1 and 2 upstream emissions by the end of 2025.

Exxon Barnett Acquisition

On June 30, 2022, we closed the acquisition (the “Exxon Barnett Acquisition”) of natural gas upstream and associated midstream infrastructure in the Barnett from XTO Energy, Inc. and Barnett Gathering LLC, subsidiaries of Exxon Mobil Corporation, for a total purchase price of $750.0 million, plus additional contingent consideration of up to $50.0 million depending on future natural gas prices. Pursuant to the Exxon Barnett Acquisition, we acquired approximately 175,000 total net acres that are approximately 99% held by production, primarily in Tarrant, Johnson and Parker counties, and additional smaller positions in Jack, Wise, Denton, Erath, Hood and Ellis counties, Texas (our “2022 Barnett Assets”). These upstream assets include low decline wells, ideal for delivering consistent cash flow, and high average working interests of approximately 94% in over 2,100 operated wells. The Exxon Barnett Acquisition also included approximately 778 miles of gathering pipelines and compression and processing midstream infrastructure with, as of September 30, 2022, over 450 MMcf/d of throughput capacity and approximately 26 MMcf/d of third-party production being gathered on the system. In connection with the Exxon Barnett Acquisition, we entered into the Term Loan Credit Agreement (as defined herein) with a syndicate of banks and Bangkok Bank Public Company Limited (New York Branch), as the administrative agent. The Term Loan Credit Agreement includes up to $600.0 million of commitments for term loans to be used solely to fund a portion of the purchase price for the Exxon Barnett Acquisition and other costs and expenses associated with the acquisition. As of June 30, 2022, there was $570.0 million in aggregate principal amount outstanding under the Term Loan Credit Agreement. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Loan Agreements and Credit Facilities —  Term Loan Credit Agreement” for more information.

Amendment to Derivative Agreement

On August 4, 2022, we entered into an amendment to our ISDA Master Agreement with a counterparty to our derivative contracts pursuant to which we agreed to terminate or novate, at our election, at least $100.0 million of our derivative contracts. As of September 9, 2022, we terminated derivative contracts of $100.2 million with the counterparty to satisfy this requirement. In connection with such termination, we are

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required to make cash payments to the counterparty in an aggregate amount of $100.2 million, of which $30.0 million was paid in September 2022, an additional $30.0 million is due and payable before October 31, 2022 and the remaining $40.2 million must be paid by November 30, 2022. We intend to make the remaining payments with cash flows from operations. See “Note 14 — Commitments and Contingencies” to our unaudited condensed consolidated financial statements included elsewhere in this prospectus for additional information regarding this agreement.

CCUS Project Development with Verde CO2

On August 22, 2022, we entered into a development agreement with Verde CO2 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. As of October 20, 2022, we have invested $8.3 million to Verde CO2 under the development agreement and we currently expect to invest up to $250.0 million over the next three years to equip efforts by BKVerde, LLC (“BKVerde”), a subsidiary of BKV dCarbon Ventures, with the resources needed to efficiently identify and evaluate a pipeline of feasible CCUS projects, and to execute on those projects, which we expect to finance through cash flow from operations. This investment in CCUS evaluation and development aligns with our goal to reach net zero owned and operated upstream emissions across Scope 1 and 2 by the end of 2025.

Revolving Credit Agreement

On August 24, 2022, we entered into a Revolving Credit Agreement (the “Revolving Credit Agreement”) with Bangkok Bank Public Company Limited (New York Branch), as the administrative agent and sole initial lender. The Revolving Credit Agreement includes $100.0 million of commitments for unsecured revolving loans used for short-term working capital and operating needs. As of October 19, 2022, $45.0 million was outstanding under the Revolving Credit Agreement. 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 more additional information regarding the Revolving Credit Agreement.

Cotton Cove CCUS Project

On October 18, 2022, BKV dCarbon Ventures reached a Phase I FID to develop our second CCUS project to dispose of, and geologically sequester, acid gas and CO2 generated as a byproduct of the production of our natural gas in the Barnett and will utilize our newly acquired BKV Midstream assets. This CCUS project, which we refer to as the Cotton Cove Project, will separate CO2 from our natural gas production in the Barnett. We estimate the Cotton Cove Project will geologically sequester up to 45,000 tons of CO2 per year initially, which we expect will increase to an average of up to 82,350 tons CO2 per year by the end of 2024 through ongoing well development in the area. We currently estimate the total project cost for the Cotton Cove Project to be between $14.0 and $24.0 million. We expect to own or hold the source, the capture, the transportation pipeline and the lease to the pore space with respect to this project. We are targeting commencement of CO2 injection activities by the first half 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 up to eight potential NGP projects that are in different phases of the appraisal and development process. As part of the Cotton Cove Project, we also expect to pilot, and then scale, post-combustion carbon capture technology that would allow us to sequester an additional 250,000 tons per year of captured CO2 from low concentration emissions from within our BKV Midstream operations. We expect that our technology applications will utilize compressor waste heat to reduce energy requirements and cost. We also expect to reduce the cost of low concentration transport and sequestration as the cost of the initial infrastructure build will have been incurred in connection with the high concentration anchor injection. We expect this project to initially offset our current Scope 1 and 2 annual emissions from our owned and operated upstream businesses by approximately 2%, bringing us closer to our goal of reaching net zero across our Scope 1 and 2 owned and operated upstream emissions by the end of 2025.

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Our History

In June 2015, our Chief Executive Officer, Chris Kalnin, and Banpu founded our predecessor, BKV O&G, a Delaware partnership developed for oil and gas investments owned primarily by Banpu and managed by Kalnin Ventures LLC, with the goal of creating long-term sustainable value in the energy industry.

In 2016, BKV O&G acquired from Range Resources a 29.4% interest in certain midstream assets and an approximately 24% interest in certain upstream assets in the Marcellus Chaffee Corners area that are operated by Repsol. From 2017 to 2019, BKV completed a series of other accretive acquisitions, including two major acquisitions of upstream and midstream assets in NEPA from Carrizo Oil and Gas and its non-operated partner, Reliance Industries, and BKV O&G devoted its time to strengthening its technological, exploration, production and operational capabilities.

On May 1, 2020, we completed a corporate restructuring in which we converted all of the interests and assets owned by BKV O&G (the “BKV O&G Conversion”) and also acquired Kalnin Ventures (the “KV Acquisition”). The BKV O&G Conversion and the KV Acquisition resulted in our formation as a new consolidated corporate entity, BKV Corporation. See “— The Corporatization Event” for more information about our corporate restructuring.

In October 2020, we became one of the largest natural gas producers by volume in the Barnett, following our acquisition of more than 289,000 net acres, 3,850 producing operated wells and related upstream assets in the Barnett from Devon Energy (the “Devon Barnett Acquisition”) for a cash purchase price of $570.0 million.

In July 2021, we launched our natural gas-based power generation business with the formation of BKV-BPP Power, a joint venture owned 50% by us and 50% by BPPUS, a wholly owned subsidiary of Banpu Power and an affiliate of our sponsor, Banpu. In November 2021, BKV-BPP Power acquired Temple Generation Intermediate Holdings II, LLC, the owner of 100% of the interests in Temple I, a combined cycle gas turbine and steam turbine power plant located in the ERCOT North Zone in Temple, Texas.

In September 2021, we purchased a non-operated interest spanning over 3,000 net acres from Black Falcon Energy, LLC, a managing company for Jamestown Resources, LLC, Larchmont Resources, LLC and Pelican Energy, LLC in the Barnett and NEPA.

In March 2022, we launched our CCUS business line, BKV dCarbon Ventures, and we reached FID in June 2022 on our first CCUS project, the Barnett Zero Project, with EnLink to dispose of, and geologically sequester, acid gas and CO2 generated as a byproduct of the production of our EnLink-gathered natural gas in the Barnett. Following commencement of commercial operations of our project with EnLink, we intend to use this project as a prototype for modular projects that can be repeated and quickly scaled.

In June 2022, we consummated the Exxon Barnett Acquisition, which also substantially grew our natural gas midstream business. Pursuant to the Exxon Barnett Acquisition, we acquired approximately 175,000 total net acres and 2,100 operated wells primarily in Tarrant, Johnson and Parker counties, and additional smaller positions in Jack, Wise, Denton, Erath, Hood and Ellis counties, Texas. The Exxon Barnett Acquisition also included the addition of 129 employees and approximately 778 miles of gathering pipelines, compression and processing midstream infrastructure.

In August 2022, we entered into a development agreement with Verde CO2 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 and aligns with our goal to reach net zero owned and operated upstream emissions across Scope 1 and 2 by the end of 2025.

The Corporatization Event

Prior to May 1, 2020, BKV O&G held 100% of the outstanding equity interests in BKV Chaffee, BKV Chelsea, BKV Operating and BKV Barnett (the “BKV O&G Group”). During this period, Banpu held approximately 97% of BKV O&G’s limited partner interests, and Kalnin Capital Partners, L.P. (the “General Partner”) held BKV O&G’s general partner interest.

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On May 1, 2020, Banpu and the General Partner incorporated BKV Corporation and restructured BKV O&G through a contribution by Banpu, the other limited partners and the General Partner of all of the partnership interests in BKV O&G to BKV Corporation in exchange for common stock of BKV Corporation. In addition, Kalnin Ventures, which previously managed BKV O&G, was contributed to BKV Corporation in exchange for BKV Corporation common stock. As a result of these transactions, as of May 1, 2020, the BKV O&G Group and Kalnin Ventures became wholly-owned subsidiaries of BKV Corporation. We refer to this series of transactions collectively as the “Corporatization Event.”

Our Relationship with Banpu

BNAC, our majority stockholder, is an indirect, wholly owned subsidiary of Banpu, our ultimate parent company. Immediately prior to this offering, Banpu owned approximately 96.1% of our common stock and will own approximately    % at the completion of this offering (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. However, Banpu is not obligated to continue to hold all or any portion of its ownership in the Company. 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.”

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.

As of the date of this prospectus, Banpu also owns approximately 78.66% of Banpu Power. Banpu Power is a public company listed on the Stock Exchange of Thailand. Banpu Power is the owner of BPPUS, our 50/50 partner in BKV-BPP Power.

See “Certain Relationships and Related Party Transactions” for additional information regarding our relationship with Banpu.

Our Operations

Natural Gas Production

Our Geographic Focus

We are engaged in the acquisition, operation and development of natural gas and NGL properties located primarily in the Barnett (approximately 468,000 net acres) and NEPA (approximately 37,000 net acres) with a combined total company net production of approximately 864 MMcfe/d for the nine months ending September 30, 2022. In addition, we own an aggregate of approximately 4,500 net mineral fee acres located in the Barnett and NEPA. The Barnett has a diversified production stream of natural gas and NGLs located approximately 300 miles from major Gulf Coast industrial centers and LNG export markets. NEPA is composed predominantly of organically rich shale and is generally acknowledged as one of North America’s largest and richest sources of natural gas.

Our upstream assets are predominantly located in the Barnett, which is where horizontal drilling was pioneered and which has the advantage of more than 15 years of technological advancements, proximity to demand hubs and a significant amount of midstream and other infrastructure in place. We also enjoy an average 6.5% 10-year Barnett base production decline on a current production base of approximately 731 MMcfe/d. Using modern technologies, we can drill and complete more profitably and successfully with longer laterals, optimal 750 foot down hole well spacing and latest shale fracturing designs. More than a decade of technological advancements since the discovery of the Barnett, combined with significant remaining gas and NGL resources in place, have created a highly capital efficient opportunity to re-stimulate legacy wellbores

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to meaningfully increase production and enhance recovery factors and reserves. We also have negotiated a midstream contract, covering 44% of our Barnett acreage, that offers incentive gathering and processing rates for new drills and restimulations, enhancing our margins and project economics alike. We entered the Barnett in October of 2020, through our completion of the Devon Barnett Acquisition. As of September 30, 2022, we had 430 new drill horizontal locations and 1,684 horizontal refrac candidates in the Barnett, including those acquired in the Exxon Barnett Acquisition.

We are the largest producer of natural gas in the Barnett, based on publicly reported gross production volume as of March 31, 2022. During the nine months ended September 30, 2022, our Barnett properties, including both operated and non-operated wells, produced 161.0 Bcfe (or an average of 718.6 MMcfe/d). During the year ended December 31, 2021, we produced 190.1 Bcfe (or an average of 520.9 MMcfe/d) from our Barnett properties, including both operated and non-operated wells. We did not drill any of our own operated wells in our Barnett properties during 2021. However, in November 2020, we began a restimulation program to develop economic incremental reserves in existing wellbores and arrest the overall field production decline. In 2021, we led the industry in number of executed horizontal restimulations by completing 213, according to public completion reports.

The image below reflects our Barnett acreage that was acquired in the 2020 Barnett Acquisition (Green) and the Exxon Barnett Acquisition (Blue) and reflects how we are now positioned in the core of the Barnett with transportation to key gulf coast markets. Transportation to the East and the South provide key flexibility and optionality for gas transportation out of the basin. This strategically positions us geographically to utilize existing infrastructure to the gulf without needing to rely on new-build pipelines such as in the Permian and Haynesville.

In NEPA, we have built our position through 12 accretive acquisitions since May 2016. We have an attractive production base comprising approximately 37,000 net acres located primarily in Wyoming, Susquehanna and Bradford counties, Pennsylvania, in one of the most prolific areas of the play. With respect to our operated and non-operated assets in NEPA, our position consists of average 89% working interest

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and 72% NRI on operated wells that yield 100% lean natural gas. We enjoy a significant non-operated position in NEPA. In addition, we have approximately 27 new well locations for near-term development in NEPA.

We are the eighth largest producer in NEPA, on a gross operated production basis. During the nine months ended September 30, 2022 and the year ended December 31, 2021, we produced 36.4 Bcf (or an average of 133.3 MMcf/d) and 56.1 Bcf (or an average of 153.7 MMcf/d), respectively, from our NEPA properties, including both operated and non-operated wells. We did not drill any new wells in NEPA in 2021. During the nine months ended September 30, 2022, we drilled four wells in NEPA. However, we utilized a combination of compression projects and drilled but uncompleted (DUC) well completions to slow production declines and optimize production.

The image below reflects our NEPA acreage (Green), which spans the northeast portion of Pennsylvania and is comprised of both operated and non-operated assets. Our downstream transportation has the flexibility to move West and South into gulf coast markets via the Tennessee Gas Pipeline as well as into the northeast corridor via the Millenium pipeline while also maintaining intra-basin optionality.

Our Technology-Enabled Business

Our integrated business model allows us to develop, test and deploy new technologies to drive efficiencies across the business and to reduce our own emissions. We leverage technology in two important ways: we utilize our Data Lake and in-house data science team to drive efficiencies and insights across the business and we utilize probabilistic modeling approaches and advance risk management techniques to enhance our decision-making abilities, particularly with regards to potential acquisitions. We employ a technology-focused approach, such as utilization of our proprietary instrument air packages, satellite and perimeter pad emissions monitoring, and advanced production and emissions measurement, to enable methane measurement and mitigation, and emission elimination strategies, that reduce CO2e emissions across our operations. We estimate an approximate 72% reduction in BKV Scope 1 and 2 CO2e emissions (inclusive of the Exxon

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Barnett Acquisition) by the end of 2025 from our 2021 baseline using these technological innovations, based on management estimates. We expect that the balance of our Scope 1 and 2 emissions will be offset by CCUS, solar and other mitigations to achieve our goal of Scope 1 and 2 emissions by the end of 2025 for our owned and operated upstream businesses.

Our operations in the Barnett and NEPA have been increasingly automated through a program called “Autotune,” which is an effort to optimize and automate plunger lift systems to increase production through autonomous dynamic tuning of plunger control inputs. This Autotune method utilizes computer algorithms which toggle and optimize various input and control variables for plunger lift systems to increase production time for an average well as compared to a baseline (based on a manual method of managing plunger input and control variables).

We have implemented our “Pad of the Future” program in our upstream business, with the objectives of converting natural gas-powered instrument pneumatics to compressed air-powered functionality on existing pads, significantly reducing our GHG emissions and improving pad efficiencies and economics. In addition, we have implemented emissions surveys, an advanced four-tiered emissions monitoring and mitigation strategy utilizing specialized surveillance technology. We also are in the process of permitting 2.5 MW of commercial solar power, with plans to install up to 10 MW of commercial solar power within the next three years to offset our Scope 2 emissions from our electricity usage in our upstream operations.

In 2021, we certified our NEPA production and 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 our NEPA natural gas production as RSG, which we believe could command a premium in the marketplace. Through RSG production, we provide reliable and affordable energy, while actively participating in the energy transition. In 2022, we plan to certify a portion of our Barnett assets through Project Canary, and anticipate achieving certification more broadly across our Barnett assets in the future.

Our Reserves

The following summarizes our natural gas and oil properties as of September 30, 2022 and our average net daily production for the nine months ended September 30, 2022, including the properties we acquired in the Exxon Barnett Acquisition.

​

September 30, 2022

​

Estimated Total Proved Reserves

​

​

​

​

​

​

​

​

Operating Region

Natural Gas (MMcf)

Natural Gas Liquids (MMBbls)

Oil (MMBbls)

Total (MMcfe)

Average Net Daily Production (MMcfe/d)(1)

Average Reserve Life (years)

Producing Wells

Net Acres

Barnett

​

4,073,171

​

220,587

​

1,743

​

5,407,155

​

730.6

​

20.3

​

6,975

​

467,925

NEPA

​

925,102

​

—

​

—

​

925,102

​

133.3

​

19.0

​

408

​

36,978

Total

​

4,998,273

​

220,587

​

1,743

​

6,332,257

​

863.9

​

20.1

​

7,383

​

504,904

(1)

The production rate for the properties acquired in the Exxon Barnett Acquisition was based on management’s review of the historical accounting information with respect to such assets.

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Based on forecasts used in our reserve reports, our PDP reserves as of September 30, 2022 had estimated average five-year and ten-year annual decline rates of approximately 8.1% and 7.0%. As a result of this overall low decline profile of our natural gas and oil assets, coupled with refrac opportunities that are capital efficient projects, we are able to maintain flat production year over year with relatively low reinvestment rate. We believe the combination of our high margin profile and our conservative reinvestment rate approach, supported by our low decline reserves, will allow us to generate significant Adjusted Free Cash Flow to (i) deliver stockholder returns and (ii) opportunistically fund value accretive growth opportunities.

The following table illustrates the weighted average decline profiles and total production in the first nine months of 2022 associated with our proved reserves as of September 30, 2022:

​

September 30, 2022

Operating Region

Estimated Total Proved Reserves (MMcfe)

% Natural Gas

% Natural Gas Liquids

% Oil

Weighted Average Annual PDP Decline(1)

Five Year

Ten Year

Barnett

​

5,407,155

​

75.3%

​

24.5%

​

0.2%

​

7.3%

​

6.5%

NEPA

​

925,102

​

100%

​

0%

​

0%

​

12.8%

​

9.9%

Total

​

6,332,257

​

78.9%

​

20.9%

​

0.2%

​

8.1%

​

7.0%

(1)

Reflects the estimated average year over year decline rates of our base reserves as of September 30, 2022 for the five-year period ending December 31, 2027 and the ten-year period ending December 31, 2032, in each case based on the forecasts used in estimating our proved reserves.

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The following table summarizes our proved reserves by commodity and proved reserves by location at September 30, 2022:

The following table illustrates the weighted average decline profiles and total production in 2021 associated with our proved reserves as of December 31, 2021:

​

December 31, 2021

Operating Region

Estimated Total Proved Reserves (MMcfe)

% Natural Gas

% Natural Gas Liquids

% Oil

Weighted Average Annual PDP Decline(1)

Five Year

Ten Year

Barnett

​

3,496,235

​

71.5%

​

28.3%

​

0.2%

​

7.0%

​

6.3%

NEPA

​

945,528

​

100%

​

0%

​

0%

​

12.4%

​

9.9%

Total

​

4,441,763

​

77.6%

​

22.3%

​

0.1%

​

8.3%

​

7.2%

(1)

Reflects the estimated average year over year decline rates of our base reserves as of December 31, 2021 for the five-year period ending January 31, 2027 and the ten-year period ending January 31, 2032, in each case based on the forecasts used in estimating our proved reserves.

Our Acreage

The following table summarizes our acreage position as of September 30, 2022:

​

Developed

Undeveloped

Total

Operating Region

Gross

Net

Gross

Net

Gross

Net

Barnett(1)

​

643,008

​

428,269

​

41,803

​

39,656

​

684,811

​

467,925

NEPA

​

61,971

​

28,162

​

20,890

​

8,816

​

82,862

​

36,978

Total

​

704,980

​

456,432

​

62,693

​

48,472

​

767,673

​

504,904

The following table summarizes our acreage position as of December 31, 2021:

​

Developed

Undeveloped

Total

Operating Region

Gross

Net

Gross

Net

Gross

Net

Barnett(1)

​

453,584

​

261,810

​

32,120

​

30,771

​

485,704

​

292,582

NEPA

​

61,971

​

28,162

​

20,890

​

8,816

​

82,862

​

36,978

Total

​

515,555

​

289,973

​

53,010

​

39,587

​

568,566

​

329,560

(1)

Includes acreage acquired during 2021 from Jamestown Resources, L.L.C., Larchmont Resources, L.L.C., and Pelican Energy, L.L.C., for which acreage the leasehold interest is derived from unit-based assignments and includes 133,470.22 gross and 3,317.69 net developed acres, and no undeveloped acres.

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The percentage of our net undeveloped acreage that is subject to lease expiration over the next three years, if such leases are not renewed, is less than 0.03% in 2022, approximately 2.52% in 2023 and 0.40% in 2024.

Our Productive Wells

The following table sets forth our gross and net productive natural gas and oil wells as of September 30, 2022:

​

Producing Natural Gas Wells

Producing Oil Wells

Total

Average Working Interest

​

Gross

Net

Gross

Net

Gross

Net

Barnett

​

5,822

​

5,597

​

9

​

9

​

5,831

​

5,606

​

96.1%

NEPA

​

142

​

126

​

0

​

0

​

142

​

1262

​

88.9%

Total . . . . . . . . . . . . . . . . . . . . . .

​

5,964

​

5,724

​

9

​

9

​

5,973

​

5,733

​

96.0%

Non-operated Wells:

​

​

​

​

​

​

​

Barnett

​

1,122

​

95

​

22

​

0.1

​

1,144

​

96

​

9.9%

NEPA

​

266

​

36

​

0

​

0

​

266

​

36

​

14.3%

Total . . . . . . . . . . . . . . . . . . . . . .

​

1,388

​

132

​

22

​

.1

​

1,410

​

132

​

10.8%

Total Wells:

​

​

​

​

​

​

​

Barnett

​

6,944

​

5,693

​

31

​

9

​

6,975

​

5,702

​

83.9%

NEPA

​

408

​

163

​

0

​

0

​

408

​

163

​

41.0%

Total

​

7,352

​

5,855

​

31

​

9

​

7,383

​

5,864

​

81.5%

The following table sets forth our gross and net productive natural gas and oil wells as of December 31, 2021:

​

Producing Natural Gas Wells

Producing Oil Wells

Total

Average Working Interest

​

Gross

Net

Gross

Net

Gross

Net

Operated Wells:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Barnett

​

3,950

​

3,170

​

8

​

6

​

3,958

​

3,177

​

97.8%

NEPA

​

138

​

101

​

0

​

0

​

138

​

101

​

88.9%

Total

​

4,088

​

3,272

​

8

​

6

​

4,096

​

3,279

​

​

Non-operated Wells:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Barnett

​

838

​

672

​

8

​

6

​

846

​

679

​

3.5%

NEPA

​

256

​

189

​

0

​

0

​

256

​

189

​

13.9%

Total

​

1094

​

861

​

8

​

6

​

1102

​

868

​

​

Total Wells:

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Barnett

​

4,788

​

3,843

​

16

​

12

​

4,804

​

3,856

​

81.2%

NEPA

​

394

​

291

​

0

​

0

​

394

​

291

​

39.9%

Total

​

5,182

​

4,134

​

16

​

12

​

5,198

​

4,147

​

​

Drilling, Refrac and Restimulation Activity

During the years ended December 31, 2021 and 2020, we did not have an active drilling rig running in any of our operated properties, and therefore we did not drill any wells on these properties. During this period, we completed a total of six wells that were previously drilled but uncompleted wells in NEPA. During the nine months ended September 30, 2022, we drilled five wells in NEPA and nine wells in the Barnett, each of which constitutes a gross operated well and net operated development well, that, as of September 30, 2022, four wells were completed in Barnett and three wells were completed in NEPA all of which were net productive.

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In November 2020, we began a restimulation program in the Barnett to develop economic incremental reserves in existing wellbores and arrest the overall field production decline. In 2021, we led the industry in number of executed horizontal restimulations by completing 213, according to public completion reports. Additionally, as of September 30, 2022, we had 430 new drill horizontal locations and 1,684 horizontal refrac opportunities in the Barnett, including those acquired in the Exxon Barnett Acquisition.

Sales Volumes and Unit Prices

The following table summarizes sales volumes, sales prices and production cost information for our net natural gas and production for the nine months ended September 30, 2022 and 2021.

​	Six Months Ended June 30,
​	2022		2021
Sales Volumes	​	​	​	​
Barnett:	​	​	​	​
Natural gas (MMcf)	​	65,345.7	​	64,310.4
Natural gas liquids (MBbl)	​	4,800.2	​	4,913.5
Oil (MBbl)	​	54.4	​	67.0
Total Barnett (Bcfe)	​	94.5	​	94.2
NEPA:	​	​	​	​
Natural gas (MMcf)	​	24,746.2	​	29,148.8
Natural gas liquids (MBbl)	​	0.0	​	0.0
Oil (MBbl)	​	0.0	​	0.0
Total NEPA (Bcfe)	​	24.7	​	29.1
Total Company (Bcfe)	​	119.2	​	123.3

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​	Six Months Ended June 30,
​	2022			2021
Average Sales Prices (excluding impact of derivative settlements)	​	​	​	​	​	​
Barnett:	​	​	​	​	​	​
Natural gas (per Mcf)	​	$	5.77	​	$	2.59
Natural gas liquids (per Bbl)	​	$	33.98	​	$	18.71
Oil (per Bbl)	​	$	94.16	​	$	60.51
NEPA:	​	​	​	​	​	​
Natural gas (per Mcf)	​	$	5.44	​	$	2.15
Natural gas liquids (per Bbl)	​	$	—	​	$	—
Oil (per Bbl)	​	$	—	​	$	—
Total Company (per Mcfe)	​	$	5.70	​	$	2.65
Average Sales Prices (including impact of derivative prices)	​	​	​	​	​	​
Barnett:	​	​	​	​	​	​
Natural gas	​	$	2.27	​	$	2.61
Natural gas liquids (MBbl)	​	$	29.33	​	$	14.45
Oil (MBbl)	​	$	94.16	​	$	60.51
NEPA:	​	​	​	​	​	​
Natural gas (MMcf)	​	$	2.06	​	$	0.94
Natural gas liquids (MBbl)	​	$	—	​	$	—
Oil (MBbl)	​	$	—	​	$	—
Total Company (per McF)	​	$	3.60	​	$	2.46
Average Production Cost (per Mcfe)(1)	​	​	​	​	​	​
Barnett	​	$	1.47	​	$	1.17
NEPA	​	$	0.22	​	$	0.21
Total Company	​	$	1.69	​	$	1.38

(1)

Excludes natural gas and oil ad valorem and production taxes.

The following table summarizes sales volumes, sales prices and production cost information for our net natural gas and production for the years ended December 31, 2021 and 2020.

​	Year Ended December 31,
​	2021		2020
Sales Volumes	​	​	​	​
Barnett:	​	​	​	​
Natural gas (MMcf)	​	129,960.0	​	34,879.1
Natural gas liquids (MBbl)	​	9,829.3	​	2,565.2
Oil (MBbl)	​	123.0	​	28.6
Total Barnett (Bcfe)	​	190.1	​	50.4
NEPA:	​	​	​	​
Natural gas (MMcf)	​	56,095.1	​	61,279.9
Natural gas liquids (MBbl)	​	0.0	​	0.0
Oil (MBbl)	​	0.0	​	0.0
Total NEPA (Bcfe)	​	56.1	​	61.3
Total Company (Bcfe)	​	245.8	​	111.7

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​	Year Ended December 31,
​	2021			2020
Average Sales Prices (excluding impact of derivative settlements)	​	​	​	​	​	​
Barnett:	​	​	​	​	​	​
Natural gas (per Mcf)	​	$	3.58	​	$	1.62
Natural gas liquids (per Bbl)	​	$	22.90	​	$	4.66
Oil (per Bbl)	​	$	61.46	​	$	46.67
NEPA:	​	​	​	​	​	​
Natural gas (per Mcf)	​	$	2.34	​	$	0.74
Natural gas liquids (per Bbl)	​	$	0.00	​	$	0.00
Oil (per Bbl)	​	$	0.00	​	$	0.00
Total Company (per Mcfe)	​	$	3.38	​	$	1.03
Average Sales Prices (including impact of derivative settlements)	​	​	​	​	​	​
Natural gas (per Mcf)	​	$	2.40	​	$	1.87
Natural gas liquids (per Bbl)	​	$	16.76	​	$	12.57
Oil (per Bbl)	​	$	61.46	​	$	31.07
Total Company (per Mcfe)	​	$	2.52	​	$	1.90
Average Production Cost (per Mcfe)(1)	​	​	​	​	​	​
Barnett	​	$	1.31	​	$	0.36
NEPA	​	$	0.23	​	$	0.22
Total Company	​	$	1.06	​	$	0.28

(1)

Excludes natural gas and oil ad valorem and production taxes.

Base Production Optimization

We seek to be a leader in safe, efficient and accretive base production management. We are highly focused on flattening decline while minimizing costs all while reducing our environmental footprint. Automation and optimization play a pivotal role in this focused approach. Our plunger automation program, i.e., “Autotune,” improves the efficiency of our plunger lift systems, resulting in up to 2% improvement in production. Initiatives like automated equipment actuation and automated water call outs serve to minimize response times and reduce manpower requirements. BKV operates a steady and robust workover program, constantly reviewing candidate wells and maintaining a queue of prioritized jobs that provide economic and accretive production uplift. We operate a fleet of over 700 gas lift and wellhead compression units with real time optimization of this fleet. Ensuring our compressors are optimized for each specific facility allows us to maximize production and reduce costs. Other elements of our base management excellence include automated data collection and analysis processes, including well reviews, surveillance dashboards, and process change alerts. Additionally, we monitor and mitigate pipeline pressures, evaluate and implement compression and pressure reduction projects jointly with our midstream partners. We seek to prudently manage and lower operating costs through, for example, purchasing and operating our own slickline units, bringing various maintenance activities in-house which are traditionally third party, negotiating and signing longer term supply and vendor contracts, establishing strategic and advantageous procurement partnerships, leveraging basin scale to achieve organizational and purchasing efficiencies, and maintaining an efficient organizational structure with high performing teams.

Natural Gas Midstream

Our natural gas midstream operations support our upstream assets as well as generate incremental revenue via gathering, processing and transportation of third-party production. In the Barnett, we have extensive infrastructure with capacity across the field and limited additional capital required to connect our wells. Our midstream system in the Barnett operates at low pressure with only approximately 50%

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utilization as of September 30, 2022. In the Barnett, as of September 30, 2022, approximately 220 MMcf/d of our gross production volumes (approximately 29% of our total gross Barnett production) were gathered and processed by our owned Barnett midstream system, with our remaining Barnett production primarily under an agreement with EnLink with no minimum volume commitments. Our owned Barnett midstream system includes approximately 778 miles of gathering pipeline, 64 gas compression units and one amine processing unit.

In NEPA, as of September 30, 2022, our gross operated production volumes were approximately 156 MMcf/d. The volumes flow into third-party gatherers in the following proportions:

•

Williams Companies (“Williams”): 54%

•

UGI Energy Services Midstream Services (“UGI”): 42%

•

Energy Transfer LP (“Energy Transfer”): 4%

Our owned NEPA midstream system includes approximately 16 miles of gas gathering pipelines, 14 miles of freshwater distribution pipelines and six gas compression units. We also have a 29.4% non-operated ownership interest in a Repsol operated midstream system with over 100 miles of gathering pipelines with 450 MMcf/d of capacity and a compression station with approximately 14,000 horsepower. Repsol owns the remaining 70.6% of the system, which has a current throughput of approximately 174 MMcf/d and services both system owner gas and third-party gas.

Gas Gathering & Processing Agreements

The majority of our gross operated production volumes in NEPA are contractually further gathered and treated by three main third parties. As of September 30, 2022, approximately 54%, 42% and 4% of our gross operated volumes in NEPA were further gathered and treated on Williams, UGI, and Energy Transfer gathering systems, respectively. We have secured these services through acreage dedications, pursuant to which current and future production sourced from the specific acreage positions designated in each contract is required to be gathered and treated by each specific entity. Some of our NEPA gas gathering and processing contracts contain limited minimum volume commitment terms (“MVCs”), the earliest of which expire in the first quarter of 2025 and the second quarter of 2029. As of September 30, 2022, such MVCs require us to deliver 36 MMcf/d of natural gas, a majority of which flows into 95 MMcf/d of MVC related the gathering, central delivery point aggregation and intra-basin transport, which currently represents 61% of the gross volumes produced from covered acreage. Overall, the acreage dedication approach, coupled with limited MVCs, provides us strategic flexibility while also securing access to gathering, processing and transportation services. The use of third parties to contractually perform gathering and treating services also negates capital spending requirements for these services and allows us to focus our efforts and capital spend on our core energy and production business.

The terms of these contracts range from 10 and 20 years from original execution date, with an average term of seven years remaining between the various contracts, as of September 30, 2022. The specified rates within these contracts are generally escalated annually subject to a standard Consumer Price Index escalator. These gathering and treating contracts offer deliverability to intra-basin markets, as well as multiple downstream pipelines that offer access to inter and intra-regional markets. This flexibility ultimately provides sufficient liquidity and market optionality that help facilitate the overall process of maximizing corporate netbacks.

For the assets we acquired in the Devon Barnett Acquisition, approximately 99% of our natural gas is gathered and transported by EnLink through various contracts that govern the services provided for the Bridgeport, Ponder and Jarvis systems. The Bridgeport system consists of both rich and lean gas governed by a market-rate based contract, as amended, with a term expiring in 2033. The gathering and processing fees under the Bridgeport contract contain an incentive mechanism pursuant to which we can achieve lower rates through refractured or new wells. All NGLs under the Bridgeport contract are sold to EnLink at Mont Belvieu pricing subject to a market-based transport and fractionation differential. There are no MVCs associated with the natural gas gathering agreements for the assets we acquired in the Devon Barnett Acquisition.

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For the assets we acquired in the Exxon Barnett Acquisition, approximately 90% of our natural gas is gathered and transported through an agreement assigned to our subsidiary, BKV Midstream, through various market-rate based contracts that take lean gas to various delivery points into Energy Transfer’s pipeline. All gas currently flows to Energy Transfer, where BKV is under an acreage dedication for its downstream takeaway. We have one MVC related to the assets acquired in the Exxon Barnett Acquisition for less than $1.0 million per year, which MVC is currently unfulfilled and results in immaterial unutilized gathering charges. However, produced gas that can currently flow through this contract and fulfill the MVC has been rerouted and now flows through BKV’s (formerly XTO Energy, Inc.’s) owned and operated gathering and compression facilities. The decision to construct the facilities, reroute this gas and strand the MVC-based contract was based upon superior economics and results in lower overall gathering and compression fees, even with the inclusion of the unutilized gathering charges. The MVC-based contract expires in the third quarter of 2024.

Power Generation

We have a 50% ownership interest in the BKV-BPP Power Joint Venture, which owns Temple I, a newly-constructed, modern combined cycle gas and steam turbine power plant located in the 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’s power generation output is sold into the competitive wholesale bulk power market managed by ERCOT, Texas’ electrical grid operator. ERCOT currently provides electric power to approximately 23 million people in Texas, with its customers using about 85% of the state’s electric power. The operating flexibility of the power plant provides significant competitive advantages in the ERCOT market. Temple I can generate and supply the power needs of approximately 750,000 households in central Texas.

Operational since July 2014, Temple I’s modern technology enables it to respond to rapidly changing market signals in real time, making it well-suited to serve the various needs of the ERCOT market. Temple I has an average power generation capacity of 755 MW. Key equipment at Temple I includes Siemens natural gas combustion turbine generators and steam turbine generators, as well as Benson heat recovery steam generators. The electrical transmission interconnection at Knob Creek Substation ensures minimal congestion risk. Temple I typically undergoes seasonal maintenance outages in spring and fall to ensure the highest operational readiness during the time when electricity consumption peaks (in winter and summer).

Temple I remained online at full capability during the historic February 2021 Winter Storm Uri and has since implemented incremental upgrades. Temple I has invested over $700,000, with an additional $140,000 in planned expenditures for 2022, to construct winterization enclosures, add insulation, and install heat tracing systems and back-up generators to provide freeze protection around at-risk piping, equipment and instrumentation in the power plant and gas yard. In 2021, a wet compression system was installed to increase the power plant’s output while operating in high ambient temperatures. The system allows a larger volume of air to be compressed before being fed into the combustion process along with natural gas, thus increasing generation capacity during summer, the time when the ERCOT market’s power demand typically peaks. Temple I deploys modern CCGT technology, which combines the working process of gas combustion, turbine and steam turbine generation. It is one of the more flexible CCGTs supplying power the ERCOT system due to its ability to achieve 50% production within 10 minutes and full baseload capacity within 30 minutes. Temple I is also among the most efficient generators supplying power to ERCOT, with a baseload design heat rate of approximately 6,950 Btu/kWh, which is well below the ERCOT CCGT average, as shown in the chart below. Equipped with pollution control management systems to maintain low emissions, the power plant’s high efficiency and flexible operations helps maintain its competitive position in the ERCOT market.

165

The following chart summarizes Temple I’s realized heat rate as compared to other CCGT in ERCOT.

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 to Temple I and its firm intrastate natural gas storage service at the Bammel storage facility. Supplying our own natural gas to Temple I will 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. We intend to continue to build out our power generation business through opportunistic acquisitions of power generation assets and eventually to expand into retail power, which would enable us to ultimately provide net zero wellhead-to-household energy to the end-consumer.

In addition to 75,000 MMBtu/d of firm transportation services with Energy Transfer and its subsidiaries, Temple I’s Bammel storage contract with Energy Transfer provides Temple I up to 2.8 Bcf of natural gas storage capacity, providing daily gas supply operating flexibility. The firm transportation and storage contracts with Energy Transfer and its subsidiaries also grant BKV-BPP Power the option to purchase and store in reserve excess natural gas, which can be released at times when gas prices are potentially higher, such as during seasonal price cycles or times of scarcity. Moreover, the potential to utilize our midstream assets to deliver and optimize natural gas feedstock to the power plant and to expand our CCUS business by sequestering post combustion CO2 from the power plant are additional vertical integration opportunities that we intend to explore over time.

In addition, we are working with Project Canary, an environmental certification and ESG data company, to assess future development of emissions monitoring for the gas supply and combined-cycle electric production at Temple I and to explore the potential ability to certify reliability and low emissions from wellhead to electron. Furthermore, we believe there is significant opportunity from integrated retail gas and power offerings directly to end-user customers and we are in the process of building this capability for the future. We believe we can create a differentiated offering to strategic buyers, retail and industrial customers.

BKV-BPP Power Limited Liability Company Agreement

Temple I is owned by Temple Generation Intermediate Holdings II, LLC, which is owned 100% by BKV-BPP Power, which, in turn, is owned 50% by us and 50% by BPPUS, a wholly owned subsidiary of Banpu Power. See “— Our Relationship with Banpu” and “Certain Relationships and Related Party Transactions.”

We and BPPUS are each a party to the BKV-BPP Power LLC Agreement governing the BKV-BPP Power Joint Venture, which, among other things, provides that a general manager appointed by the BKV-BPP

166

board will have the power to manage and administer the business and affairs of BKV-BPP Power, subject to specified matters reserved for approval by the BKV-BPP board. The appointment and removal of the general manager must be approved by both the BKV-BPP board and BPPUS. Transfer or encumbrance of a party’s interest in BKV-BPP Power is permitted without prior approval of the other party or the BKV-BPP board. However, no transfer will be permitted if the transfer: (A) would subject BKV-BPP Power to U.S. federal securities law reporting requirements, (B) would cause BKV-BPP Power to lose its status as a U.S. partnership for federal income tax purposes or will cause BKV-BPP Power to be classified as a “publicly traded partnership,” ​(C) would violate, give rise to a default under or cause any payment to become due under any credit agreement, guaranty, or similar credit document or any other material contract to which BKV-BPP Power or any affiliate is bound, or (D) occurs prior to the repayment by BKV-BPP Power of all loans and other amounts outstanding under the term loans.

In the event that either party admits in writing that it is unable to perform its obligations (including any obligation to provide additional capital contributions) under the BKV-BPP Power LLC Agreement, the non-defaulting party will be entitled to (i) sell the assets of the joint venture and dissolve the joint venture on reasonable terms deemed acceptable to the BKV-BPP board, (ii) obtain specific performance of the non-defaulting party’s obligations, and/or (iii) exercise any other right or remedy provided in law or in equity.

The BKV-BPP board will determine the amount and timing of distributions of operating cash flow (which will be done no less frequently than once per quarter) and net capital proceeds (which will be distributed within three business days after becoming available for distribution). All distributions will be made on a pro-rata basis to us and BPPUS. As of June 30, 2022, no distributions have been made by BKV-BPP Power. Additional cash capital contributions will be required to be made by us and by BPPUS on a pro-rata basis upon 30 days written notice either by us or by BPPUS; provided that the additional contributions must be expended on items included in the annual approved budget, items in response to an emergency in the event that BKV-BPP Power does not have sufficient cash reserves to address such emergency, or any other matter approved by the BKV-BPP board. Otherwise, neither us nor BPPUS will be required to provide additional capital contributions without consent.

Major decisions and significant activities of BKV-BPP Power are reserved for approval by at least a majority of the members of the BKV-BPP board, such as, among other things, any merger, consolidation, amalgamation, conversion of BKV-BPP or any of its subsidiaries, into another form or entity or other business combination of any nature, wind up, the dissolution, liquidation, commencement or any filing or petition for a voluntary bankruptcy, reorganization, debt arrangement involving BKV-BPP Power, any plan to or initial sale of BKV-BPP Power or other equity interests to the public, any amendments, restatements or revocations of its organizational documents, execution, amendment or termination of a material contract, and any amendment to or deviation from the dividend policy of the joint venture or any of its subsidiaries. Under the terms of the BKV-BPP Power LLC Agreement:

•

we do not have the power to unilaterally cause BKV-BPP Power to make distributions;

•

we may be required to make additional capital contributions to fund items approved in the annual budget or other matters approved by the board of BKV-BPP Power at the request of BPPUS, which would reduce the amount of cash otherwise available for dividend payments by us on our common stock or require us to incur additional indebtedness; and

•

BKV-BPP Power may incur additional indebtedness in an amount greater than $1,500,000 if approved by the board of BKV-BPP Power, which debt payments would reduce the amount of cash that might otherwise be available for distributions to us.

Carbon Capture, Utilization and Sequestration

BKV dCarbon Ventures is our business that is focused on driving CCUS innovations and project development. It is the critical link in our integrated business model chain that we believe will allow us to meet our goal of the full elimination and/or offset of the Scope 1 and 2 emissions in our owned and operated upstream businesses by the end of 2025. We have been evaluating project opportunities and developing our CCUS business for over 20 months. 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,

167

we will begin generating positive CCUS business revenue via tax credits and other tax benefits by the end of 2023, and we expect to begin generating positive Adjusted EBITDAX in 2025.

We seek to execute CCUS projects with attractive standalone economics for high, medium and low CO2 concentration streams that contribute to our goal of the full elimination and/or offset of the Scope 1 and 2 emissions in our owned and operated upstream businesses by the end of 2025.

In March 2022, we formally launched our CCUS business with the establishment of BKV dCarbon Ventures and in June 2022, we reached a Phase I FID on our first high concentration CCUS project in the Barnett with 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, which we expect to achieve an average injection rate of up to 185,000 tons of CO2 per year. We currently estimate the total project cost to us of the Barnett Zero Project to be between $20.0 and $22.0 million. We are targeting commencement of CO2 injection activities by the second half of 2023, subject to our ability to secure all required permits, at which point we expect this project to be one of the first permanent commercial CO2 disposal and sequestration projects to come online in the United States. We estimate this initial CCUS project will represent more than 8% of our estimated Scope 1 and 2 emissions from our owned and operated upstream businesses, with the first injection scheduled for the second half of 2023. Following commencement of commercial operations of our project with EnLink, we intend to use this project as a prototype for modular projects that can be repeated and quickly scaled.

On October 18, 2022, BKV dCarbon Ventures reached a Phase I FID to develop our second CCUS project to dispose of, and geologically sequester, acid gas and CO2 generated as a byproduct of the production of our natural gas in the Barnett and will utilize our newly acquired BKV Midstream assets. This CCUS project, which we refer to as the Cotton Cove Project, will separate CO2 from our natural gas production in the Barnett. We estimate the Cotton Cove Project will geologically sequester up to 45,000 tons of CO2 per year initially, which we expect will increase to an average of up to 82,350 tons CO2 per year by the end of 2024 through ongoing well development in the area. We currently estimate the total project cost for the Cotton Cove Project to be between $14.0 and $24.0 million. We expect to own or hold the source, the capture, the transportation pipeline and the lease to the pore space with respect to this project. We are targeting commencement of CO2 injection activities by the first half 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 up to eight potential NGP projects that are in different phases of the appraisal and development process. As part of the Cotton Cove Project, we also expect to pilot, and then scale, post-combustion carbon capture technology that would allow us to sequester an additional 250,000 tons per year of captured CO2 from low concentration emissions from within our BKV Midstream operations. We expect that our technology applications will utilize compressor waste heat to reduce energy requirements and cost. We also expect to reduce the cost of low concentration transport and sequestration as the cost of the initial infrastructure build will have been incurred in connection with the high concentration anchor injection. We expect this project to initially offset our current Scope 1 and 2 annual emissions from our owned and operated upstream businesses by approximately 2%, bringing us closer to our goal of reaching net zero across our Scope 1 and 2 owned and operated upstream emissions by the end of 2025.

We are rapidly developing our CCUS business and plan to invest additional capital to grow BKV dCarbon Ventures. We are currently partnering with engineering firms to develop our modular, repeatable CO2 capture design and are in various stages of developing additional CCUS projects which include potential joint venture or other commercial arrangements with third parties in the carbon capture and/or storage business. For example, in August 2022, we entered into a development agreement with Verde CO2, an independent carbon capture and sequestration developer and operator, to identify, evaluate and develop additional 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 and aligns with our goal to reach net zero owned and operated upstream emissions across Scope 1 and 2 by the end of 2025. As of October 20, 2022, we have invested $8.3 million to Verde CO2 under the development agreement and we currently expect to invest up to $250.0 million over the next three years to fund efforts by BKVerde, a subsidiary of BKV dCarbon Ventures, to efficiently identify and evaluate a pipeline of feasible CCUS projects, and to execute on those projects. We expect to fund BKVerde through cash flow from BKV operations. This investment in

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CCUS evaluation and development aligns with our goal to reach net zero owned and operated upstream emissions across Scope 1 and 2 by the end of 2025.

We are currently evaluating and discussing with third parties three to ten additional CCUS projects (inclusive of the projects with Verde CO2). Assuming we reach FID with respect to each of these projects, we would expect to develop and complete each of these projects during the next several years based on economics supported by the current carbon tax credit policy in Section 45Q of the Code. For three of these potential CCUS projects, we expect to reach FID within three to six months. We believe these projects could generate an aggregate of up to 4.5 Mtpy CO2e in carbon capture and sequestration on a total capital investment of approximately $520.0 million (inclusive of the investment with Verde CO2). We also are currently evaluating an additional seven potential CCUS projects with respect to which we have begun commercial discussions with third parties. Although each of these potential projects are in different stages of the evaluation process and we have not reached FID or entered into any agreements with respect to any of them, if these potential CCUS projects, together with the Barnett Zero Project and the Cotton Cove Project, are ultimately completed, based on our current estimates we believe these potential projects represent a project pipeline of nearly 30 Mtpy CO2e of carbon capture and sequestration, with the largest potential CCUS project representing approximately 8 Mtpy CO2e and the smallest representing approximately 0.8 Mtpy CO2e. The aggregate number of metric tons of CO2 represented by these potential projects would represent nearly twice the aggregate size of our current Scope 1, 2 and 3 emissions from our owned and operated upstream businesses, which we estimate to be approximately 16.1 Mtpy CO2e as of September 30, 2022.

We estimate the aggregate cost to us to offset all of our Scope 3 emissions through at least some of these ten identified potential projects, to be between approximately $1.3 billion and $1.8 billion over the next seven to ten years. We expect to fund these costs through our cash flows from operations, as well as a variety of external sources, including joint ventures, project-based equity partnerships and federal grants, in each case, to the extent permitted under our credit facilities. We expect to fund these costs through our cash flows from operations, as well as a variety of 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 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. In addition, we anticipate that some of the project costs will be borne by third party investors in these projects, including emitters, landowners and other stakeholders.

For facilities placed in service on or after February 9, 2018 and before January 1, 2023, the current Section 45Q tax credit policy generally provides the capturing parties a tax credit that escalates until 2026, when it reaches $50 per ton for CO2 directly stored in geologic formations, annually escalating for inflation thereafter. For facilities placed in service after December 31, 2022, the credit amount is increased to $85 per ton, subject to satisfaction or nonapplication of certain prevailing wage and apprenticeship requirements (or $17 per ton if applicable prevailing wage and apprenticeship requirements are not satisfied), with adjustments for inflation after 2026. In either case, the Section 45Q tax credit is available for a 12-year period for qualifying facilities that begin construction before January 1, 2033. These CCUS projects will capture and sequester sufficient emission quantities to achieve our upstream Scope 1 and 2 net zero goals (based upon current upstream production without giving effect to the Exxon Barnett Acquisition), in addition to offsetting a portion of our upstream Scope 3 emissions from our owned and operated upstream businesses.

As we strive to become a leader in CCUS, we have on our steering committee 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 have each been engaged in CCUS for over 20 years.

Our CCUS business and all of our CCUS projects are in the early stages of development, and we have not executed any definitive agreements with respect to our identified potential projects. In addition, the development of our CCUS business is expected to require material capital investments, and the commercial viability of our CCUS projects depends, in part, on certain financial and tax incentives provided by the

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U.S. federal government. In particular, we must meet certain wage and apprenticeship requirements in order to qualify for the majority of the Section 45Q tax credits, the details of which have not yet been released and are to be included in future guidance. Our ability to establish large scale CCUS projects is subject to numerous risks and uncertainties, including 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 on the timeline we anticipate, on terms acceptable to us or at all. For more information about the risks involved in our CCUS business, see “Risk Factors — Risks Related to Our CCUS Business.”

Summary of Our Reserve Estimates

Ryder Scott, our independent petroleum engineers, prepared estimates of our natural gas, NGL and oil proved reserves as of December 31, 2021 and 2020, and as of September 30, 2022, including the assets we acquired in the Exxon Barnett Acquisition. These reserve estimates were prepared in accordance with the rules and regulations of the SEC regarding oil and natural gas reserve reporting using SEC Pricing. For more information about our proved reserves, see “Business — Preparation of Reserves Estimates and Internal Controls” and Ryder Scott’s summary reserve reports, which are filed as exhibits to the registration statement of which this prospectus forms a part.

The following table provides our total estimated proved reserve information prepared by Ryder Scott as of September 30, 2022 and December 31, 2021 and 2020 and PV-10 Value and the Standardized Measure for each period. The increase in our proved reserves and the PV-10 Value of those reserves as of September 30, 2022 as compared to December 31, 2021 is primarily due to the Exxon Barnett Acquisition, our refrac and restimulation program and the increase in natural gas prices used in preparing the December 31, 2021 reserve information. There are numerous uncertainties inherent in estimating quantities of proved natural gas, NGL and oil reserves and their values, including many factors beyond our control. See “Risk Factors — Risks Related to Our Upstream Business and Industry — Our estimated proved natural gas, NGL and oil reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in the reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.” For more information about our proved reserves, see “Business —  Preparation of Reserves Estimates and Internal Controls” and Ryder Scott’s summary reserve reports, which are filed as exhibits to the registration statement of which this prospectus forms a part.

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Estimated Proved Reserves at SEC Pricing(1)

​	​	​	​	December 31,
​	September 30, 2022			2021			2020
Estimated proved developed reserves:	​	​	​	​	​	​	​	​	​
Natural gas (MMcf)	​	​	3,857,807	​	​	2,494,926	​	​	1,893,161
Producing	​	​	3,466,758	​	​	2,346,712	​	​	1,893,161
Non-producing	​	​	391,049	​	​	148,214	​	​	0
Natural gas liquids (MBbls)	​	​	177,692	​	​	151,433	​	​	107,234
Producing	​	​	163,830	​	​	142,961	​	​	107,234
Non-producing	​	​	13,862	​	​	8,472	​	​	0
Oil (MBbls)	​	​	1,123	​	​	867	​	​	723
Producing	​	​	1,019	​	​	876	​	​	723
Non-producing	​	​	104	​	​	0	​	​	0
Total estimated proved developed reserves (MMcfe)	​	​	4,930,696	​	​	3,408,723	​	​	2,540,901
Producing	​	​	4,455,853	​	​	3,209,679	​	​	2,540,901
Non-producing	​	​	474,843	​	​	199,044	​	​	0
Estimated proved undeveloped reserves:	​	​	​	​	​	​	​	​	​
Natural gas (MMcf)	​	​	1,140,466	​	​	950,359	​	​	92,373
Natural gas liquids (MBbls)	​	​	42,896	​	​	13,722	​	​	—
Oil (MBbls)	​	​	620	​	​	58	​	​	—
Total estimated proved undeveloped reserves (MMcfe)(3)	​	​	1,401,561	​	​	1,033,040	​	​	92,373
Estimated proved reserves:	​	​	​	​	​	​	​	​	​
Natural gas (MMcf)	​	​	4,998,273	​	​	3,445,285	​	​	1,985,534
Natural gas liquids (MBbls)	​	​	220,587	​	​	165,155	​	​	107,234
Oil (MBbls)	​	​	1,743	​	​	925	​	​	723
Total estimated proved reserves (MMcfe)	​	​	6,332,257	​	​	4,441,763	​	​	2,633,274
Standardized Measure (millions)	​	$	7,648	​	​	2,413	​	​	510
PV-10 (millions)(2)	​	$	9,818	​	$	3,074	​	$	561

(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 September 30, 2022 were $6.127 per MMbtu (Henry Hub), $91.71 per Bbl (WTI Cushing) and pricing equal to 40% of WTI Cushing, (ii) at December 31, 2021 were $3.598 per MMbtu (Henry Hub), $66.56 per Bbl (WTI Cushing) and pricing equal to 39.5% of WTI Cushing and (iii) at December 31, 2020 were $1.985 per MMbtu (Henry Hub), $39.57 per Bbl (WTI Cushing) and pricing equal to 47% of WTI Cushing.

(2)

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

(3)

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

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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. See “Prospectus Summary —​Summary Reserve, Production and Operating Data — Estimated Proved Reserves at SEC Pricing” for a reconciliation of the Standardized Measure to PV-10 as of September 30, 2022 and December 31, 2021 and 2020.

During the nine months ended September 30, 2022 and the year ended December 31, 2021, we incurred costs of approximately $115.5 million and $24.0 million, respectively, to convert 115.9 Bcfe and 45.5 Bcfe, respectively, of proved undeveloped reserves and proved developed non-producing reserves to proved developed reserves. Estimated future development costs relating to the development of our proved undeveloped reserves and proved developed non-producing reserves at September 30, 2022 and December 31, 2021 are approximately $1,311.7 million and $719.0 million, respectively, over the next five years, substantially all of which we expect to finance through cash flow from operations. Our development programs through the first three quarters of 2022 focused on refracturing under-stimulated wells and designing and drilling new wells in both our Barnett and Marcellus assets. All of our PUD reserves are scheduled to be developed within five years of their initial disclosure as PUDs. See “Risk Factors — Risks Related to Our Upstream Business and Industry — The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.”

2021 Activity

During the year ended December 31, 2021, the Company’s proved reserves increased by 1,808.5 Bcfe. The increase in proved reserves was primarily due to increasing commodity pricing improving economics, and additions to the drilling schedule for both proved developed and undeveloped reserves. The Company produced 245.8 Bcfe during the year ended December 31, 2021.

Revisions of previous estimates primarily consisted of upward revisions to proved developed reserves and proved undeveloped reserves of 715.9 Bcfe and 245.6 Bcfe, respectively, as a result of higher average pricing during 2021 for natural gas, NGLs and oil. The remaining upward adjustment of 139.8 Bcfe relates to upward performance adjustments of 219.2 Bcfe offset by a downward revision of 79.4 Bcfe due to increased production costs.

Upon completing our evaluation of properties acquired through our Barnett Asset Acquisition, 550.1  Bcfe of proved undeveloped reserves was recognized for 123 gross (94.8 net) locations added to the Company’s revised drilling schedule during 2021. Additional extensions consisted of proved undeveloped reserves of 143.2 Bcfe related to 13.0 gross (9.6 net) locations in the Marcellus Basin recognized from acquired acreage and the revised 2021 drilling plan. Extensions related to proved developed reserves of 34.8 Bcfe consisted of 14 gross (5.9 net) newly drilled wells.

Improved recoveries consisted of 205.4 Bcfe of proved undeveloped reserves recognized as a result of the application of improved recovery techniques to producing wells during the year ended December 31, 2021.

2020 Activity

During the year ended December 31, 2020, the Company’s proved reserves increased by 1,684.5 Bcfe. The increase in proved reserves was due to the Barnett Asset Acquisition offset by downward revisions primarily due to lower average pricing for natural gas during 2020.The Company produced 111.7 Bcfe during the year ended December 31, 2020.

Revisions of previous estimates primarily consisted of a downward revision of 83.0 Bcfe due to a combination of performance adjustments and lower average pricing of natural gas during 2020, and a downward revision of 171.5 Bcfe which removed locations due to lower average pricing of natural gas during

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2020. Proved developed reserves were adjusted downward by 127.4 Bcfe due to lower average natural gas prices and performance.

There were no extensions and discoveries of proved developed or proved undeveloped reserves during the year ended December 31, 2020.

Preparation of Reserves Estimates and Internal Controls

Our reserve estimates as of December 31, 2020, December 31, 2021 and September 30, 2022 included in this prospectus are based on reports prepared by Ryder Scott, our independent reserve engineer, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC in effect at such time. We rely on Ryder Scott’s expertise to ensure that our reserve estimates are prepared in compliance with SEC rules, regulations and disclosure guidelines and that appropriate geologic, petroleum engineering, and evaluation principles and techniques are applied in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers titled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of June 2019).” Copies of Ryder Scott’s reserve reports are included as exhibits to the registration statement of which this prospectus forms a part.

The person at Ryder Scott responsible for the preparation of the reserve report is Stephen E. Gardner, a Licensed Professional Engineer in the State of Colorado (No. 44720). Mr. Gardner, an employee of Ryder Scott since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level. Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Our internal staff of petroleum engineers, geoscience professionals, operations, land, finance and accounting, and marketing personnel prior to our annual reserves process, work closely together to ensure the integrity, accuracy and timeliness of data so that our reservoir engineering team can review such data and then furnish it to, and work with, our independent reserve engineers in their reserve evaluation process. Our internal reserves process follows a rigorous workflow where the multidisciplinary teams come together to vet our model assumptions and input and get final signoff before our technical team meets with the independent reserve engineers to review properties and discuss methods and assumptions used to prepare reserve estimates. Our Chief Technology Services Officer, Ethan Ngo, is primarily responsible for overseeing the independent reserve engineers during the process. Mr. Ngo has over 14 years of conventional and unconventional experience on and offshore across the lower 48 states with a major oil and gas company, independent oil and gas companies, and a private-equity-backed oil and gas company. Mr. Ngo has a BS in Civil Engineering and Masters in Petroleum Engineering and International Political Economy of Resources from the Colorado School of Mines, and a MBA from the University of Colorado, Denver.

Ryder Scott relies on various data provided by our internal reservoir engineering team in preparing its reserve estimates, including such items as oil and natural gas prices, ownership interests, production information, operating costs, planned capital expenditures and other technical data. Our internal reservoir engineering team consists of qualified petroleum engineers who maintain our internal evaluation of reserves and compare our information to the reserves prepared by Ryder Scott. Management is responsible for designing the internal control procedures used in the preparation of our oil and gas reserves, which include verification of data input into reserve forecasting and economics evaluation software, as well as multi-discipline management reviews. The internal reservoir engineering team reports directly to our Senior Vice President of Engineering.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved behind pipe (proved developed non-producing) oil and gas reserves are new reserves that can be expected to be recovered through existing wells,

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active or shut-in, where expenditure is required to access the new reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. Proved undeveloped reserves on undrilled acreage are limited to those locations on development spacing areas that are offsetting economic producers that are reasonably certain of economic production when drilled. Proved undeveloped reserves for other undrilled development spacing areas are claimed only where it can be demonstrated with reasonable certainty that there is continuity of economic production from the existing productive formation. Proved undeveloped reserves are included only if a development plan has been adopted indicating that such locations are scheduled to be drilled within five years.

Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing, and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices or development and production expenses, may require revision of such estimates. Accordingly, quantities of oil and natural gas ultimately recovered will vary from reserve estimates. See “Risk Factors” for a description of some of the risks and uncertainties associated with our upstream business and reserves.

Reserve estimates are based on production performance, data acquired remotely or in wells, and are guided by petrophysical, geologic, geophysical and reservoir engineering models. Estimates of our proved reserves were based on deterministic methods. In the case of mature developed reserves, reserve estimates are determined by decline curve analysis and in the case of immature developed and undeveloped reserves, by analogy, using proximate or otherwise appropriate examples in addition to volumetric and statistical analyses. The technologies and economic data used in estimating our proved reserves include empirical evidence through drilling results and well performance, well logs and test data, geologic maps and available surface and downhole pressure data, and production and reservoir data. Further, the internal review process of our wells and related reserve estimates includes but is not limited to the following:

•

3D seismic-based subsurface maps,

•

Petrophysical estimates of original gas in place,

•

Volumetric estimates for producing wells,

•

Decline curve analysis,

•

Rate transient and analytical model analysis,

•

Statistical analysis and Monte Carlo simulation, and

•

Fracture modeling.

Our estimated proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. Regional variations in pricing and related deductions are similarly obtained and a 12-month average is calculated at year end.

For the nine months ended September 30, 2022 and the years ended December 31, 2021 and 2020, Ryder Scott and our multidisciplinary team of technical and other professionals jointly reviewed our well performance and future development plans. Following that joint review, we furnished our internal reserve database and supporting data to Ryder Scott to facilitate their preparation of independent reserve estimates and final reports. Access to our database containing reserve information is restricted to select individuals from our engineering department.

Seasonality

Weather conditions have a significant impact on the demand for natural gas used for heating loads and natural gas-fired power generation. Demand for natural gas is generally at its lowest during the spring and fall months and peaks during the summer and winter months. Demand in the winter season peaks due to residential and commercial heating load demand, while the summer season peaks due to cooling loads,

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which calls on increased natural gas fired power generation loads. However, seasonal anomalies such as warmer than normal winters or cooler than normal summers can lessen the magnitude of the seasonal fluctuations in demand. In addition, natural gas storage facilities are utilized to bring additional supply to the market that is utilized to meet peak demand levels during both winter and summer seasons.

In addition to the demand side effects, specific seasonal weather events can also have an effect on available natural gas supply. In recent history, much colder than normal weather has induced wellhead freeze-offs in various regional supply markets, which ultimately lessens supply available to broader markets. Various weather events related to the summer months can similarly have detrimental effects on available supply also.

These seasonal anomalies can also increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations. Similarly, winter months may bring about delays in operational capabilities and efficiency of execution related to new and existing supply.

Enterprise Risk Management (ERM)

We have a standing risk management committee (“RMC”) which meets regularly and assesses, mitigates and provides direction on management of key enterprise risks. RMC members include executives and senior leaders within various functions such as legal, information technology, marketing, regulatory and sustainability, safety, security, operations, finance and accounting, and land.

COVID-19 Impact

Since the start of the COVID-19 pandemic, governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, among other actions, which caused a significant decrease in activity in the global economy and the demand for oil, and to a lesser extent, natural gas and NGLs. As vaccines have become widely available, social distancing guidelines, travel restrictions and stay-at-home orders have eased, activity in the global economy has increased and demand for natural gas, NGLs and oil and related commodity pricing, has improved. However, new variants of the virus could cause further commodity market volatility and resulting financial market instability, and these are variables beyond our control that may adversely impact our operating cash flows, distributions from unconsolidated affiliates, our ability to pay dividends on our common stock and our ability to access the capital markets.

As a producer of natural gas and NGLs, we are recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic. As such, we have continued to operate throughout the pandemic as permitted under these regulations while taking steps to protect the health and safety of our workers. We have implemented protocols to reduce the risk of an outbreak within our field operations and corporate offices, and these protocols have not reduced our production and our throughput in a significant manner. A substantial portion of our non-field level employees currently operate in remote work from home arrangements, and we have been able to effectively maintain our day-to-day operations. We continue to monitor the COVID-19 environment in order to protect the health and safety of our employees and contract workers.

Our supply chain has not experienced any significant interruptions as a result of the COVID-19 pandemic. The lack of a market or available storage for any one NGL product or oil could result in our having to delay or discontinue well completions and commercial production or shut-in production for other products because we cannot curtail the production of individual products in a meaningful way without reducing production of other products. Potential impacts of these constraints may include partial shut-in of production, although we are not able to determine the extent of shut-ins or for how long they may last. However, because some of our wells produce rich gas, which is processed, and some produce lean gas, which does not require processing, we can change the mix of products that we produce and wells that we complete to adjust our production to address takeaway capacity constraints for certain products. For example, we can shut-in rich gas wells and still produce from our lean gas wells if processing or storage capacity of NGL products becomes limited or constrained.

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Customers and Product Marketing

We utilize an unaffiliated third party to market all of our natural gas and oil production to various purchasers, which consist of credit-worthy counterparties, including utilities, LNG producers, industrial consumers, major corporations and super majors, in our industry. This third party collects directly from the purchasers and remits to us the total of all amounts collected on our behalf less their fee for making such sales. We do not believe the loss of any customer would have a material adverse effect on our business, as other customers or markets are currently accessible to us.

Our ability to market oil and natural gas depends on many factors beyond our control, including the extent of domestic production and imports of oil and natural gas, available storage, the proximity of our natural gas and oil production to pipelines and corresponding markets, the available capacity in such pipelines, the demand for natural gas and oil, the effects of weather, and the effects of state and federal regulation. While we have not experienced significant difficulty in finding a market for our production as it becomes available or in transporting our production to those markets, there is no assurance that we will always be able to market all of our production or obtain favorable prices.

Marketing and Differentials

In NEPA, we continually monitor ongoing market dynamics to ensure equity gas sales are well positioned in terms of market optionality and counterparty liquidity. Within our operating area, sales are generally exposed to indices (denoted in parentheses) located on Eastern Gas Pipeline (South), Millennium Pipeline (East Pool), Tennessee Gas Pipeline (Zone 4) and Transco Pipeline (Leidy). From time to time, we will enter into longer-term commitments with downstream pipelines for firm transportation service. As of September 30, 2022, we have multiple contracts for firm transportation services including a combined 90,000 MMBtu/d to various locations on Tennessee Gas Pipeline, 27,500 MMBtu/d on Millennium Pipeline and 20,000 MMBtu on Eastern Gas Pipeline, which provide access to premium markets in New England (Algonquin), the Northeast and Gulf Coast areas. The remaining term on these contracts range from one year to 15 years, with an average remaining duration of 7.5 years as of September 30, 2022.

In the Barnett, we have several firm transportation contracts specific to the Devon Barnett Acquisition to transport natural gas volumes out of the Barnett to premium markets, including 200,000 MMBtu/d to the Katy area, 200,000 MMBtu/d of intra-basin aggregation transport, which feeds 200,000 MMBtu/d of interstate transport to Transco Zone 4 Station 85, and 80,000 MMBtu/d to NGPL-TxOk with term end dates ranging through 2023 and 2024. The capacity to NGPL-TxOk is currently approximately 15,000 MMBtu/d deficient, however we reserve the right to tranche this capacity down annually to match production. BKV is currently negotiating an extension of several Barnett transport agreements to preserve optionality to transport volumes out of the Barnett.

We were assigned 270,000 MMBtu/d of firm transport on Energy Transfer and Houston Pipe Line Company LP in connection with the closing of the Exxon Barnett Acquisition, which contract will expire in 2027. The contract with Energy Transfer and Houston Pipe Line provides access to the NGPL-TxOk market. Additionally, we executed a transaction confirmation with XTO Energy, Inc., which had the structural effect of assigning 170,000 MMBtu/d of firm capacity on Midcontinent Express Pipeline providing access to premium markets at Transco Zone 4 Station 85, which contract will expire in late 2022.

As it relates to Temple I, in addition to 2,812,500 MMBtu of storage at Energy Transfer’s Bammel storage facility which expires in late 2027, BKV-BPP Power holds 75,000 MMBtu/d of firm transport with Energy Transfer and its subsidiaries which supports receipt of gas from the Katy Area with delivery to the Temple Facility and expires in late 2027. Additionally, Temple I holds 125,000 MMBtu/d of interruptible transport with Atmos Pipeline for delivery to Temple I, which terminates upon cancellation by the parties.

Unless otherwise mentioned, under all firm transportation contracts, we pay reservation fees, regardless of usage, to hold transportation rights of the contracted volume on these pipelines for the duration of the contract. Our minimum aggregate required payments per year under firm gathering and transportation agreements are approximately $16.5 million for 2022, $58.0 million for 2023, $42.1 million for 2024, $22.3 million for 2025, $20.5 million for 2026 and $82.5 million for 2027 and beyond. The utilization and economic optimization of the upstream business units’ firm transportation contracts are currently managed

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by Concord Energy, LLC, who acts as the marketing agent for all our upstream marketed volumes. We believe that all NEPA, Barnett and Temple I transport contracts are at competitive rates.

Competition

The oil and gas industry is very competitive, and we compete with a substantial number of other companies, many of which are large, well-established and have greater financial and operational resources than we do. We compete with several other onshore unconventional natural gas producers to deliver our products to the marketplace, some of which include TotalEnergies and Lime Rock Resources (operating in the Barnett), Chesapeake Energy Corporation, Repsol USA, Coterra Energy Inc. and Southwestern Energy Company (operating in NEPA), among others.

Some of our competitors not only engage in the acquisition, exploration, development and production of oil and gas reserves and electricity generation, but also carry-on refining operations and the marketing of refined products. In addition, the oil and gas industry in general competes with other industries supplying energy and fuel to industrial, commercial and individual consumers, including alternative energy sources. Competition is particularly intense in the acquisition of prospective oil and gas properties. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. We also compete with other oil and gas companies to secure drilling rigs, frac fleets, sand and other equipment and materials necessary for the drilling and completion of wells and in the recruiting and retaining of qualified personnel. Such materials, equipment and labor may be in short supply from time to time. Shortages of equipment, labor or materials may result in increased costs or the inability to obtain such resources as needed. Many of our larger competitors may have a competitive advantage when responding to commodity price volatility and overall industry cycles. Further, the current inflation may affect us more than it may affect some of our larger competitors.

Environmental, Health, Safety and Climate Change Considerations

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 ESG goals.

We have established a Working Team consisting of a cross-functional group of BKV leaders who specialize in ESG strategy that meets periodically to identify, assess and implement critical ESG program initiatives. In addition, we have a Risk Management Committee that includes representatives from our operations, legal, finance, investor relations, information technology, marketing and environmental compliance teams and meets periodically to review potential ESG and other risks, tracks how these risks may be changing and ensures they are being properly managed. Our executive short-term incentive plan is tied to ESG-related initiatives, such as operational safety goals, social goals related to employee engagement and the establishment and implementation of our ESG program. In 2021, we exceeded our operational safety goals by having zero major incidents (such as well control issues or explosions), having zero regulatory reportable violations and having zero reportable incidents or injuries. In 2021, we exceeded our social goals relating to employee engagement with greater than 80% employee participation in our employee engagement survey, which led to the identification of areas for improvement, including career development and recognition and feedback. And, we exceeded our ESG program goals by establishing our baseline score for transparent quantification of BKV’s emission inventory and developing and executing initial steps toward emission reduction. The baseline ESG impact will be utilized to measure our emission reduction goals in the future.

We also have established robust Environmental, Health, Safety and Regulatory (“EHSR”) goals with proven results. At the management level, our EHSR programs are overseen directly by our Chief Executive Officer and Chief Operating Officer. Our Director of EHSR reports to our Chief Operating Officer, providing direct access to executive management and decision-making with respect to our top priority focus of EHSR performance. Our safety performance ranks high in comparison to our peers, and we have achieved a Total Recordable Incident Rate (TRIR) of zero in 2019 through 2021, which includes both our employees and our contractors. In the past three years, our employees have driven a total average of nearly 3,000,000 miles per year, during which time we have had zero at-fault driving incidents. Regarding our environmental and safety performance, we have received zero notices of violation in 2020, 2021 and through the date of this prospectus that have carried a penalty. We have established a four-tiered emissions

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monitoring ecosystem through which we monitor our wells and facilities via satellite, fixed wing aircraft, continuous perimeter sensors (largely through our Project Canary partnership), and handheld Forward Looking Infrared (FLIR) cameras. We will self-audit our environmental management system in the third quarter of 2022 for alignment to ISO 14001 (a set of environmental management standards). We have certified 100% of our production in NEPA with Project Canary TrustWell and achieved a Gold rating for all wells; a strong rating that will enable us to sell RSG. As of September 2022, we have received TrustWell certification for 168 wells on 64 pads and have achieved Gold rating for these wells. We expect to continue the TrustWell certification process throughout our Barnett assets in the coming years.

As a top 20 gas-weighted natural gas producer in the U.S. market, we believe we have a significant opportunity to reduce our environmental footprint by reducing GHG emissions through a series of strategic projects and technological commitments, and by offsetting remaining operational emissions. We have set a goal of reaching net-zero emissions across Scopes 1 and 2 by the end of 2025. To address our Scope 1 and 2 emissions between 2021 and 2022, we are investing approximately $8.8 million in 2022 to reduce emissions from our operations. These investments will allow us to prototype and deploy electrified components into the production processes, convert pneumatic gas instruments, enhance measurement technology, remove redundant equipment and develop and draw on renewable energy sources, among other operational improvements. For our Scope 3 profile, we aspire to offset 100% of our combined Scope 1, 2 and 3 emissions from our owned and operated upstream businesses by the early 2030s. We believe we have a path to these net-zero goals through the expansion of our carbon negative businesses, such as significant expansion of our CCUS activities and our ongoing BKV dCarbon Ventures efforts. We believe we can achieve this goal if certain of the ten identified potential CCUS projects in our project pipeline are completed upon terms that we believe are obtainable. In addition to these identified projects, we expect to continue to identify and evaluate additional CCUS projects, some of which are already in a preliminary screening stage.

Our CCUS business and all of our CCUS projects are in the early stages of development and we have not executed any definitive agreements with respect to the ten identified potential projects. In addition, the development of our CCUS business is expected to require material capital investments and the commercial viability of our CCUS projects depends, in part, on certain financial and tax incentives provided by the U.S. federal government. Our ability to establish large scale CCUS projects is subject to numerous risks and uncertainties and we may be unable to execute on some or all of these projects on terms acceptable to us or at all. For more information on our CCUS business, see “— Our Operations — Carbon Capture, Utilization and Sequestration.” For more information about the risks involved in our CCUS business, see “Risk Factors — Risks Related to Our CCUS Business.” Another way we are enabling CO2 emission reduction from our operations is by increasing our production of RSG. We received Project Canary’s TrustWell environmental assessment Gold rating in 2021 across our entire Marcellus Shale (NEPA) operations, earning the highest score achieved for wells taken over by a new operator.

Human Capital Resources

As of December 31, 2021, we had a total of 219 employees. As of July 1, 2022, we had a total of 356 employees, which includes employees added following the completion of the Exxon Barnett Acquisition. We hire independent contractors on an as needed basis. We believe we have good relations with our employees. We and our employees are not subject to any collective bargaining agreements.

Safety.   Safety is our highest priority, including the prevention of any releases from our operations. We conduct routine maintenance and inspections at our facilities, and we have established practices and operational infrastructure to control and mitigate potential spills or discharges. We also offer annual specialized training to staff on spill prevention and host routine Response Tabletop Sessions to ensure our teams are fully trained on our response plan in the event of any releases. We believe these measures continue to strengthen our process safety culture.

Compensation and Benefits.   We recognize that our employees are our most valuable resource and that we must provide competitive compensation to ensure we attract and retain top talent. As part of our commitment to these efforts, we underwent a third-party evaluation to confirm our compensation was both competitive and reflective of the work our employees were performing. In 2021, we assessed our existing compensation strategy and have begun working towards standardizing salary ranges. We have implemented

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a compensation framework that strives to pay employees fairly and consistently based on their skills, experience and performance and that we believe is competitive compared to other companies in our industry.

To foster the health and well-being of our employees and their families, we offer all of our full- and part-time employees access to financial, health and wellness programs. We also offer a matched 401(k) plan, short-term and long-term incentive plans, medical insurance coverage, parental leave, and paid time off for holidays, personal days and vacation.

Diversity and Inclusion.   We strongly believe that a diverse workforce fosters new ideas and makes us stronger as a company. Providing a safe, inclusive working environment for our employees and contractors is among our top priorities. Our executive leaders are committed sponsors and supporters of programs that foster an increase in diverse demographic representation, nurture the careers of underrepresented groups and create a greater sense of inclusion and belonging.

In 2021, we implemented a new code of business conduct, updating our employee policies and completing an employee handbook refresh. Among the policies that were updated was our whistleblower policy. In conjunction with the update of the whistleblower policy, we launched our confidential ethics and compliance hotline (in addition to our online submission portal).

In 2022, we implemented a comprehensive manager and employee online training program across the Company that includes topics such as business ethics, human rights and diversity, equity and inclusion and that will be tracked to ensure participation.

We are also prioritizing the formal buildout of employee resource groups to create more opportunity for colleagues and peers to connect with others facing similar situations or challenges.

Human Rights.   Providing a safe, inclusive working environment for our employees and contractors is a priority. We do not tolerate discrimination or harassment of any kind. We also have a Human Rights Policy that applies to all of our employees and is aligned with the UN Declaration of Human Rights and the UN Guiding Principles on Business and Human Rights. We continue to monitor the effectiveness of our human rights policy with the goal of growing and aligning our business to the dynamic rights of our workforce. Our Human Rights Policy extends to all our operations, as well as partners and suppliers, including security providers.

Recruitment, Retention and Development.   We provide equal opportunity for all employees and consultants regardless of race, religion, gender, sexual orientation, age, ethnic or national origin, social origin, disability, family status or any other protected status and personal characteristics for all aspects of employment. This applies to recruitment and talent attraction, training and professional development opportunities, promotions and all employee benefits. Additionally, we prioritize local hiring for both employees and contractors, particularly in areas of field operations, to support employment opportunities in our local communities.

Government Regulation and Environmental Matters

Our operations are subject to extensive federal, state and local laws and regulations that govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. These laws, rules and regulations may, among other things:

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require the acquisition of various permits before drilling commences;

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require notice to stakeholders of proposed and ongoing operations;

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require the installation of expensive pollution control equipment;

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restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling and production and saltwater disposal activities;

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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, or otherwise restrict or prohibit activities that could impact the environment, including water resources; and

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require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to plug and abandon wells.

Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities for failure to comply. Violations and liabilities with respect to these laws and regulations could also result in remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and cash flows. In certain instances, citizens or citizen groups also have the ability to bring legal proceedings against us if we are not in compliance with environmental laws or to challenge our ability to receive environmental permits that we need to operate. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of June 30, 2022, we have recorded asset retirement obligations of $209.3 million attributable to these activities. The regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general.

We believe that we are in material compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition, results of operations or cash flows. Nevertheless, changes in existing environmental laws or regulations or the adoption of new environmental laws or regulations, including any significant limitation on the use of hydraulic fracturing, could have the potential to adversely affect our financial condition, results of operations and cash flows. Federal, state or local administrative decisions, developments in the federal or state court systems or other governmental or judicial actions may influence the interpretation or enforcement of environmental laws and regulations and may thereby increase compliance costs. Environmental regulations have historically become more stringent over time, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation.

The following is a summary of the significant environmental laws to which our business operations are subject.

CERCLA.   The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, is also known as the “Superfund” law. CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on parties that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Such “responsible parties” may be subject to joint and several liability under CERCLA for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own or lease properties that have been used for the exploration and production of natural gas, NGLs and oil for a number of years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other wastes may have been disposed of or released on or under the properties currently owned or leased by us. Many of these properties have been operated by third parties whose treatment or release of hydrocarbons or other wastes was not under our control. These properties, and any wastes that may have been released on them, may be subject to CERCLA, and we could potentially be required to investigate and remediate such properties, including soil or groundwater contamination by prior owners or operators, or to perform remedial plugging or pit closure operations to prevent future contamination. States also have environmental cleanup laws analogous to CERCLA, including Texas.

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RCRA.   The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, the individual states administer some or all of the provisions of RCRA. While there is currently an exclusion from RCRA for drilling fluids, produced waters and most of the other wastes associated with the exploration and production of oil or gas, it is possible that some of these wastes could be classified as hazardous waste in the future and therefore be subject to more stringent regulation under RCRA. For example, in December 2016, the EPA and certain environmental organizations entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production-related oil and gas wastes from regulation as hazardous wastes under RCRA. The consent decree required the EPA to propose a rulemaking no later than March 15, 2019, for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary; the EPA ultimately determined that a revision was not necessary. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes that may be regulated as hazardous wastes if such wastes have hazardous characteristics.

Oil Pollution Act.   The Oil Pollution Act of 1990, or the OPA, contains numerous restrictions relating to the prevention of and response to oil spills into waters of the United States. The term “waters of the United States” has been interpreted broadly to include inland water bodies, including wetlands and intermittent streams. The OPA imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs, and certain other damages arising from a spill. As such, a violation of the OPA has the potential to adversely affect our business, financial condition, results of operations and cash flows.

Clean Water Act.   The Clean Water Act and implementing regulations, which are primarily executed through a system of permits, also govern the discharge of certain pollutants into waters of the United States. Enforcement for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities or to cease hauling wastewaters to facilities owned by others that are the source of water discharges to resolve non-compliance. The Clean Water Act also requires the preparation and implementation of Spill Prevention, Control and Countermeasure Plans in connection with on-site storage of significant quantities of oil. In 2016, the EPA finalized new wastewater pretreatment standards that would prohibit onshore unconventional oil and gas extraction facilities from sending wastewater to publicly-owned treatment works. This restriction of disposal options for hydraulic fracturing waste may result in increased costs. In addition, state laws analogous to the Clean Water Act also may require permits for certain of our operations.

Safe Drinking Water Act.   The SDWA and comparable local and state provisions restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including oil and gas wastewater disposal wells or enhanced oil recovery) is governed by U.S. federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. The SDWA’s Underground Injection Well Program requires that we obtain permits from the EPA or delegated state agencies for our disposal wells, establishes minimum standards for injection well operations, restricts the types and quantities of fluids that may be injected and prohibits the migration of fluid containing any contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources, and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages, and personal injuries. In addition, in some instances, the operation of underground injection wells has been alleged to cause earthquakes (induced seismicity) as a result of flawed well design or operation. This has resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground

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injection wells, and regulators in some states have imposed or are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise, to assess the relationship between seismicity and the use of such wells. The adoption of federal, state and local legislation and regulations intended to address induced seismic activity in the areas in which we operate could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could result in increased costs and additional operating restrictions or delays.

We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells in which we act as operator. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional plays, and is generally exempted from federal regulation as underground injection (unless diesel is a component of the fracturing fluid) under the SDWA. Concerns have been raised that hydraulic fracturing activities, separate and apart from use of injection wells, may be correlated to induced seismicity. In addition, EPA conducted a comprehensive study of the potential adverse impacts of hydraulic fracturing on drinking water and ground water and released its final report on this study in December 2016. The report found that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. This study and other studies that may be undertaken by the EPA or other federal agencies could spur initiatives to further regulate hydraulic fracturing under the SDWA, the Toxic Substances Control Act, or other statutory and/or regulatory mechanisms, which could lead to operational delays, increased operating and compliance costs and additional regulatory burdens that could make it more difficult or commercially impracticable for us to perform hydraulic fracturing. Such costs and burdens could delay the development of unconventional gas resources from shale formations, which are not commercially feasible without the use of hydraulic fracturing.

Chemical Disclosures Related to Hydraulic Fracturing.   A number of states, including Texas, have implemented chemical disclosure requirements for hydraulic fracturing operations. We currently disclose all hydraulic fracturing additives we use on www.FracFocus.org, a website created by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission.

Prohibitions and Other Regulatory Limitations on Hydraulic Fracturing.   There have been a variety of regulatory initiatives at the state level to restrict oil and gas drilling operations in certain locations.

In addition to chemical disclosure rules, some states have implemented permitting, well construction or water withdrawal regulations that may increase the costs of hydraulic fracturing operations. For example, Texas has water withdrawal restrictions allowing suspension of withdrawal rights in times of shortages while other states require reporting on the amount of water used and its source.

Increased regulation of and attention given by environmental interest groups, as well as state and federal regulatory authorities, to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and gas, including from developing shale plays, or could make it more difficult to perform hydraulic fracturing. These developments could also lead to litigation challenging proposed or existing wells. The adoption of federal, state or local laws or the implementation of regulations regarding hydraulic fracturing that are more stringent could cause a decrease in the completion of new oil and gas wells, as well as increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows. We use hydraulic fracturing extensively and any increased federal, state, or local regulation of hydraulic fracturing could reduce the volumes of oil and gas that we can economically recover.

Clean Air Act.   Our operations are subject to the Clean Air Act, or the CAA, and comparable state and local requirements to control emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permitting requirements. Federal and state laws designed to control toxic air pollutants and GHGs might require installation of additional controls. Payment of fines and correction of any identified deficiencies generally resolve any failures to comply strictly with air regulations or permits. However, in the event of non-compliance, regulatory agencies could also require us to cease construction or operation of certain

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facilities or to install additional controls on certain facilities that are air emission sources. Further, stricter requirements could negatively impact our production and operations.

In 2012, the EPA published final New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS, that amended the existing NSPS and NESHAP for the oil and natural gas sector. In June 2016, the EPA published a final rule that updated and expanded the NSPS by setting additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. In June 2017, the EPA proposed a two-year stay of certain requirements contained in the June 2016 rule. In March 2018, the EPA published a final rule that amended two narrow provisions of the NSPS, removing the requirement for completion of delayed repair during emergency or unscheduled vent blowdowns. In September 2020, the EPA published a final rule amending the 2012 and 2016 NSPS for the oil and natural gas sector that removed transmission and storage sources from the oil and natural gas industry source category and rescinded the methane requirements applicable to the production and processing sources. On June 30, 2021, President Biden signed into law a joint Congressional resolution under the Congressional Review Act nullifying the September 2020 rule amending the EPA’s 2012 and 2016 NSPS standards for the oil and natural gas sector and effectively reinstating the prior standards. On November 15, 2021, the EPA proposed rules to reduce methane emissions from both new and existing oil and natural gas industry sources. The EPA has announced that it hopes to finalize these rulemakings by the end of 2022. The reinstatement of direct regulation of methane emission for new sources and the promulgation of requirements for existing oil and gas sources and enhanced requirements for new sources could result in increased compliance costs or otherwise impact our results of operations. For additional information, see “Risk Factors — Risks Related to Environmental, Legal Compliance and Regulatory Matters-Our operations are subject to a series of risks relating to climate change that could result in increased compliance or operating costs, limit the areas in which we may conduct natural gas exploration and NGL exploration and production activities, and reduce demand for the natural gas and NGLs we produce.”

In October 2015, the EPA revised the existing National Ambient Air Quality Standards for ground level ozone to make the standard more stringent. The EPA finished promulgating final area designations under the new standard in 2018, which, to the extent areas in which we operate have been classified as non-attainment, may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. Generally, it will take the states several years to develop compliance plans for their non-attainment areas. While we are not able to determine the extent to which this new standard will impact our business at this time, it has the potential to have a material impact on our operations and cost structure.

In June 2016, the EPA finalized a rule “aggregating” individual wells and other facilities and their collective emissions for purposes of determining whether major source permitting requirements apply under the CAA. These changes may introduce uncertainty into the permitting process and could require more lengthy and costly permitting processes and more expensive emission controls.

Collectively, these rules and proposed rules, as well as any future laws and their implementing regulations, may require a number of modifications to our operations. We may, for example, be required to install new equipment to control emissions from our well sites or compressors at initial startup or by the applicable compliance deadline. We may also be required to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

Greenhouse Gas and Climate Change Laws and Regulations.   Scientific studies have concluded that increasing concentrations of GHGs in the Earth’s atmosphere are producing climate changes that have significant physical effects. Potential physical risks resulting from climate change may be event driven (including increased severity of extreme weather events, such as hurricanes, droughts, or floods) or longer-term shifts in climate patterns that may cause sea level rise or chronic heat waves. Potential physical risks may cause direct damage to our assets as well as indirect impacts such as supply chain disruption and also could include changes in water availability, sourcing, and quality, which could impact drilling and completion operations. These physical risks could cause increased costs, production disruptions, lower revenues and substantially increase the cost or limit the availability of insurance. In response to studies indicating that emissions of carbon dioxide and certain other GHGs, including methane, are contributing to global climate

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change, there is increasing focus by local, state, regional, national and international regulatory bodies as well as by investors and the public on GHG emissions and climate change issues.

While the United States has yet to adopt comprehensive climate change legislation, the federal government has taken a series of administrative actions aimed at curtailing GHG emissions. For example, in response to 2009 findings that emissions of CO2, methane and other GHGs present an endangerment to public health and the environment, the EPA issued regulations to restrict emissions of GHGs under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources.

In August 2015, the EPA promulgated the Clean Power Plan (“CPP”) rule to limit CO2 emissions from existing coal and natural-gas fired electric generating units. The CPP rule, which never went into effect, adopted a sector-wide, generation shifting approach and determined the best system of emissions reduction (BSER) for CO2 at coal and natural-gas fired units included three components — heat rate improvement at existing coal-fired units, a shift in generation from coal-fired to natural-gas fired units, and a shift in generation from natural-gas fired facilities to renewables. Several industry groups and states challenged the CPP rule. On February 9, 2016, the U.S. Supreme Court stayed the implementation of the CPP rule pending judicial review. In August 2019, the EPA repealed the CPP rule and replaced it with the Affordable Clean Energy rule, or ACE rule, which adopted a narrower, source-based approach limited to designating heat rate improvement, or efficiency improvement, as the BSER for CO2 from existing coal-fired electric generating units. The ACE rule and the repeal of the CPP rule were challenged by several states and private parties. On January 19, 2021, the D.C. Circuit vacated the ACE rule but at the EPA’s request subsequently stayed issuance of the portion of the mandate that would have vacated the repeal of the CPP rule while the EPA decided whether it would promulgate a new rule instead of the CPP rule. On October 29, 2021, the U.S. Supreme Court agreed to review the D.C. Circuit’s decision, and on June 30, 2022 the U.S. Supreme Court ruled that the generation-shifting approach included in the CPP rule exceeded EPA’s statutory authority under the CAA. The EPA is expected to propose new rules to regulate GHG emissions from electric generating units, but whether and how such rules would affect our business is uncertain.

The EPA has issued the “Final Mandatory Reporting of Greenhouse Gases” Rule and a series of revisions to it, which requires operators of oil and gas production, natural gas processing, transmission, distribution and storage facilities and other stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report annually their GHG emissions occurring in the prior calendar year on a facility-by-facility basis. The EPA widened the scope of annual GHG reporting to include not only activities associated with completion and workover of gas wells with hydraulic fracturing and activities associated with oil and gas production operations, but also completions and workovers of oil wells with hydraulic fracturing, gathering and boosting systems, and transmission pipelines. These rules do not require control of GHGs. However, the EPA has indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG limits. More recently, on November 15, 2021, the EPA proposed rules to reduce methane emissions from new and modified sources in the oil and gas sector.

In certain circumstances, large sources of GHG emissions are subject to preconstruction permitting under the EPA’s Prevention of Significant Deterioration program. This program historically has had minimal applicability to the oil and gas production industry. However, there can be no assurance that our operations will avoid applicability of these or similar permitting requirements, which impose costs relating to emissions control systems and the efforts needed to obtain the permit.

In April 2016, the United States signed the Paris Agreement, which requires countries to review and “represent a progression” in their intended nationally determined contributions (“NDC”), which set GHG emission reduction goals, every five years beginning in 2020. In November 2019, the Trump Administration formally moved to exit the Paris Agreement, initiating the treaty-mandated one-year process at the end of which the United States officially exited the agreement. However, the current Presidential administration has made climate change a central priority and on January 20, 2021, his first day in office, President Biden announced its intention to rejoin the Paris Agreement. The United States officially rejoined the Paris Agreement on February 19, 2021, and in April 2021 submitted its NDC. The United States NDC sets an economy-wide target of net GHG emissions reduction from 2005 levels of 50-52% by 2030. The specific measures to be taken in furtherance of achieving this target have not been established, but the NDC submission

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indicated that an interagency approach will play an important role, including regulatory, technology and policy initiatives designed to reduce the generation of GHG emissions and to incentivize the capture and geologic sequestration or utilization of carbon dioxide that would otherwise be emitted in the atmosphere. Also on his first day in office, President Biden signed an executive order on climate action and reconvened an interagency working group to establish interim and final social costs of three GHGs: carbon dioxide, nitrous oxide, and methane. Carbon dioxide is released during the combustion of fossil fuels, including natural gas, NGLs and oil, and methane is a primary component of natural gas. The Biden Administration stated it will use updated social cost figures to inform federal regulations and major agency actions and to justify aggressive climate action as the United States moves toward a “100% clean energy” economy with net-zero GHG emissions.

The United States Congress has also passed a number of bills in recent years aimed at addressing climate change in a limited manner, primarily directed at funding climate change initiatives. The 2021 Infrastructure and Investment Jobs Act passed by Congress in November 2021 included measures aimed at decarbonization to address climate change, including funding for replacing transit vehicles, including buses, with zero- and low-emission vehicles and for the deployment of an electric vehicle charging network nationwide. This legislation, and other future laws, that promote a shift toward electric vehicles could adversely affect the demand for our products. Similarly, the Inflation Reduction Act, recently passed by Congress, imposed several new climate-related requirements on oil and gas operations. Moreover, in August 2022, the U.S. Congress passed, and President Biden signed into law, the Inflation Reduction Act of 2022, which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on GHG emissions from certain facilities. The emissions fee and funding provisions of the law could increase our operating costs and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations.

In the absence of comprehensive climate change legilation at the federal level, a number of state and regional efforts have emerged. These include measures aimed at tracking and/or reducing GHG emissions through cap-and-trade programs, which typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting GHGs. In addition, a coalition of over 20 governors of U.S. states formed the United States Climate Alliance to advance the objectives of the Paris Agreement, and several U.S. cities have committed to advance the objectives of the Paris Agreement at the state or local level as well. To this end, the California governor issued an executive order on September 23, 2020 ordering actions to pursue GHG emissions reductions, including a direction to the California State Air Resources Board to develop and propose regulations to require increasing volumes of new zero-emission passenger vehicles and trucks sold in California over time, with a targeted ban of the sale of new gasoline vehicles by 2035.

If we are unable to recover or pass through a significant portion of our costs related to complying with current and future regulations relating to climate change and GHGs, it could materially affect our operations and financial condition. Any future laws or regulations that limit emissions of GHGs from our equipment and operations could require us to both develop and implement new practices aimed at reducing GHG emissions, such as emissions control technologies, which could increase our operating costs and could adversely affect demand for the oil and gas that we produce. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of, and access to, capital. Future implementation or adoption of legislation or regulations adopted to address climate change could also make our products more or less desirable than competing sources of energy. At this time, it is not possible to quantify the impact of any such future developments on our business.

OSHA.   We are subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations, and the provision of such information to employees, state and local government authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations.

Endangered Species Act.   The ESA was established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas it believes are necessary for survival of a threatened or endangered species.

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While some of our facilities are in areas that may be designated as a habitat for endangered species, we believe that we are in substantial compliance with the ESA. The presence of any protected species or the final designation of previously unprotected species as threatened or endangered in areas where we operate could result in increased costs from species protection measures or could result in limitations, delays, or prohibitions on our exploration and production activities that could have an adverse effect on our ability to develop and produce our reserves.

National Environmental Policy Act.   Oil and gas exploration and production activities on federal lands trigger review under the National Environmental Policy Act. The National Environmental Policy Act requires federal agencies, including the U.S. Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment of the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed environmental impact statement that may be made available for public review and comment. This process has the potential to delay or even halt development of some of our oil and gas projects.

Operating Hazards and Insurance

Natural gas, NGLs and oil operations are subject to many risks, including well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, pipe, casing or cement failures, abnormal pressure, pipeline leaks, ruptures or spills, vandalism, pollution, releases of toxic gases, adverse weather conditions or natural disasters and other environmental hazards and risks.

In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot provide assurance that any insurance we obtain will be adequate to cover our losses or liabilities. We have elected to self-insure for certain items for which we have determined that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

The insurance policies we currently maintain, and their respective policy limits, are as follows:

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Commercial General Liability:   $2,000,000 annual general aggregate policy limit or $1,000,00 per occurrence.

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Property:   annual aggregate policy limits of $1,575,715 for personal property and $50,000 to $3,200,000 for certain real property.

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Operators Extra Expense:

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$25,000,000 per occurrence limit for wells located in Pennsylvania;

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$15,000,000 per occurrence limit for wells located in Texas;

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$30,000,000 per occurrence additional limit for property under our care, custody or control;

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$2,500,000 per occurrence additional limit for certain materials and supplies; and

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Oil Lease Property:   $314,293,392 annual aggregate policy limit for physical loss and/or physical damage to certain scheduled onshore property.

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Business and Contingent Business Interruption:   $64,240,000 annual aggregate limit per accident or occurrence, or $176,000 per day.

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Site Pollution Incident Legal Liability:   $11,000,000 annual aggregate policy limit, with a $10,000,000 limit per incident.

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Management Liability:

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$5,000,000 annual aggregate policy limit for director, officer and organizational liability, with an additional $1,000,000 of coverage for claims against certain insured persons;

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$2,000,000 annual aggregate policy limit for employment practices liability;

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$1,000,000 aggregate policy limit for fiduciary liability; and

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$1,000,000 for certain crime liability.

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Automobile Liability:   $1,000,000 aggregate policy limit.

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Workers’ Compensation:   limited to the value of the benefits required under Colorado, Montana, Oregon, Pennsylvania or Texas law, as applicable.

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Employer’s Liability:   $1,000,000 limit per accident for bodily injury by accident, and $1,000,000 aggregate policy limit for bodily injury by disease.

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Umbrella Excess Liability:   $75,000,000 aggregate policy limit covering damages in excess of policy limits for commercial general liability, automobile liability, employee benefits liability and employer’s liability.

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Cybersecurity and Identity Fraud Liability:   $3,000,000 aggregate policy limit for cybersecurity incidents and $5,000 per victim of identity fraud.

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Kidnap and Ransom:   $10,000,000 limit per insured event.

For more information about potential risks that could affect us, see “Risk Factors — Risks Related to Our Business Generally — Our business is subject to operating hazards that could result in substantial losses or liabilities for which we may not have adequate insurance coverage.”

Other Facilities

Our corporate headquarters are located at 1200 17th Street, Suite 2100, Denver, Colorado 80202, and our telephone number at such address is (720) 375-9680. Our corporate headquarters are leased and our field office facilities are owned, and we believe that they are adequate for our current needs.

Title to Properties

Title to our oil and gas properties is subject to royalty, overriding royalty, carried, net profits, working, and similar interests customary in the oil and gas industry. Our properties may also be subject to liens incident to operating agreements, as well as other customary encumbrances, easements, and restrictions, and for current taxes not yet due. Our general practice is to conduct title examinations on material property acquisitions. Prior to the commencement of drilling operations, a title examination and, if necessary, curative work is performed. The methods of title examination that we have adopted are reasonable in the opinion of management and are designed to ensure that production from our properties, if obtained, will be salable by us. We believe that title to our oil and natural gas properties is good and defensible, subject only to such exceptions that we believe do not materially interfere with the use of such properties.

Legal Proceedings

From time to time, we may be subject to various claims, title matters and legal proceedings arising in the ordinary course of business, including environmental contamination claims, personal injury and property damage claims, claims related to joint interest billings and other matters under natural gas operating agreements and other contractual disputes. While the outcome and impact on the Company cannot be predicted with certainty, we believe that our ultimate liability with respect to any such matters will not have a significant impact or material adverse effect on our financial positions, results of operations or cash flows. Our results of operations and cash flows, however, could be significantly impacted in the reporting periods in which such matters are resolved.

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MANAGEMENT

Directors and Executive Officers

The following table provides information as of the date of this prospectus regarding the individuals who are expected to constitute our executive officers and directors upon completion of this offering. Executive officers serve at the discretion of our board of directors and until their successors are elected and qualified. Messrs. C. Vongkusolkit and S. Vongkusolkit are father and son, respectively.

Name	Age	Current Position(s) with the Company
Christopher P. Kalnin	45	Chief Executive Officer and Director
John T. Jimenez	53	Chief Financial Officer
Eric S. Jacobsen	52	Chief Operating Officer
Brid C. Kealey	59	Chief Human Resources Officer
Lindsay B. Larrick	40	Chief Legal Officer
Ethan Ngo	41	Chief Technical Services Officer
Chanin Vongkusolkit	70	Chairman of the Board
Somruedee Chaimongkol	61	Director
Joseph R. Davis	72	Director
Akaraphong Dayananda	63	Director
Carla S. Mashinski	59	Director
Thiti Mekavichai	61	Director
Charles C. Miller III	70	Director
Sunit S. Patel	60	Director
Anon Sirisaengtaksin	69	Director
Sinon Vongkusolkit	32	Director

Christopher P. Kalnin has served as Chief Executive Officer and a director of the Company since its formation in May 2020 and founded the Company in 2015. He also worked at Kalnin Ventures, the fund manager of BKV O&G, owned by Banpu (SET: BANPU), as Managing Director from June 2014 to May 2020 and Group CEO from January 2019 to May 2020. Prior to that, Mr. Kalnin served in multiple roles at Level 3 Communications, Inc. (“Level 3 Communications”), a global provider of high-capacity communications services to businesses, serving as Vice President of Strategic Business Operations and Planning from January 2014 to June 2014 and Senior Director from February 2012 to December 2013. From January 2010 to July 2011, he served as a Strategy Advisor and Chief of Staff to the Chief Executive Officer at PTT Exploration (SET: PTTEP), a petroleum exploration and production company based in Thailand. Additionally, he served as Engagement Manager at McKinsey & Company, a management consulting firm, from October 2005 to January 2010 and Senior Analyst at Credit Suisse First Boston, the investment banking division of Credit Suisse Group, from July 2000 to July 2003. Mr. Kalnin received a BA in Finance from the University of Western Ontario and an MBA from Northwestern University’s Kellogg School of Management. We believe that Mr. Kalnin’s extensive industry experience and demonstrated leadership capabilities throughout our growth make him qualified to serve on our board of directors.

John T. Jimenez has served as Chief Financial Officer of the Company since April 2021. Prior to joining the Company, he served as Chief Financial Officer of BP Gas and Power Trading Americas and a member of the board of directors of BP Energy Company, a subsidiary of BP (NYSE: BP), from January 2019 to April 2021. Mr. Jimenez also served as interim Chief Executive Officer and a member of the board of directors of VAKT Global Ltd, a venture established by some of the world’s leading energy majors, trading houses and banks to develop a blockchain-based digital platform for post-transaction management of physical energy commodities, from January 2018 to December 2018 and Chairman of the board of directors of VAKT Holdings Ltd from January 2019 to April 2021. Prior to that, he served in various positions at various affiliates of BP, including, most recently, Vice President and Head of IST Global Finance Services from January 2016 to December 2017, Transformation Director from March 2014 to December 2015, Chief

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of Staff and Vice President of HR Strategy and Planning from May 2012 to March 2014 and Finance Director — Group HR from January 2006 to April 2012. In addition, he has held various leadership roles in international business environments, ranging from start-up operations to corporate head offices, in the US, UK, Mexico, Poland, Bulgaria and India. He has led a range of commercial activities, including large scale transformations, systems implementations, business turnarounds, business start-ups, analytics, strategy and business development. Mr. Jimenez received a BA in Accounting from Saint Mary’s University of Minnesota and an MBA from Northwestern University’s Kellogg School of Management.

Eric S. Jacobsen has served as Chief Operating Officer of the Company since its formation in May 2020. He also served as Chief Operating Officer of Kalnin Ventures from February 2020 to May 2020. Prior to that, he served as Senior Vice President of Extraction Oil & Gas, Inc. (previously NASDAQ: XOG), an independent oil and gas company focused on the acquisition, development and production of oil, natural gas and NGL reserves, from October 2016 to December 2019 and Director of Planning and Development, Director of Exploration and Production and Well Engineering Manager of Noble Energy, Inc. (previously NASDAQ: NBL), an independent energy company engaged in worldwide crude oil and natural gas exploration and production, where he led large-scale shale development efforts of the DJ Basin in Colorado, from January 2011 to October 2016. From June 1993 to January 2011, Mr. Jacobsen worked at BP (NYSE: BP) and its heritage companies, Atlantic Richfield Company and Vastar Resources, Inc., in Montana, Texas, Louisiana, Gulf of Mexico, Algeria, Azerbaijan and other locations and in various positions, including Operations Manager, Offshore Installation Manager and Reservoir Engineer. Mr. Jacobsen received a BS in Environmental Engineering and an MS in Petroleum Engineering from Montana Tech University.

Brid C. Kealey has served as Chief Human Resources Officer of the Company since February 2021. Prior to joining the Company, she co-founded and served as Senior Partner of Vector Human Capital Services, a provider of human resources strategy and operational services, from January 2012 to January 2021. In addition, Ms. Kealey served as Chief Human Resources Officer and Vice President, PEO Services of MedSynergies, a provider of business services to Physician Networks, from November 2010 to December 2012 and Chief Learning Officer of Atmos Energy Corporation (NYSE: ATO), a gas utilities company, from March 2009 to May 2010. Previously, she held global human resources leadership roles at Google Inc. (now Alphabet Inc. (NASDAQ: GOOGL, GOOG)) from June 2007 to July 2008, Nokia Corporation (NYSE: NOK) from March 2000 to June 2007 and PepsiCo, Inc. (now NASDAQ: PEP) from 1995 to 2000. Ms. Kealey received a Bachelor of Laws from Trinity College Dublin and a Masters in Business Studies from University College Dublin Michael Smurfit Graduate Business School.

Lindsay B. Larrick has served as Chief Legal Officer of the Company since July 2022 and as Vice President, General Counsel and Corporate Secretary of the Company since its formation in May 2020. She also served as Vice President and General Counsel of Kalnin Ventures from October 2018 to May 2020. Prior to that, she was a partner at national law firms Fox Rothschild LLP from July 2016 to October 2018 and Lathrop & Gage LLP from January 2007 to July 2016. During her time at such law firms, she specialized in the energy practice, served in various management positions, including Chair of the Energy Practice Group for both firms, and gained experience in structuring private equity funds and mergers, acquisitions and divestitures in the oil and gas industry. Ms. Larrick received a BS in Business Administration and a JD from the University of Denver.

Ethan Ngo has served as Chief Technical Services Officer of the Company since July 2022 and, prior to that, as Senior Vice President, Engineering of the Company since its formation in May 2020. He served at Kalnin Ventures as Senior Vice President, Engineering since December 2017 and Vice President, Engineering from March 2015 to December 2017. Prior to that, Mr. Ngo served as A&D Reservoir Engineer of Fidelity Exploration and Production Company, which is involved in the acquisition, exploration, development and production of natural gas and oil resources, from July 2014 to March 2015, Reservoir Engineer of Liberty Resources LLC, a Denver-based private equity backed oil and gas company, from April 2013 to June 2014 and Reservoir Engineer of Newfield Exploration Company (previously NYSE: NFX), an independent energy company, from April 2011 to April 2013. He also served as Senior Reservoir Engineer of ExxonMobil Production Company from February 2008 to March 2011. Mr. Ngo received a BS in Civil Engineering, an MS in International Political Economy and an ME in Petroleum Engineering from the Colorado School of Mines. Mr. Ngo also received an MBA from the University of Colorado, Denver.

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Chanin Vongkusolkit has served as Chairman of the Board of the Company since May 2020. He founded Banpu (SET: BANPU) in 1983 and has served as its Chairman of the Board since April 2016. His other positions at Banpu include director and Senior Executive Officer from 2015 to 2016 and director and Chief Executive Officer from 1983 to 2015. In addition, Mr. Vongkusolkit has served as a director of The Erawan Group Public Company Limited (SET: ERW), a hotel investor, developer and operator, since November 2004, and Chairman of its board of directors since April 2018. He has also served as a director of Mitr Phol Sugar Corp., Ltd., a sugar and bio-energy producer, since 1983 and various subsidiaries of Banpu, including Banpu Power (SET: BPP). Additionally, Mr. Vongkusolkit serves as Chairman of the Thai Listed Companies Association and an advisor at the Thammasat Economics Association. He previously served as a Commissioner at the Securities and Exchange Commission of Thailand from 2016 to 2018 and a director of Ratchaburi Electricity Generating Holding Public Company Limited, an independent power producer, from November 2003 to March 2011. Mr. Vongkusolkit received a Bachelor in Economics from Thammasat University and an MBA in Finance from St. Louis University. Mr. Vongkusolkit brings broad expertise in corporate development and leadership to the board of directors. In addition, we believe that Mr. Vongkusolkit’s extensive experience with international energy companies makes him qualified to serve on our board of directors.

Somruedee Chaimongkol has served as a director of the Company since May 2020. She has served as a director and Chief Executive Officer of Banpu (SET: BANPU) since May 2015 and a director of BNAC since February 2015. Prior to that, she worked at Banpu as Chief Financial Officer from 2006 to 2015 and Senior Vice President of Finance from 2001 to 2006. In addition, Ms. Chaimongkol has served as a director of various subsidiaries of Banpu, including Banpu Power (SET: BPP). She has also served as a commissioner of PT. Indo Tambangraya Megah Tbk (IDX: ITMG), an Indonesian coal supplier, since March 2022, and served as a director of Biofuel Development Holdings Co., Ltd., from November 2010 to December 2018. Ms. Chaimongkol received a Bachelor’s degree in Accounting from Bangkok University. Ms. Chaimongkol brings broad expertise in corporate leadership and financial matters to the board of directors. In addition, we believe that Ms. Chaimongkol’s extensive experience as an executive and director at international energy companies makes her qualified to serve on our board of directors.

Joseph R. Davis has served as a director of the Company since May 2020. He has served as a director of Reconnaissance Energy Africa Ltd. d/b/a ReconAfrica (TSXV: RECO), a Canadian oil and gas company engaged in the exploration and development of oil and gas in Mexico, Namibia and Botswana, since January 2022. In 2014, Mr. Davis began working with our Chief Executive Officer, Chris Kalnin, as a consultant, and upon the formation of BKV O&G in June 2015, he assumed the role of Vice President of Geosciences with Kalnin Ventures. He was later promoted to Senior Vice President of Kalnin Ventures, and in January 2019, he became Chief Operating Officer and served in that position until his retirement in March 2020. In addition, he served as Exploration Advisor for Digital Prospectors, LLC, an exploration consulting firm, from May 2009 to May 2015 and Vice President of Hyperion Oil Iraq, L.L.C., an international oil and gas exploration company involved in Iraq and Latin America, from August 2006 to May 2009. From 1992 to 2006, he had a consulting business specializing in evaluation of oil and gas exploration projects. Mr. Davis received an AB in Earth Science from Dartmouth College, an MS in Geology from Southern Methodist University and a PhD in Geology from the University of Texas at Austin. Mr. Davis brings broad expertise in strategic planning and operations. In addition, we believe that Mr. Davis’s upstream industry experience and executive experience make him qualified to serve on our board of directors.

Akaraphong Dayananda has served as a director of the Company since May 2020. He has served as a director and President of BNAC since February 2015. Prior to that, Mr. Dayananda served in various positions at Banpu (SET: BANPU) and Banpu Power (SET: BPP), including a director of Banpu Power from July 2009 to December 2017, Chief Strategy Officer — Head of Strategy and Business Development of Banpu from 2011 to 2019, Senior Vice President — Head of Strategy and Business Development of Banpu from 2006 to 2011, Senior Vice President — Head of Corporate Strategic Planning of Banpu from 1999 to 2006 and Senior Vice President — Finance of Banpu Power from 1997 to 1999. Prior to that, he gained expertise in the financial service sector while serving as Managing Director of Peregrine Nithi Finance and Securities Company Limited from 1995 to 1997 and in various positions at Thai Investment and Securities Plc from 1984 to 1995, including most recently Senior Vice President of Corporate Lending and Marketing. Mr. Dayananda has also served as a director of various subsidiaries of Banpu, both internationally and domestically throughout his career. Mr. Dayananda received a BS in Engineering from Chulalongkorn

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University and an MBA from Bowling Green State University. He also received certificates in various management and directorship programs, such as the Executive Program in Strategy and Organization from Stanford University and the Director Certificate Program from the Thai Institute of Directors. Mr. Dayananda brings broad expertise in strategic planning, business development and risk management to the board of directors. In addition, we believe that Mr. Dayananda’s extensive experience as an executive and director and financial and investment experience make him qualified to serve on our board of directors.

Carla S. Mashinski has served as a director of the Company since September 1, 2022. Since 2019, she has served on the board of directors of Primoris Services Corporation (NASDAQ: PRIM), a specialty construction and infrastructure company in the United States, and has served as chair of its audit committee and a member of its compensation committee since 2021. Ms. Mashinski served as Chief Financial Officer of Cameron LNG, a liquefied natural gas terminal near the Gulf of Mexico, from 2015 to 2017, then was promoted to Chief Financial Officer and Administrative Officer and served in this role until her retirement in May 2022. Prior to that, she served as Chief Financial Officer and Vice President, Finance and Information Management, North American Operations, of Sasol Ltd. (JSE: SOL), an integrated energy and chemical company based in South Africa, from 2014 to 2015, Vice President, Finance and Administration and U.S. Chief Financial Officer of SBM Offshore (AMX: SBMO), a Dutch-based global group of companies servicing the offshore oil and gas industry, from 2008 to 2014 and Vice President, Accounting and Chief Accounting Officer/Controller of GulfMark Offshore, Inc., a global provider of marine transportation services, from 2004 to 2008. Her previous board experience includes serving as a director, and a member of the audit, compensation and nominating committees, of Carbo Ceramics Inc., a technology and services company servicing the oil and gas industry, from 2019 to 2020 and a director, and chair of the compensation committee and member of the audit committee, of Unit Corporation (OTC: UNTC), a diversified energy company, from 2015 to 2020. Ms. Mashinski received a BS in Accounting with high honors from the University of Tennessee at Knoxville and an Executive MBA from the University of Texas at Dallas. She is a Certified Public Accountant in the State of Texas, Certified Management Accountant and Project Management Professional. Ms. Mashinski brings broad experience in financial and accounting matters and corporate governance to the board of directors. In addition, we believe that Ms. Mashinski’s financial and accounting experience, U.S. public company board experience and upstream industry experience make her qualified to serve on our board of directors.

Thiti Mekavichai has served as a director of the Company since May 2020. He has served as a director and Chief Executive Officer of BNAC since January 2019 and Head of Oil and Gas Business of Banpu (SET: BANPU) since November 2018. Prior to that, Mr. Mekavichai served as Executive Vice President of Human Resources and Business Services of PTT Exploration (SET: PTTEP) from October 2011 to September 2018 and Executive Vice President of Human Resources of Central Retail Corporation, Thailand’s leading multi-format and multi-category retailing platform, from June 2008 to October 2011. From December 1992 to June 2008, he held various technical and human resources positions at subsidiaries of Shell plc (NYSE: SHEL), in both the upstream and downstream industries, and served as a director of Shell Company of Thailand Limited from February 2004 to May 2008. He also served as a director of Energy Complex Company Limited, a company responsible for the construction and operational management of an office building complex, from April 2012 to August 2018 and PTT Digital Solutions Co., Ltd., an information and communication technology company, from March 2014 to August 2018. Mr. Mekavichai received a BS in Geography from Srinakharinwirot University and a diploma in Hydrographic Surveying from Plymouth Polytechnic, U.K. Mr. Mekavichai brings broad expertise in oil and gas operations, risk management, human resources and corporate development to the board of directors. In addition, we believe that Mr. Mekavichai’s extensive experience as an executive and director at international energy companies makes him qualified to serve on our board of directors.

Charles C. Miller III has served as a director of the Company since May 2020. He has served as a director of Global Healthcare Exchange, a provider of exchange and other electronic services to health care providers and their suppliers, since June 2017 and Equideum Health, a Web3 person-centered healthcare and research network provider, since December 2021. Mr. Miller was an executive in the telecommunications industry from 1987 to 2013. From 2000 to 2014, he was Vice Chairman of Level 3 Communications where his responsibilities included corporate strategy, mergers and acquisitions, business development, marketing and information services. Prior to that, Mr. Miller was an executive officer of BellSouth Corporation from 1987 to 2000, where his roles included Senior Vice President, Corporate Strategy and Development, as

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well as President of BellSouth International, Inc. Before his telecommunications career, he practiced corporate law at King & Spalding LLP from 1979 to 1984 and Ropes & Gray LLP from 1977 to 1979. Mr. Miller received an AB from Harvard College and a JD from Harvard Law School. Mr. Miller brings broad expertise in strategic planning, business development and technology to the board of directors. In addition, we believe that Mr. Miller’s U.S. public company board experience and legal expertise make him qualified to serve on our board of directors.

Sunit S. Patel has served as a director of the Company since September 1, 2022. Since February 2021, Mr. Patel has served as Chief Financial Officer of Ibotta, Inc., a consumer technology company. Prior to that, he served as Executive Vice President, Merger and Integration Lead, at T-Mobile US, Inc., a provider of mobile communications services, from October 2018 to April 2020. In addition, Mr. Patel served as Executive Vice President and Chief Financial Officer of CenturyLink, Inc., an international facilities-based communications company, from November 2017 to September 2018 and Executive Vice President and Chief Financial Officer of Level 3 Communications Inc. from 2003 until its merger with CenturyLink in November 2017. He also co-founded and served as Chief Financial Officer of Looking Glass Networks Inc., a facilities-based provider of metropolitan telecommunication transport services, from April 2000 to March 2003. Prior to that, he served in senior leadership positions in a number of telecom companies and began his professional career in investment banking. Mr. Patel received a B.S. in Chemical Engineering and Economics from Rice University and is a Chartered Financial Analyst (CFA). Mr. Patel brings broad experience in financial, accounting and technology matters and strategic planning and transactions to the board of directors. In addition, we believe that Mr. Patel’s financial and accounting expertise, executive leadership experience and public company experience make him qualified to serve on our board of directors.

Anon Sirisaengtaksin has served as a director of the Company since May 2020. He has served as a director of Banpu (SET: BANPU) since April 2016 and an Executive Advisor to Banpu for its oil and gas business since 2014. He has also served as a director of Saha-Union Public Company Limited (SET: SUC), an investment company, since January 2020 and CIMB Thai Bank Public Company Limited (SET: CIMBT), a commercial bank in Thailand, since June 2020. In addition, he served as a director and Chief Executive Officer of PTT Global Chemical Public Company Limited (SET: PTTGC) from 2012 to 2013, President and Chief Executive Officer of PTT Exploration (SET: PTTEP) from 2008 to 2012, Senior Executive Vice President, Corporate Strategy and Development of PTT Public Company Limited (“PTT PCL”) (SET: PTT) from 2002 to 2008, Executive Vice President, Natural Gas Supply and Trading, Gas Business Group, of PTT PCL from 2001 to 2002 and Deputy President, Natural Gas Marketing and Transmission of PTT Natural Gas Distribution Co., Ltd. from 1996 to 2001. Mr. Sirisaengtaksin received a BS in Geology from Chulalongkorn University and an MBA from Thammasat University. Mr. Sirisaengtaksin brings broad expertise in corporate leadership and strategic planning to the board of directors. In addition, we believe that Mr. Sirisaengtaksin’s extensive experience as an executive at international energy companies makes him qualified to serve on our board of directors.

Sinon Vongkusolkit has served as a director of the Company since July 2022. He has served as Chief Executive Officer of Banpu NEXT Co. Ltd. since July 2022. Prior to that, he served at Banpu (SET: BANPU) in the Project Management Office team, where he executed financial and asset transactions, from January 2020 to June 2022. He also served as a financial analyst in the Corporate Finance team of Banpu, where he worked on funding for the Banpu group, from November 2014 to January 2020. Mr. Vongkusolkit received a BA in Business and Marketing Management from Oxford Brookes University and an MA in Global Management Finance from Regent’s University London. Mr. Vongkusolkit brings broad expertise in strategic management and operations, including corporate finance, investments and project management, from his time at Banpu to the board of directors. In addition, we believe that Mr. Vongkusolkit’s leadership skills, technological adeptness and growth mindset from his time at Banpu NEXT Co. Ltd. make him qualified to serve on our board of directors.

Controlled Company

We intend to apply to list our common stock on the NYSE. 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

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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:

•

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

•

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

•

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           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 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.

Board of Directors

We currently have eleven directors on our board of directors.

Pursuant to 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 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. The BNAC designees are Messrs. Kalnin, Davis, C. Vongkusolkit, Dayananda, Mekavichai, Sirisaengtaksin and S. Vongkusolkit and Ms. Chaimongkol.

Our board of directors will be divided into three classes of directors, with each class to be as equal in number as possible, and with the directors serving staggered three-year terms. The term of office of the Class I directors, consisting of                 , will expire at our first annual meeting of stockholders following the completion of this offering. The term of office of the Class II directors, consisting of                 , will expire at our second annual meeting of stockholders following the completion of this offering. The term of office of the Class III directors, consisting of                 , will expire at our third annual meeting of stockholders following the completion of this offering. See “Description of Capital Stock — Anti-Takeover Provisions — Classified Board of Directors” for more information.

Director Independence

Upon completion of this offering,                 members of our board of directors will qualify as “independent” under the listing standards of the NYSE. Our board of directors has determined as of the date of this prospectus that each of                 is independent as defined under the NYSE corporate governance standards.

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Committees of the Board of Directors

Our board of directors will establish standing committees in connection with the discharge of its responsibilities. Upon the completion of this offering, these committees will include an Audit & Risks Committee, a Compensation Committee and a Nominations & Governance Committee. The composition and responsibilities of each of the committees of our board of directors are described below. Members will serve on these committees until their resignation or until as otherwise determined by our board of directors.

Audit & Risks Committee

The Audit & Risks Committee will oversee the conduct of our financial reporting processes, including (i) reviewing with management and the outside auditors the audited financial statements included in our annual reports filed with the SEC, (ii) reviewing with management and the outside auditors the interim financial results included in our quarterly reports filed with the SEC, (iii) discussing with management and the outside auditors the quality and adequacy of internal controls and (iv) reviewing the independence of the outside auditors.

Our Audit & Risks Committee will have a minimum of three members. Upon the completion of this offering, we expect the members of our Audit & Risks Committee will be           ,           and           .           will serve as the chair of the Audit & Risks Committee. All members of our Audit & Risks Committee will be “independent” as defined in the NYSE corporate governance standards and Rule 10A-3 of the Exchange Act. All members of our Audit & Risks Committee will, in the judgment of our board of directors, be financially literate, or become so within a reasonable period of time after appointment to the Audit & Risks Committee, and at least one member of the Audit & Risks Committee will qualify as an “audit committee financial expert” as defined under the Sarbanes-Oxley Act and applicable SEC regulations. The Audit & Risks Committee will operate under a written charter that satisfies the applicable rules and regulations of the SEC and the listing standards of the NYSE, and the Audit & Risks Committee will review the charter annually. A copy of the Audit & Risks Committee Charter will be available for review on the Company’s website.

Nominations & Governance Committee

The Nominations & Governance Committee will be responsible for (i) advising our board of directors about the appropriate composition of our board of directors and its committees, (ii) identifying and evaluating candidates for board service, (iii) recommending director nominees for election at annual meetings of stockholders or for appointment to fill vacancies and newly created directorships, and (iv) recommending the directors to serve on each committee of our board of directors. The Nominations & Governance Committee will also be responsible for periodically reviewing and making recommendations to our board of directors regarding corporate governance policies and responses to stockholder proposals, for conducting an annual performance review of our board of directors and its committees, and for reviewing whether our directors satisfy applicable independence requirements. Pursuant to our Stockholders’ Agreement, BNAC, through ownership interests in us held by BNAC and its affiliates, will have certain rights to designate individuals for nomination to our board of directors, subject to applicable corporate governance rules of the SEC and the NYSE (which may require BNAC to designate independent directors). See “Certain Relationships and Related Party Transactions — Stockholders’ Agreement.”

Upon the completion of this offering, we expect the members of our Nominations & Governance Committee will be           ,           and           .           will serve as the chair of the Nominations & Governance Committee. As a “controlled company,” our Nominations & Governance Committee is not required to be comprised of entirely independent directors. The Nominations & Governance Committee will operate under a written charter that satisfies the applicable rules and regulations of the SEC and the listing standards of the NYSE, and the Nominations & Governance Committee will review the charter annually. A copy of the Nominations & Governance Committee Charter will be available for review on the Company’s website.

Compensation Committee

The Compensation Committee will review, evaluate and recommend to our board of directors compensation policies with respect to our directors, executive officers and senior management. The

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Compensation Committee will also administer the 2022 Plan. The Compensation Committee will have the authority to approve the compensation of the directors, executive officers and senior management of the Company. The Compensation Committee will also have the authority to grant equity awards under the 2022 Plan.

Upon the completion of this offering, we expect the members of our Compensation Committee will be                 ,                 and                 .                 will serve as the chair of the Compensation Committee. As a “controlled company,” our Compensation Committee is not required to be comprised of entirely independent directors. The Compensation Committee will operate under a written charter that satisfies the applicable rules and regulations of the SEC and the listing standards of the NYSE, and the Compensation Committee will review the charter annually. A copy of the Compensation Committee Charter will be available for review on the Company’s website.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serve on the board of directors or compensation committee of another public company that has an executive officer that serves on our board or compensation committee. No member of our board is an executive officer of another public company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Code of Business Conduct and Ethics

Upon the completion of this offering, our board of directors will adopt a new Code of Business Conduct and Ethics applicable to all the Company’s employees, officers and directors. The Code of Business Conduct and Ethics will cover compliance with law; fair and honest dealings with the Company, its competitors and others; full, fair and accurate disclosure to the public; and procedures for compliance with the Code of Business Conduct and Ethics. This Code of Business Conduct and Ethics will be available on the Company’s website.

Corporate Governance Guidelines

Upon the completion of this offering, our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of the NYSE.

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EXECUTIVE COMPENSATION

This section describes the material elements of compensation awarded to, earned by or paid to the following named executive officers (our “NEOs”) for calendar year 2021:

•

Christopher Kalnin, Chief Executive Officer and interim Chief Financial Officer

•

John Jimenez, Chief Financial Officer

•

Eric Jacobsen, Chief Operating Officer

2021 Summary Compensation Table

Name and Position (as of December 31, 2021)	Year	Salary ($)	Bonus ($)(1)	Stock awards ($)(2)	Nonequity incentive plan compensation ($)(3)	All other compensation ($)(4)	Total ($)
Christopher Kalnin Chief Executive Officer(5)	2021	501,923	—	16,896,074	795,000	11,928	18,204,925
John Jimenez Chief Financial Officer(6)	2021	250,385	250,000	8,009,952	120,204	31,339	8,661,880
Eric Jacobsen Chief Operating Officer	2021	401,539	—	9,591,205	224,190	22,340	10,239,274

(1)

Amount represents the one-time sign-on bonus paid to Mr. Jimenez in connection with the commencement of his employment.

(2)

Amounts reported represent the aggregate grant date fair value of TRSUs and PRSUs under the 2021 Plan, computed in accordance with FASB ASC 718. Each of Messrs. Kalnin’s, Jimenez’s and Jacobsen’s PRSUs were granted in 2021. Under the 2021 Plan, TRSUs are expected to be granted in four annual grants over a four-year period. The first annual grant of each of Messrs. Kalnin’s, Jimenez’s and Jacobsen’s TRSUs were granted in 2021. In accordance with FASB ASC 718, for accounting purposes, the Company recognized a compensation expense for each of the four annual grants expected to be granted during the four-year period, although only the first annual grant was granted in 2021. Therefore, the grant date fair value of the TRSUs reflects not only the TRSUs granted in 2021, but also the TRSUs that were expected to be granted in 2022, 2023 and 2024, subject to the continuation of the 2021 Plan and continued employment through each such anticipated grant date, in addition to other factors. For more details relating to the assumptions used in calculating the grant date fair value of the TRSUs and PRSUs reported in this column, including modifications made thereto in November 2021, see “Note 11 — Equity-based Compensation” to our historical consolidated financial statements included elsewhere in this prospectus. The grant date fair value for the PRSUs reflected in this table are reported based upon the probable outcome of the performance conditions as of the grant date, and were $12,570,730, $5,959,428 and $7,135,885 for Messrs. Kalnin, Jimenez and Jacobsen, respectively, which amounts are the sum of the original grant date fair value of the PRSUs, assuming a stock price of $10.00 per share and assumptions made with respect to the achievement of the performance goals at that time, plus the incremental cost associated with a modification made to the awards in November 2021, assuming a stock price of $11.06 per share and changes to the assumptions made with respect to the achievement of the performance goals as of the date of modification. The value of the PRSUs granted in 2021, assuming achievement of the maximum performance would have been as follows: Mr Kalnin: $20,184,942; Mr. Jimenez: $12,029,741; Mr. Jacobsen: $14,404,544, which amounts are the sum of the original grant date fair value of the PRSUs, assuming a stock price of $10.00 per share, plus the incremental cost associated with a modification made to the awards in November 2021, assuming a stock price of $11.06 per share.

(3)

Amounts reported represent each NEO’s annual performance-based bonus earned in 2021 but paid after the end of the fiscal year, upon certification of the applicable performance measures by our Compensation Committee. See “— 2021 Performance-Based Bonuses” for more information.

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(4)

Amounts reported include the amounts paid to the NEOs shown in the following table:

​	Company 401(k) Contribution ($)(a)		Life Insurance Premiums ($)(b)		Relocation ($)(c)
Christopher Kalnin	​	11,808	​	120	​	—
John Jimenez	​	16,956	​	120	​	14,263
Eric Jacobsen	​	22,220	​	120	​	—

(a)

The Company maintains a 401(k) plan that provides employees with an opportunity to save for retirement. The Company makes matching contributions of up to 6% of base salary, which contributions are immediately vested.

(b)

Included in this column are the life insurance premiums paid on behalf of each NEO.

(c)

Included in this column are the relocation expenses for which Mr. Jimenez was reimbursed in connection with his relocation to the Denver, Colorado area.

(5)

Mr. Kalnin served as the Company’s interim Chief Financial Officer from July 2020 until Mr. Jimenez assumed the role in April 2021. Mr. Kalnin was not separately compensated for his position as interim Chief Financial Officer.

(6)

Mr. Jimenez assumed the role of Chief Financial Officer on April 16, 2021, and thus his base salary and non-equity incentive plan compensation information reflects only the period from April 16, 2021 through December 31, 2021.

Employment Agreements

CEO Employment Agreement

Mr. Kalnin and the Company entered into an employment agreement effective as of August 4, 2020 (the “CEO Employment Agreement”), which provides Mr. Kalnin with, among other things, (1) an annual base salary of $500,000, subject to annual review by our board of directors, (2) the eligibility to receive an annual cash bonus, with target payment equal to 100% of his base salary, but paid at an amount commensurate with the level at which the applicable performance goals are achieved (which may be higher or lower than the target level) and subject to continued employment through the end of the year, and (3) the opportunity to participate in the Company’s equity incentive plan, with an annual restricted stock unit (“RSU”) award to be made in each of 2020, 2021, 2022 and 2023 (each an “Annual RSU Grant”) that is equal to, at least 325,900 RSUs per year; subject to the terms of the applicable plan. Mr. Kalnin’s Annual RSU Grant has been satisfied in accordance with the 2021 Plan, by reference to Mr. Kalnin’s four-year Annual RSU Grant opportunity, granted approximately 70% on January 1, 2021 in the form of PRSUs and the remaining 30% in TRSUs, the first and second annual grants of which were granted in each of January 1, 2021 and January 1, 2022. Each of the TRSU annual grants are subject to vesting requirements once granted, as described in more detail below in “— Equity Awards Granted Under Our 2021 Long Term Incentive Plan.” Mr. Kalnin is also eligible to participate in and receive benefits offered to our employees, including paid and holiday time off, health insurance coverage and participation in our 401(k) plan. Mr. Kalnin is subject to customary confidentiality and invention assignment covenants, as well as non-competition and non-solicitation covenants which extend for 18 months after termination of employment. Additionally, Mr. Kalnin may receive compensation and benefits in connection with a termination of his employment or a change in control, which are discussed below in “— Potential Payments Upon Termination or Change in Control — Separation Benefits in the CEO Employment Agreement.”

CFO Employment Agreement

Mr. Jimenez and the Company entered into an employment agreement effective as of January 11, 2021 (the “CFO Employment Agreement”), pursuant to which Mr. Jimenez assumed the role of the Company’s Chief Financial Officer as of April 16, 2021 and which provides Mr. Jimenez with, among other things, (1) an annual base salary of $350,000, (2) the opportunity to receive a discretionary annual cash bonus based on the Company’s performance (and taking into account Mr. Jimenez’s individual effort and satisfactory

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achievement of established performance goals) in an amount between 0% and 60% of his base salary, and (3) the opportunity to participate in the 2021 Plan, which was originally estimated to equate to equity awards with respect to approximately 618,000 shares over a four-year period and, which would be subject to the terms of the 2021 Plan and ultimately dependent based on Company performance and Mr. Jimenez’s individual effort and satisfactory achievement of performance goals. The CFO Employment Agreement provided Mr. Jimenez with a one-time singing bonus of $250,000 in connection with the commencement of his employment with the Company and the payment of Mr. Jimenez’s relocation expenses, up to a maximum of $30,000, incurred in connection with his relocation to the Denver, Colorado area. Mr. Jimenez is also eligible to participate in and receive benefits offered to other employees, including paid and holiday time off, health insurance coverage and participation, with a company match, in our 401(k) plan. Mr. Jimenez is subject to customary confidentiality and invention assignment covenants, as well as non-disparagement, non-competition and non-solicitation covenants which extend for 12 months after termination of employment. Additionally, Mr. Jimenez may receive compensation in connection with a termination of his employment, which is discussed below in “— Potential Payments Upon Termination or Change in Control — Separation Benefits in the CFO Employment Agreement.”

COO Employment Agreement

Mr. Jacobsen and Kalnin Ventures entered into an employment agreement effective as of February 18, 2020 (the “COO Employment Agreement”), which provides Mr. Jacobsen with, among other things, (1) an annual base salary of $400,000 and (2) the opportunity to receive a discretionary annual cash bonus based on the Company’s performance (and taking into account Mr. Jacobsen’s individual effort and satisfactory achievement of established performance goals) in an amount between 0% and 40% of his base salary. Mr. Jacobsen is also eligible to participate in and receive benefits offered to other employees, including paid and holiday time off, health insurance coverage and participation, with a company match, in our 401(k) plan. Mr. Jacobsen is subject to customary confidentiality and invention assignment covenants, as well as non-disparagement, non-competition and non-solicitation covenants. Additionally, Mr. Jacobsen may receive compensation in connection with a termination of his employment, which is discussed below in “— Potential Payments Upon Termination or Change in Control — Separation Benefits in the COO Employment Agreement.”

Equity Awards Granted Under Our 2021 Long Term Incentive Plan

During the year ending December 31, 2021, RSU awards were granted to our NEOs under the 2021 Plan, some of which are subject to service-based vesting conditions and some of which are subject to both performance-based and service-based vesting conditions. On January 1, 2021, Mr. Kalnin and Mr. Jacobsen were granted 97,770 and 55,500 TRSUs, respectively, and 912,520 and 518,000 PRSUs at the target payout level (which equate to 1,825,040 and 1,036,000 PRSUs at maximum payout level), respectively. On April 16, 2021, Mr. Jimenez was granted 46,350 TRSUs and 432,600 PRSUs at the target payout level (which equates to 865,200 PRSUs at maximum payout level). Approximately 25% of Messrs. Kalnin’s and Jacobsen’s TRSUs were vested at the time of grant and the remainder were set to vest in three roughly equal tranches on each of January 1, 2022, January 1, 2023 and January 1, 2024, in each case, subject to continued employment through such applicable vesting date. Approximately 25% of Mr. Jimenez’s TRSUs were vested at the time of grant and the remainder were set to vest in three roughly equal tranches on each of April 16, 2022, April 16, 2023 and April 16, 2024, in each case, subject to continued employment through such applicable vesting date. Messrs. Kalnin’s, Jacobsen’s and Jimenez’s PRSUs will vest based upon the level at which the performance measures described below in “— BKV Corporation 2021 Long Term Incentive Plan” are achieved over the period beginning January 1, 2021 and ending on the earliest of December 31, 2023, an IPO or Change in Control of the Company (each as defined in the 2021 Plan), so long as each of Messrs. Kalnin, Jacobsen and Jimenez remain employed by the Company through the end of such performance period.

2021 Performance-Based Bonuses

For 2021, our Compensation Committee recommended and our board of directors approved the adoption of an annual, performance-based bonus program for all of our employees, including each of our NEOs (the “2021 Annual Bonus”). Messrs. Kalnin, Jimenez and Jacobsen were assigned a target bonus opportunity equal to, for Mr. Kalnin, 100% of his base salary and for Messrs. Jimenez and Jacobsen, 30%

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of each of their respective base salaries. Each employee’s 2021 Annual Bonus was calculated by multiplying the individual’s base salary by his target bonus opportunity and multiplied by an additional two components: the corporate multiplier, based on corporate performance goals, which were based off of the KPI Scorecard (discussed below), and an individual multiplier, based on individual performance goals determined by, for Mr. Kalnin, the board of directors and for Messrs. Jimenez and Jacobsen, Mr. Kalnin, subject to approval by our board of directors. Once both the corporate performance goals and the individual performance goals were scored and the corporate multiplier and individual multipliers were determined, the 2021 Annual Bonus earned by each of Messrs. Kalnin, Jimenez and Jacobsen were equal to the product of their respective target bonus opportunities and the corporate multiplier and individual multiplier assigned to the corporate performance goals and individual performance goals, respectively. Mr. Jimenez’s 2021 Annual Bonus was prorated to reflect the number of full months worked during 2021.

Company Performance Measures

The company performance metrics were based on the “KPI Scorecard,” which evaluated “lagging” indicators and “leading” indicators that were weighted at an aggregate of 70% and 30%, respectively. The “lagging “indicators measured the Company’s key financial and operation metrics, including the Company’s EBITDA, net income, free cash flow, net production, year-end reserves, break-even unit costs, costs of upstream subsurface development and environmental health safety and regulatory measures. Each of these metrics comprised between 5% and 20% of the overall “lagging” indicator category.” The “leading” indicators measured the Company’s achievement of strategic and business plan goals, including employee engagement, baseline ESG scores as measured by a third-party consultant, the successful completion of the integration of the Devon Barnett Acquisition, the number of acquisition opportunities identified by the Company, the Company’s automation and use of big data tools, the process redesign implementation of EHSR and operations, the achievement of midstream projects, enhancements in the Company’s value chain and the level at which future projects inventory is clearly planned and to go, each weighted equally at 10%.

The Compensation Committee determined that the “lagging” indicators, or the financial and operational metrics were met, in the aggregate, at 160% of target, resulting in a company multiplier of 1.12 (or the product of the 160% level of achievement and the 70% weighting of such metrics). The Compensation Committee determined that the “leading” indicators, or the Company’s strategic goals, were met, in the aggregate, at 184% of target, resulting in a company multiplier of .55 (or the product of the 184% level of achievement and the 30% weighting of such metrics). These determinations would have resulted in a total company multiplier equal to 1.67. However, the Compensation Committee included in its analysis of the Company’s performance during 2021 that, while not costs that affected the level at which the performance metrics of the KPI Scorecard were met, there were nonetheless certain other costs that affected the Company. As a result of these costs and in the Compensation Committee’s discretion to determine the level at which the performance metrics of the KPI Scorecard were achieved, the Compensation Committee determined that the overall company multiplier should be lowered by approximately 5%, resulting in a company multiplier equal to 1.59.

Individual Performance Measures

The Compensation Committee set Mr. Kalnin’s individual performance measures to be the same as the KPI Scorecard used for the company performance measures. The Compensation Committee determined that Mr. Kalnin’s individual contributions to the KPI Scorecard, along with his guiding the Company to be ready for an IPO and the Company’s employee satisfaction (measured through a survey of the employees) resulted in an individual multiplier of 1.000, which the board of directors approved. Mr. Kalnin set Messrs. Jimenez’s and Jacobsen’s individual performance goals to be based off the elements of the KPI Scorecard that directly related to each of their duties. For Mr. Jimenez, his individual performance goals included his leadership, people and culture skills, his finance and accounting foundational processes and his IPO readiness. Mr. Kalnin recommended to the board of directors that, based on the strong relationships Mr. Jimenez built with investors, his ability to address audit issues and his engagement of Deloitte to define strategy and baseline readiness, and to prepare a plan for the Company’s IPO, Mr. Jimenez’s individual multiplier should be 1.080, which the board of directors approved. Mr. Jacobsen’s individual performance goals included his leadership, people and culture skills, his ESG foundations and his IPO readiness. Mr. Kalnin recommended to the board of directors that, based on the strong leadership skills Mr. Jacobsen showed in

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both internal and external collaboration, his defined ESG strategy and implementation and his operations preparedness for an IPO in 2022, Mr. Jacobsen’s individual multiplier should be 1.175, which the board of directors approved.

Outstanding Equity Awards at Fiscal Year-End

​	Stock Awards
Name	Number of shares or units of stock that have not vested (#)		Market value of shares or units of stock that have not vested ($)		Equity incentive plan awards: Number of unearned shares, units or other rights that have not vested (#)		Equity incentive plan awards: Market or payout value of unearned shares, units or other rights that have not vested ($)
Christopher Kalnin	​	—	​	—	​	912,520(1)	​	10,722,110
Christopher Kalnin	​	73,328(2)	​	861,604	​	—	​	—
John Jimenez	​	—	​	—	​	432,600(1)	​	5,083,050
John Jimenez	​	34,763(3)	​	408,465	​	—	​	—
Eric Jacobsen	​	—	​	—	​	518,000(1)	​	6,086,500
Eric Jacobsen	​	41,625(2)	​	489,094	​	—	​	—

(1)

Represents the target number of PRSUs outstanding as of December 31, 2021 (assuming the performance goals are determined to be met at target). The number of PRSUs outstanding (and the value thereof), as of December 31, 2021 assuming the performance goals are determined to be met at maximum was 1,825,040 (or $21,444,220); 865,200 (or $10,166,100); and 1,036,000 (or $12,173,000) for Messrs. Kalnin, Jimenez and Jacobsen, respectively.

(2)

Represents the portion of the TRSUs granted on January 1, 2021 to Messrs. Kalnin and Jacobsen that remained outstanding and unvested as of December 31, 2021, which vest approximately one-third on each of January 1, 2022, January 1, 2023 and January 1, 2024.

(3)

Represents the portion of the TRSUs granted on April 16, 2021 to Mr. Jimenez that remain outstanding and unvested as of December 31, 2021, which vest approximately one-third on each of April 16, 2022, April 16, 2023 and April 16, 2024.

Potential Payments Upon Termination or Change in Control

Separation Benefits in the CEO Employment Agreement

The CEO Employment Agreement provides that, if Mr. Kalnin’s employment with the Company is terminated by the Company without “cause” or by Mr. Kalnin with “good reason,” ​(1) any outstanding RSUs granted pursuant to his Annual RSU Grant will become vested and (2) Mr. Kalnin will receive a lump sum payment equal to 200% of the sum of (a) his base salary plus (b) his target annual cash bonus, each in effect at the time of Mr. Kalnin’s termination. If Mr. Kalnin elects coverage under the Company’s medical plan pursuant to COBRA, Mr. Kalnin will be reimbursed for the full amount of his and his eligible dependents’ COBRA premiums for the 18-month period following his termination, unless he earlier becomes eligible for coverage under another employer’s medical plan (together with the Annual RSU Grant acceleration and lump sum payment, the “CEO Separation Benefits”). “Cause,” as defined in the CEO Employment Agreement, means Mr. Kalnin’s (i) indictment for a felony or his commission of fraud against the Company; (ii) misconduct that brings the Company into substantial public disgrace or disrepute; (iii) gross negligence or gross misconduct with respect to the Company; (iv) insubordination to, or material failure to follow lawful directions of, the board of directors, in either case if not cured within 10 days of Mr. Kalnin’s receipt of written notice of such event; (v) material violation of the restrictive covenants in the CEO Employment Agreement; (vi) material breach of any a Company work rule or internal policy that is not cured within 10 days of Mr. Kalnin’s receipt of written notice of such event (if such event can be cured); (vii) a violation of the Foreign Corrupt Practices Act of 1977 or any state or federal anti-money laundering laws; or (viii) material breach of the CEO Employment Agreement that is not cured within 30 days of

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Mr. Kalnin’s receipt of written notice of such breach. “Good Reason,” as defined in the CEO Employment Agreement, means (i) a material reduction in Mr. Kalnin’s base salary or target annual bonus (other than as part of an across-the board reduction of no more than 10% applicable to all of the Company’s executives); (ii) a material diminution in Mr. Kalnin’s position, duties, authority, reporting or responsibilities; (iii) the Company’s material breach of the CEO Employment Agreement; or (iv) the involuntary permanent relocation of Mr. Kalnin’s principal place of business to a location more than 35 miles beyond the Company’s current place of business.

Mr. Kalnin’s receipt of the CEO Separation Benefits is subject to his execution and non-revocation of a release of claims in favor of the Company and his continued compliance with the restrictive covenants contained in the CEO Employment Agreement. Such restrictive covenants include non-competition, non-solicitation (of both employees or customers) and intellectual development prohibitions for 18 months following termination, along with a perpetual confidentiality prohibitions.

Separation Benefits in the CFO Employment Agreement

The CFO Employment Agreement provides that, if Mr. Jimenez’s employment with the Company is terminated by the Company without “cause” ​(as defined in the CFO Employment Agreement), Mr. Jimenez will receive 18 months of base salary, subject to his execution of a separation agreement and general release and his compliance with a 12 month non-competition and non-solicitation restriction.

Separation Benefits in the COO Employment Agreement

The COO Employment Agreement provides that, if Mr. Jacobsen’s employment with the Company is terminated by the Company without “cause” ​(as determined by the Company in good faith), Mr. Jacobsen will receive a lump sum payment equal to three months of his base salary.

BKV Corporation 2021 Long Term Incentive Plan

The 2021 Plan was initially adopted by our board of directors on January 1, 2021 and was amended in November 2021. The 2021 Plan will be terminated by the board of directors in connection with this offering.

Purpose.   The purpose of the 2021 Plan was to permit the grant of awards to our directors and employees of our Company or any of our subsidiaries, and to attract and retain such individuals who contribute to the achievement of the Company’s economic objectives.

Administration.   Our 2021 Plan was administered by our Compensation Committee (for purposes of this section, the “Committee”) and subject to the board of director’s approval. Subject to the terms of the 2021 Plan, the administrator had the authority to, among other things, select the persons to whom awards are granted, determine the nature, extent and timing of the awards to be granted, determine the duration of and restrictions and other conditions applicable to such awards. Any interpretation or determination by the Committee under the 2021 Plan will be final and conclusive. The Committee may delegate its administrative duties or powers to one or more of our officers.

Shares Available.   There were 14,941,176 shares of our common stock authorized for grant under the 2021 Plan. The shares available for issuance may be shares authorized but unissued or treasury shares. The Chief Executive Officer had the authority to grant up to 60% of the available shares on or before December 31, 2022 (assuming target payout of the PRSUs). Assuming maximum payout of the PRSUs and based on the TRSUs that were legally outstanding as of September 30, 2022, 12,633,605 shares were underlying outstanding equity awards and 916,119 shares remained available for issuance under the 2021 Plan.

Share Counting.   The aggregate number of shares of our common stock that were available for award under the 2021 Plan were reduced by one share of our common stock for every one share of our common stock subject to an award granted under the 2021 Plan. Shares of our common stock that were subtracted from the amount of available shares with respect to an award that ultimately lapsed, expired, was forfeited or for any reason was terminated or unvested were not automatically available again for issuance under the 2021 Plan.

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Eligibility.   Awards under the 2021 Plan could be granted to employees and directors of the Company or any of our subsidiaries. Eligible recipients who were either (1) the Chief Executive Officer or classified by the Company at the Senior Management level (those reasonably likely to be in the four most highly compensated during the next financial year or otherwise recommended by the Chief Executive Officer and approved by the board of directors as such) or (2) classified by the Company below the Senior Management level but who were recommended for an award by our Chief Executive Officer generally received PRSUs and TRSUs under the 2021 Plan.

Types of Awards Under the 2021 Plan.   Pursuant to the 2021 Plan, we could grant TRSUs and PRSUs. Generally, with respect to the aggregate awards anticipated to be granted to participants over a four-year period, 70% of such aggregate award granted under the 2021 Plan were PRSUs and 30% were TRSUs.

Time-Vested Restricted Stock Units.   The TRSUs were contemplated as being granted annually beginning on the effective date of the 2021 Plan and in each of the three (3) financial years thereafter or commencing upon an individual first becoming a participant under the 2021 Plan. The TRSUs were subject to the recipient’s continued employment and are 25% vested on grant, with the remaining TRSUs vesting 25% on each of the first, second and third anniversaries of grant.

Performance-Vested Restricted Stock Units.   The PRSUs were granted as a one-time grant on the effective date of the 2021 Plan or upon an individual first becoming a participant under the 2021 Plan. The PRSUs vest subject to the recipient’s continued performance through the vesting date and based upon the level at which the performance metrics are attained, which metrics may be attained at a level between 0% and 100% of the maximum performance level. The performance period for the PRSUs began on the effective date of the 2021 Plan and will end on the earliest of December 31, 2023, the date of an IPO or the date of a Change in Control (as defined in the 2021 Plan), which means that the performance period will end in connection with the completion of this offering. The performance measures include total shareholder return, return on capital employed and the Company’s IPO readiness.

Effect of Termination or Forfeiture.   Unless otherwise provided in an award agreement, or unless the Committee determines otherwise, upon a participant’s termination for any reason, awards held by the participant that have not vested as of the date of his or her termination were forfeited. If the Committee determines that the participant has committed an act that would constitute cause or an adverse action (each as defined in the 2021 Plan), either before or after such participant’s termination of employment and regardless of whether such participant was terminated for cause, the Committee in its sole discretion may require that the participant surrender and return to the Company all or any shares of common stock received prior to his or her termination in settlement of any vested award under the 2021 Plan or to disgorge all or any profits or any other economic value made or realized by the participant, during the period beginning one year before the participant’s termination in connection with any shares of stock issued upon vesting of any TRSUs and PRSUs granted under the 2021 Plan.

Repurchase, Put and Drag-Along Rights.   If a participant (1) committed a material breach of his or her employment agreement or service contract with the Company that was not capable of being remedied or, if capable of being remedied, that was not remedied by the participant within 30 days, or (2) was terminated for any reason, then the Company had the right, which remained open for 90 days following termination, to repurchase all (but not less than all) of the vested shares of common stock acquired by the participant under the 2021 Plan. The purchase price of the vested shares so repurchased was equal to the fair market value of the shares at the time of repurchase. If a participant’s employment was terminated for any reason other than the participant’s resignation or, if a participant’s employment terminated due to his or her voluntary resignation and more than 36 months had passed since the participant’s first grant of an incentive award under the 2021 Plan, and, in each case, the Company had not repurchased the participant’s shares of common stock acquired under the 2021 Plan, the participant had the right to elect to sell such shares back to the Company at an amount equal to the fair market value of the shares at the time the election to sell was made. In November 2021, both the Company’s repurchase right and this put right were amended so that they could not be exercised for at least 181 days following the date the participant’s award vests and a “Sell Fund Purchase Program” was implemented whereby, if specifically provided for in an award agreement, participants have the ability to tender shares for repurchase by the Company. Additionally, if Banpu proposed

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to effect the sale of shares of common stock representing more than 80% of the total issued and outstanding shares of Banpu, it may have required the participation in such sale of all of the vested shares of common stock owned by participants.

Corporate Transactions; Change in Control.   In the event of (1) any reorganization, merger, consolidation, recapitalization, liquidation, reclassification, stock dividend, stock split, combination of shares, rights offering, extraordinary dividend or divestiture or other similar change in corporate structure or shares, (2) any purchase, acquisition, sale, disposition or write-down of a significant amount of assets or a significant business, (3) any change in accounting principles or practices, tax laws or other such laws or provisions affecting reported results, (4) any uninsured catastrophic losses or extraordinary non-recurring items as described in Accounting Standards Codification 225-20, (5) an IPO or (6) any other similar change, in each case with respect to the Company or any other entity whose performance is relevant to the vesting of the PRSUs, the Committee may amend or modify the vesting criteria of any outstanding PRSUs to equitably reflect such event, with the desired result that the criteria for evaluating such financial performance of the Company or such other entity will be substantially the same following such event as prior to such event.

In the event of a Change in Control (as defined in the 2021 Plan), the board of directors or any corporation or entity assuming the obligations of the Company could have provided that awards outstanding under the 2021 Plan be vested in full or in part on the date of such Change in Control or could have provided that such awards be assumed or that an equivalent award be substituted by the acquiring or succeeding corporation. The performance period of the PRSUs would end as of the date of such Change in Control.

Transferability.   Generally, awards under the 2021 Plan may not be transferred by a participant except by will or the laws of descent and distribution. However, the 2021 Plan allowed participants to designate a beneficiary that would receive payment or settlement of an award under the 2021 Plan in the event of the participant’s death.

Market Standoff.   Unless the Committee otherwise provides the participant with prior written consent, the 2021 Plan places market stand-off restrictions on shares of common stock acquired in connection with the grant, vesting or settlement of the PRSUs and TRSUs. The participant may not, without the consent of the Company or the representatives of any underwriters (for the duration determined by the Company and the representatives of the underwriters, but not to exceed 180 days from the date of the final prospectus), (1) sell, pledge, offer to sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase or otherwise transfer or dispose of, any shares of common stock or any securities convertible into or exercisable or exchangeable for common stock, or (2) enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the common stock.

Amendment and Termination.   The Committee has the authority to amend or modify for any reason the terms of any outstanding awards under the 2021 Plan, including the authority to modify the number of shares or other terms and conditions of an award, accept the surrender of an outstanding award or, to the extent to previously exercised or vested, authorize the grant of new awards in substitution for surrendered awards. However, the terms of any such amendments must be permitted by the 2021 Plan and such amendment may not (1) cause the award to become taxable under Section 409A of the Code or (2) adversely affect any participant without such participant’s consent.

Our board of directors generally may amend, suspend or terminate the 2021 Plan in whole or in part. However, no termination, suspension or amendment of the 2021 Plan may adversely affect any outstanding award without the consent of the affected participant. The 2021 Plan shall terminate pursuant to its terms on the earlier of (1) six months following an IPO (including this offering) and (2) January 1, 2024; however, the board of directors acted to terminate the 2021 Plan in connection with the adoption of the 2022 Plan. Termination of the 2021 Plan pursuant to its terms will not affect the rights of the Company and participants and the Company’s and participants’ rights will remain in full force and effect as to all outstanding unvested or vested awards, and shares of common stock issued in settlement of awards.

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BKV Corporation 2022 Equity And Incentive Compensation Plan

In connection with this offering, our board of directors adopted, and we anticipate our stockholders will approve, the 2022 Plan. The material terms of the 2022 Plan are as follows:

Purpose.   The purpose of the 2022 Plan is to permit the grant of awards to our directors, officers and other employees and certain consultants, and to provide to such persons incentives and rewards for service and/or performance.

Administration; Effectiveness.   The 2022 Plan will generally be administered by the Compensation Committee or any other committee of the board of directors designated by the board of directors to administer the 2022 Plan (for purposes of this section, the “Committee”). The Committee has the authority to determine eligible participants in the 2022 Plan, and to interpret and make determinations under the 2022 Plan. Any interpretation or determination by the Committee under the 2022 Plan will be final and conclusive. The Committee may delegate its administrative duties or powers to one or more of our officers. However, the board of directors shall have the same powers and authorities as the Committee with respect to grants of awards to non-employee directors and may, in its discretion, act in lieu of the Committee with respect to such awards.

Shares Available for Awards under the 2022 Plan.   Subject to adjustment as described in the 2022 Plan, the number of shares of our common stock available for awards under the 2022 Plan is, in the aggregate, 10,000,000 shares of our common stock (which we refer to as the “Available Shares”), with such shares subject to adjustment to reflect any extraordinary cash dividend, stock dividend, split or combination of our common stock. The Available Shares may be shares of original issuance, treasury shares or a combination of the foregoing.

The 2022 Plan also contains limits on the maximum value at grant for awards to non-employee directors in any calendar year of $750,000.

Share Counting.   The aggregate number of shares of our common stock available for award under the 2022 Plan will be reduced by one share of our common stock for every one share of our common stock subject to an award granted under the 2022 Plan.

Shares of our common stock subject to an award that is cancelled or forfeited, expires, is settled for cash or is unearned (in whole or in part) will be added back to the aggregate number of shares of our common stock available under the 2022 Plan, however, the following shares of our common stock will not be added back: (i) shares of our common stock withheld by us in payment of the exercise price of a stock option; (ii) shares of our common stock tendered or otherwise used in payment of the exercise price of a stock option; (iii) shares of our common stock withheld by us or tendered or otherwise used to satisfy a tax withholding obligation; (iv) shares of our common stock subject to share-settled appreciation rights that are not actually issued in connection with the settlement of such appreciation right; and (v) shares of our common stock reacquired by the Company on the open market or otherwise using cash proceeds from the exercise of stock options. In addition, if under the 2022 Plan a participant has elected to give up the right to receive cash compensation in exchange for shares of our common stock based on fair market value, such shares of our common stock will not count against the aggregate number of shares of our common stock available under the 2022 Plan.

Shares of our common stock issued or transferred pursuant to awards granted under the 2022 Plan in substitution for or in conversion of, or in connection with the assumption of, awards held by awardees of an entity engaging in a corporate acquisition or merger with us or any of our subsidiaries (which we refer to as “Substitute Awards”) will not count against, nor otherwise be taken into account in respect of, the share limits under the 2022 Plan unless otherwise provided in the 2022 Plan. Additionally, shares of common stock available under certain plans that we or our subsidiaries may assume in connection with corporation transactions from another entity may be available for certain awards under the 2022 Plan, but will not count against, nor otherwise be taken into account in respect of, the share limits under the 2022 Plan.

Types of Awards Under the 2022 Plan.   Pursuant to the 2022 Plan, we may grant stock options, appreciation rights, restricted stock, RSUs, performance shares, performance units, cash incentive awards, and certain other awards based on or related to shares of our common stock.

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Each grant of an award under the 2022 Plan will be evidenced by an award agreement or agreements, which will contain such terms and provisions as the Committee may determine, consistent with the 2022 Plan. Those terms and provisions include the number of our shares of our common stock subject to each award, earning or vesting terms and any other terms consistent with the 2022 Plan. A brief description of the types of awards which may be granted under the 2022 Plan is set forth below.

Stock Options.   Stock options granted under the 2022 Plan are non-qualified stock options and must have an exercise price per share that is not less than the fair market value of a share of our common stock on the date of grant. The term of a stock option may not extend more than 10 years after the date of grant. Each grant will specify the form of consideration to be paid in satisfaction of the exercise price.

Appreciation Rights.   The 2022 Plan provides for the grant of appreciation rights. An appreciation right is a right to receive from us an amount equal to 100%, or such lesser percentage as the Committee may determine, of the spread between the base price and the value of shares of our common stock on the date of exercise. An appreciation right may be paid in cash, shares of our common stock or any combination thereof. Except with respect to Substitute Awards, the base price of an appreciation right may not be less than the fair market value of a share of common stock on the date of grant. The term of an appreciation right may not extend more than 10 years from the date of grant.

Restricted Stock.   Restricted stock constitutes an immediate transfer of the ownership of shares of our common stock to the participant in consideration of the performance of services, entitling such participant to dividend, voting and other ownership rights, subject to the substantial risk of forfeiture and restrictions on transfer determined by the Committee for a period of time determined by the Committee or until certain management objectives specified by the Committee are achieved. Each such grant or sale of restricted stock may be made without additional consideration or in consideration of a payment by the participant that is less than the fair market value per share of our common stock on the date of grant. Any grant of restricted stock may specify the treatment of dividends or distributions paid on restricted stock that remains subject to a substantial risk of forfeiture. Any such dividends or other distributions on restricted stock shall be deferred until, and paid contingent upon, the vesting of such restricted stock.

Restricted Stock Units.   RSUs awarded under the 2022 Plan constitute an agreement by us to deliver shares of our common stock, cash, or a combination thereof, to the participant in the future in consideration of the performance of services, but subject to the fulfillment of such conditions (which may include the achievement of management objectives) during the restriction period as the Committee may specify. Each grant or sale of RSUs may be made without additional consideration or in consideration of a payment by the participant that is less than the fair market value of shares of our common stock on the date of grant. During the applicable restriction period, the participant will have no ownership, transfer or voting rights in the shares of our common stock underlying the RSUs. Rights to dividend equivalents may be extended to and made part of any RSU award at the discretion of and on the terms determined by the Committee, provided that any dividend equivalents or other distributions on the shares of our common stock underlying the RSUs shall be deferred until and paid contingent upon the vesting of such RSUs. Each grant of RSUs will specify that the amount payable with respect to such RSUs will be paid in cash, shares of our common stock, or a combination of the two.

Cash Incentive Awards, Performance Shares, and Performance Units.   Performance shares, performance units and cash incentive awards may also be granted to participants under the 2022 Plan. A performance share is a bookkeeping entry that records the equivalent of one share of our common stock, and a performance unit is a bookkeeping entry that records a unit equivalent to $1.00 or such other value as determined by the Committee. Each grant will specify the number or amount of performance shares or performance units, or the amount payable with respect to cash incentive awards, being awarded, which number or amount may be subject to adjustment to reflect changes in compensation or other factors.

These awards, when granted under the 2022 Plan, become payable to participants upon the achievement of specified management objectives and upon such terms and conditions as the Committee determines at the time of grant. Each grant will specify the management objectives regarding the earning of the award. Each grant will specify the time and manner of payment of cash incentive awards, performance shares or performance units that have been earned, and any grant may further specify that any such amount may be paid or settled in cash, shares of our common stock, or any combination thereof. Any grant of performance

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shares or performance units may provide for the payment of dividend equivalents in cash or in additional shares of our common stock, provided that such dividend equivalents shall be subject to deferral and payment on a contingent basis based on the earning and vesting of the performance shares or performance units, as applicable, with respect to which such dividend equivalents are paid.

Other Awards.   The Committee may authorize the grant of such other awards (which we refer to as “other awards”) that may be denominated or payable in, valued in whole or in part by reference to, or otherwise based on, or related to, shares of our common stock or factors that may influence the value of such shares of our common stock, including, without limitation, convertible or exchangeable debt securities, other rights convertible or exchangeable into shares of our common stock, purchase rights for shares of our common stock, awards with value and payment contingent upon our performance or performance of specified subsidiaries, affiliates or other business units or any other factors designated by the Committee, and awards valued by reference to the book value of the shares of our common stock or the value of securities of, or the performance of our subsidiaries, affiliates or other business units.

Adjustments; Corporate Transactions.   The Committee will make or provide for such adjustments in the: (i) number and kind of shares of our common stock covered by outstanding stock options, appreciation rights, restricted stock, RSUs, performance shares, performance units and, if applicable, other awards; (ii) exercise price or base price provided in outstanding stock options and appreciation rights; (iii) cash incentive awards; and (iv) other award terms, as the Committee determines to be equitably required in order to prevent dilution or enlargement of the rights of participants that otherwise would result from (a) any extraordinary cash dividend, stock dividend, stock split, combination of shares, recapitalization or other change in our capital structure, (b) any merger, consolidation, spin-off, spin-out, split-off, split-up, reorganization, partial or complete liquidation or other distribution of assets, issuance of rights or warrants to purchase securities or (c) any other corporate transaction or event having an effect similar to any of the foregoing.

In the event of any such transaction or event, or in the event of a change in control (as defined in the 2022 Plan), the Committee may provide in substitution for any or all outstanding awards under the 2022 Plan such alternative consideration (including cash), if any, as it may in good faith determine to be equitable under the circumstances and will require in connection therewith the surrender of all awards so replaced in a manner that complies with Section 409A of the Code. In addition, for each stock option or appreciation right with an exercise price greater than the consideration offered in connection with any such transaction or event or change in control, the Committee may in its discretion elect to cancel such stock option or appreciation right without any payment to the person holding such stock option or appreciation right. The Committee will make or provide for such adjustments to the number of shares available for issuance under the 2022 Plan and the share limits of the 2022 Plan as the Committee in its sole discretion may in good faith determine to be appropriate in connection with such transaction or event.

Transferability of Awards.   Except as otherwise provided by the Committee, no stock option, appreciation right, restricted share, RSU, performance share, performance unit, cash incentive award, other award or dividend equivalents paid with respect to awards made under the 2022 Plan may be transferred by a participant except by will or the laws of descent and distribution.

Amendment and Termination of the 2022 Plan.   Our board of directors generally may amend the 2022 Plan from time to time in whole or in part. However, if any amendment (i) would materially increase the benefits accruing to participants under the 2022 Plan, (ii) would materially increase the number of shares of our common stock which may be issued under the 2022 Plan, (iii) would materially modify the requirements for participation in the 2022 Plan, or (iv) must otherwise be approved by our stockholders in order to comply with applicable law or the rules of the NYSE, then such amendment will be subject to stockholder approval and will not be effective unless and until such approval has been obtained.

Our board of directors may, in its discretion, terminate the 2022 Plan at any time. Termination of the 2022 Plan will not affect the rights of participants or their successors under any awards outstanding and not exercised in full on the date of termination. No grant will be made under the 2022 Plan more than 10 years after the effective date of the 2022 Plan, but all grants made prior to such date shall continue in effect thereafter subject to the terms of the 2022 Plan.

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IPO Equity Grants

The Compensation Committee approved the grant of RSU awards upon the consummation of this offering under the 2022 Plan, subject to final approval of our stockholders of the 2022 Plan, to our NEOs. Sixty percent (60%) of each RSU award is subject to performance-based vesting and will vest upon the achievement of pre-specified performance goals at the end of a three-year performance period and forty percent (40%) of each RSU award is subject to time-based vesting and will vest in three equal installments on each of the first three anniversaries of the grant date. The vesting of both the performance-based and time-based RSUs will be subject to the grantee’s continued employment through the applicable vesting date. We anticipate that the RSUs granted to our NEOs will have the following grant date fair values: Mr. Kalnin: $4,083,333, Mr. Jimenez: $1,866,667 and Mr. Jacobsen: $1,866,667. Following the vesting date, these RSU awards are expected to be settled in shares of our common stock.

BKV Corporation Employee Stock Purchase Plan

In connection with this offering, our board of directors adopted, and we anticipate our stockholders will approve, the ESPP. The ESPP is intended to qualify as an “employee stock purchase plan” under Section 423 of the Code. The material terms of the ESPP are as follows:

Purpose.   The purpose of the ESPP is to provide employees of the Company and certain of its subsidiaries with an opportunity to acquire a proprietary interest in the Company through the purchase of shares of our common stock.

Administration.   The ESPP will be administered by the Compensation Committee (for purposes of this section, the “Committee”). Subject to the terms of the ESPP, the Committee will have the complete discretion to establish the terms and conditions of offerings under the ESPP and the subsidiaries, if any, eligible to participate in such offerings, to interpret the ESPP and to make all decisions related to the operation of the ESPP. The board of directors has the same powers as the Committee and may act in lieu of the Committee with respect to the ESPP.

Shares Available for Issuance.   Subject to adjustment as described in the ESPP, the number of shares of our common stock available for awards under the ESPP is 1,000,000 shares of our common stock.

Eligibility.   All employees who have been employed by the Company or a designated subsidiary (whether currently existing or subsequently established) for at least six months prior to the beginning of an Offering and who work at least 20 hours per week and more than five months per calendar year are eligible to participate in the ESPP, resulting in approximately 355 employees (including six executive officers) as eligible participants. The Committee may permit employees who work less than 20 hours per week or less than five months per year to participate and may exclude certain categories of employees from participating in any offering to the extent permitted by Section 423 of the Code, including employees who have not completed a minimum period of service with the Company and/or highly compensated employees. An employee may be excluded from participation in the ESPP if his or her participation in the ESPP is prohibited by local law or if complying with local law would cause the ESPP or an offering to violate the requirements of Section 423 of the Code. Also, in accordance with Section 423 of the Code, no employee may be granted a right to purchase shares of the Company’s Class A Common Stock under the ESPP if, immediately after such grant, such employee would own stock and/or hold outstanding options to purchase stock possessing 5% or more of the total combined voting power or value of all classes of stock of the Company or any subsidiary (including in such calculation stock held directly or indirectly by or for the benefit of the employee and stock held by certain persons related to the employee) or if such option would permit his or her rights to purchase stock under all employee stock purchase plans of the Company and its subsidiaries to accrue at a rate that exceeds $25,000 of the fair market value of such stock (determined at the time the option is granted) for each calendar year in which such option is outstanding at any time.

Participation.   The ESPP will permit an eligible employee to purchase shares of the Company’s common stock through payroll deductions, which may not exceed 10% of the employee’s eligible compensation (or such lesser or greater limit as may be determined by the Committee for a particular offering). Employees will be able to withdraw all, but not less than all, of their accumulated payroll deductions prior to the end of an offering in accordance with the terms of the offering. Participation in the ESPP will

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end automatically upon termination of employment. In the event of withdrawal or termination of participation in the ESPP, a participant’s accumulated payroll contributions will be refunded without interest.

Certain limitations on the number of shares of our common stock that a participant may purchase apply. For example, if an offering is over-subscribed whereby, when added together, the total number of shares of our common stock purchased by all participants in a given offering would exceed the total number of shares of our common stock remaining available under the ESPP, the Committee shall allocate such shares remaining available under the ESPP in as uniform a manner as practicable and as the Committee determines to be equitable.

Offerings; Purchase Price.   The ESPP will be implemented through a series of offerings of up to a period of 27 months, which will consist of one offering period. During the offering period, payroll contributions will accumulate without interest and, on the last trading day of the offering period, accumulated payroll deductions will be used to purchase shares of our common stock.

The purchase price for each offering will be established by the Committee and may not be less than 85% of the fair market value of a share of our common stock on either the first trading day of an offering or on the purchase date, whichever is lower.

Adjustments.   In the event that there occurs a change in our capital structure through such actions as an extraordinary cash or a stock dividend, a stock split, combination of shares or recapitalization, or a merger, consolidation, spin-off, split-off, spin-out, split-up, reorganization, partial or complete liquidation or other distribution of assets, issuance of rights or warrants to purchase securities, or any other corporate transaction or event having a similar effect, then in order to prevent dilution or enlargement of the benefits or potential benefits intended to be made available under the ESPP, the Committee will adjust (1) the number of shares reserved under the ESPP, (2) the number of shares by which the share reserve may increase automatically each year, (3) the purchase price of outstanding options and (4) the number of shares that are subject to purchase limits under an ongoing offering.

Dissolution or Liquidation.   In the event of a proposed dissolution or liquidation of the Company, any offering then in progress will be shortened by setting a new purchase date before the proposed dissolution or liquidation and the offering will end immediately prior to the proposed dissolution or liquidation.

Change in Control.   Unless otherwise determined by the Committee, in the event of a change in control (as defined in the ESPP) each outstanding option under the ESPP will be assumed or an equivalent option will be substituted by the successor corporation (or a parent or subsidiary of such successor corporation) and if the successor corporation refused to assume or substitute the options, then, unless otherwise provided by the Committee, the offering with respect to which the option relates will be shortened by setting a new purchase date, that will occur before the date of the change in control, on which the offering will end.

ESPP Amendment or Termination.   The board of directors has the authority to amend or terminate our ESPP at any time. If any offering is terminated before its scheduled expiration, all amounts that have not been used to purchase shares of our common stock will be returned to participants (without interest, except as otherwise required by applicable law) as soon as administratively practicable. Unless earlier terminated by the board of directors, the ESPP shall have a term of 10 years.

Director Compensation

Name(1)	2021 Fees earned or paid in cash ($)(2)		Total($)
Chanin Vongkusolkit	​	—	​	—
Somruedee Chaimongkol	​	—	​	—
Joseph R. Davis	​	57,500	​	57,500
Akaraphong Dayananda	​	—	​	—
Thiti Mekavichai	​	—	​	—
Charles C. Miller III	​	57,500	​	57,500
Anon Sirisaengtaksin	​	—	​	—

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(1)

Mr. S. Vongkusolkit was elected to our board of directors effective July 19, 2022, and Ms. Mashinski and Mr.Patel were elected to our board effective September 1, 2022.

(2)

In 2021, Messrs. Davis and Miller each receive an annual $50,000 cash retainers and additional $7,500 cash retainers, for service on the Compensation Committee (for Mr. Davis) and service on the Audit & Risks Committee (for Mr. Miller).

Through September 1, 2022, the non-executive members of our board of directors, other than Messrs. Davis and Miller, did not receive any compensation from the Company. Any compensation paid through such time by Banpu to our non-executive directors, including Messrs. C. Vongkusolkit, Dayananda, Mekavichai and Sirisaengtaksin and Ms. Chaimongkol, is not reflected as such compensation was not paid by us or our subsidiaries and related to such individual’s services to Banpu.

On December 16, 2021, Mr. Davis, and on December 13, 2021, Messrs. Mekavichai and Miller, each purchased 6,000, 37,000 and 135,000 shares of our common stock, respectively, for a per share purchase price of $11.06 per share and an aggregate purchase price of $66,360; $409,220 and $1,493,100, respectively, under the Company’s 2020 Employee Stock Purchase Plan, adopted on July 16, 2020, as amended (the “2020 ESPP”). The 2020 ESPP afforded certain employees and directors of the Company selected by the Chief Executive Officer of the Company the opportunity to purchase shares of common stock for the greater of $10.00 per share and the fair market value of a share on the date of purchase.

Our board of directors adopted the BKV Corporation Non-Employee Director Compensation Program (the “Non-Employee Director Compensation Program”) which provides that, beginning on September 1, 2022, our non-employee directors will be compensated as follows:

•

Each non-employee director, other than a non-employee director who serves as chairman of the board, will be entitled to receive an annual cash retainer of $75,000, and any non-employee director serving as the chairman of the board will be entitled to receive an annual cash retainer of $137,500, each of which will be paid in quarterly installments, based on calendar quarters, in arrears on a prorated basis;

•

Members of our Audit & Risks Committee (other than the chairperson thereof) will be entitled to receive an additional cash retainer of $10,000, and the chairperson of the Audit & Risks Committee will be entitled to receive an additional cash retainer of $20,000, each paid in quarterly installments, based on calendar quarters, in arrears on a prorated basis;

•

Members of our Compensation Committee and Governance Committee (other than the chairpersons thereof) will be entitled to receive an additional cash retainer of $5,000, and the chairperson of the Compensation Committee and chairperson of the Governance Committee will be entitled to receive an additional cash retainer of $15,000, each paid in quarterly installments, based on calendar quarters, in arrears on a prorated basis;

•

Each non-employee director who is re-elected to serve, or will continue serving as a non-employee director immediately following any annual meeting of the Company’s stockholders, will receive an annual grant of RSUs on the date of the Company’s annual shareholder meeting with a grant date value of $140,000, if such non-employee director will not serving as the chairman of the board, or $202,500 if such non-employee director will serve as the chairman of the board, which will vest on the day prior to the first annual meeting of the Company’s stockholders following the date the RSUs are granted, subject to the non-employee director’s continued service; and

•

Each non-employee director will be reimbursed for reasonable out-of-pocket expenses incurred in attending meetings of the board or any of its committees.

Because the Non-Employee Director Compensation Program was adopted mid-term, compensation payable thereunder will be pro-rated based on the non-employee director’s service over the period beginning on the day the Non-Employee Director Compensation Program became effective through the day prior to the estimated date of the next annual meeting of the Company’s stockholders. To the extent the 2022 Plan has not become effective prior to such meeting, cash will be paid in lieu of the RSU awards. Messrs. C. Vongkusolkit, Dayananda, Mekavichai, Sirisaengtaskin and S. Vongkusolkit and Ms. Chaimongkol have waived their participation in the Non-Employee Director Compensation Plan, and therefore will not receive any compensation payable thereunder.

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PRINCIPAL STOCKHOLDERS

The following table sets forth certain information regarding the beneficial ownership of our common stock immediately following the completion of this offering by (i) each NEO, director and director nominee of the Company, (ii) all executive officers, directors and director nominees of the Company as a group; and (iii) each person known to the Company to own beneficially more than 5% of any class of our voting securities. Except as otherwise indicated, (a) the persons or entities identified in the table have sole voting and investment power with respect to all shares shown as beneficially owned by them and (b) the current directors and executive officers have not pledged any of such shares as security. All information with respect to beneficial ownership has been furnished by the respective 5% or more stockholders, directors, director nominees or executive officers, as the case may be.

The following information has been presented in accordance with the SEC’s rules and is not necessarily indicative of beneficial ownership for any other purpose. Under the SEC’s rules, beneficial ownership of a class of capital stock as of any date includes any shares of that class as to which a person, directly or indirectly, has or shares voting power or investment power as of that date and also any shares as to which a person has the right to acquire sole or shared voting or investment power as of or within 60 days after that date through the exercise of any stock option, warrant or other right (including any conversion or redemption right).

We have based our calculation of the percentage of beneficial ownership prior to this offering on           shares of our common stock outstanding as of the date of this prospectus. We have based our calculation of the percentage of beneficial ownership after this offering on           shares of our common stock outstanding immediately following the completion of this offering, assuming that the underwriters do not exercise their option to purchase additional shares.

Unless otherwise indicated, the address of each beneficial owner listed in the table below is c/o BKV Corporation, 1200 17th Street, Suite 2100, Denver, Colorado 80202.

​	Beneficial Ownership Before the Offering			Beneficial Ownership After the Offering
​	Common Stock		Total Voting Power Before the Offering	Common Stock		Total Voting Power After the Offering
Name of Beneficial Owner	Shares	%	%	Shares	%	%
Named Executive Officers, Directors and Director Nominees:	​	​	​	​	​	​
Christopher P. Kalnin	​	​	​	​	​	​
John T. Jimenez	​	​	​	​	​	​
Eric S Jacobsen	​	​	​	​	​	​
Somruedee Chaimongkol	​	​	​	​	​	​
Joseph R. Davis	​	​	​	​	​	​
Akaraphong Dayananda	​	​	​	​	​	​
Carla S. Mashinski	​	​	​	​	​	​
Thiti Mekavichai	​	​	​	​	​	​
Charles C. Miller III	​	​	​	​	​	​
Sunit S. Patel	​	​	​	​	​	​
Anon Sirisaengtaksin	​	​	​	​	​	​
Chanin Vongkusolkit	​	​	​	​	​	​
Sinon Vongkusolkit	​	​	​	​	​	​
All executive officers, directors and director nominees as a group (      persons)	​	​	​	​	​	​
5% Stockholders:	​	​	​	​	​	​
Banpu North America Corporation(1)	​	​	​	​	​	​

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*

Less than 1%.

(1)

Approximately 96.1% of our outstanding shares of common stock are currently owned by BNAC, a Delaware corporation wholly owned by BOG Co., Ltd., a wholly owned subsidiary of Banpu, a public company listed on the Stock Exchange of Thailand and the ultimate parent company of BKV Corporation, BNAC, Banpu Power and BPPUS. The principal address of Banpu is 27th Floor, Thanapoom Tower, 1550 New Petchburi Road, Makkasan, Ratchathewi, Bangkok, Thailand.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

We describe below transactions and series of similar transactions, during our last three fiscal years or currently proposed, to which we were a party or will be a party, in which:

•

the amounts involved exceeded or will exceed $120,000; and

•

any of our directors, director nominees, executive officers or beneficial holders of more than 5% of any class of our voting securities, or any immediate family member of any such person, had, or will have, a direct or indirect material interest.

Other than as described below, there have not been, nor are there any currently proposed, transactions or series of similar transactions meeting these criteria to which we have been or will be a party other than compensation arrangements, which are described where required under “Executive Compensation.”

Stockholders’ Agreement

We are party to a stockholders’ agreement, dated as of May 1, 2020, with certain of our stockholders, including BNAC and Chris Kalnin. Our existing stockholders’ agreement will be terminated prior to the completion of this offering.

Additionally, in connection with the closing of this offering, we will enter into our Stockholders’ Agreement with BNAC. Pursuant to 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 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. Under our Stockholders’ Agreement, we will agree to use our best efforts to cause the election of the individuals nominated by BNAC to our board of directors, including nominating such individuals to be elected as a director, recommending their election and soliciting proxies or consents in favor of their election. Our Stockholders’ Agreement also provides that we and BNAC shall, to the extent permitted by law, take actions to cause our Chief Executive Officer to be included in our board of directors.

In addition, for so long as BNAC and its affiliates beneficially own shares of our voting stock representing at least 25% of our total voting power, BNAC will have the right to designate the chairman of our board of directors from among its designees. Our Stockholders’ Agreement will also provide BNAC with certain information rights for so long as it continues to own shares of our voting stock representing at least 25% of our voting power. Further, we may not amend our charter or our bylaws in a manner inconsistent with the rights granted to BNAC pursuant to our Stockholders’ Agreement without BNAC’s consent.

Our Stockholders’ Agreement will terminate on the earlier to occur of (i) such time as BNAC is no longer entitled to designate a director pursuant to our Stockholders’ Agreement (except that the registration rights discussed below will survive and continue until BNAC and its affiliates no longer hold any shares of our common stock constituting registrable securities (as defined in our Stockholders’ Agreement)) and (ii) the delivery of written notice by BNAC to us requesting termination of our Stockholders’ Agreement.

BKV-BPP Power Joint Venture

BKV-BPP Power is jointly controlled by us and BPPUS through a board of directors (the “BKV-BPP board”) consisting of eight members, four of whom are appointed by us and four of whom are appointed by BPPUS. We account for BKV-BPP Power using the equity method of accounting.

In November 2021, BKV-BPP Power acquired Temple I for an aggregate purchase price of $430.0 million. BKV-BPP Power was formed in July 2021 for the purpose of purchasing and operating Temple I and is a joint venture owned 50% by us and 50% by BPPUS, a wholly owned subsidiary of Banpu Power.

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In connection with the purchase of Temple I, we made a capital contribution to BKV-BPP Power in the amount of $87.0 million and BPPUS made a capital contribution to BKV-BPP Power in the amount of $87.0 million.

BKV-BPP Loan Agreements

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

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

BKV-BPP Power’s payment obligations under the BKV-BPP Loan Agreements are senior unsecured indebtedness. The BKV-BPP Loan Agreements bear interest at six-month LIBOR plus 5.25% per annum. Interest on the loans is payable on a semi-annual basis, and the loans will mature on November 1, 2023. BKV-BPP is permitted to prepay the loans at any time, with no prepayment premium. The BKV-BPP Loan Agreements include covenants that, among other things, prohibit BKV-BPP from merging, incurring liens or incurring any additional indebtedness or guarantees. The BKV-BPP Loan Agreements include financial covenants that require BKV-BPP to maintain a minimum net worth (as defined in the BKV-BPP Loan Agreements, but generally meaning total assets minus total liabilities). In the $141 Million Banpu Loan Agreement, the minimum net worth requirement is $120.0 million and in the $141 Million BPPUS Loan Agreement, the minimum net worth requirement is $40.0 million. Under the BKV-BPP Loan Agreements, BNAC and BPPUS have no recourse to us with respect to any amounts owed to them thereunder and we are not liable in any manner (and are not required to provide security) for any obligations owed to them thereunder.

BKV-BPP Power Limited Liability Company Agreement

We and BPPUS are each a party to the BKV-BPP Power LLC Agreement governing the BKV-BPP Power Joint Venture, which, among other things, provides that a general manager appointed by the BKV-BPP board will have the power to manage and administer the business and affairs of BKV-BPP Power, subject to specified matters reserved for approval by the BKV-BPP board. The appointment and removal of the general manager must be approved by both the BKV-BPP board and BPPUS. Transfer or encumbrance of a party’s interest in BKV-BPP Power is permitted without prior approval of the other party or the BKV-BPP board. However, no transfer will be permitted if the transfer: (A) would subject BKV-BPP Power to U.S. federal securities law reporting requirements, (B) would cause BKV-BPP Power to lose its status as a U.S. partnership for federal income tax purposes or will cause BKV-BPP Power to be classified as a “publicly traded partnership,” ​(C) would violate, give rise to a default under or cause any payment to become due under any credit agreement, guaranty, or similar credit document or any other material contract to which BKV-BPP Power or any affiliate is bound, or (D) occurs prior to the repayment by BKV-BPP Power of all loans and other amounts outstanding under the term loans.

In the event that either party admits in writing that it is unable to perform its obligations (including any obligation to provide additional capital contributions) under the BKV-BPP Power LLC Agreement, the non-defaulting party will be entitled to (i) sell the assets of the joint venture and dissolve the joint venture on reasonable terms deemed acceptable to the BKV-BPP board, (ii) obtain specific performance of the non-defaulting party’s obligations, and/or (iii) exercise any other right or remedy provided in law or in equity.

The BKV-BPP board will determine the amount and timing of distributions of operating cash flow (which will be done no less frequently than once per quarter) and net capital proceeds (which will be distributed within three business days after becoming available for distribution). All distributions will be

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made on a pro-rata basis to us and BPPUS. As of June 30, 2022, no distributions have been made by BKV-BPP Power. Additional cash capital contributions will be required to be made by us and by BPPUS on a pro-rata basis upon 30 days written notice either by us or by BPPUS; provided that the additional contributions must be expended on items included in the annual approved budget, items in response to an emergency in the event that BKV-BPP Power does not have sufficient cash reserves to address such emergency, or any other matter approved by the BKV-BPP board. Otherwise, neither us nor BPPUS will be required to provide additional capital contributions without consent.

Major decisions and significant activities of BKV-BPP Power are reserved for approval by at least a majority of the members of the BKV-BPP board, such as, among other things, any merger, consolidation, amalgamation, conversion of BKV-BPP or any of its subsidiaries, into another form or entity or other business combination of any nature, wind up, the dissolution, liquidation, commencement or any filing or petition for a voluntary bankruptcy, reorganization, debt arrangement involving BKV-BPP Power, any plan to or initial sale of BKV-BPP Power or other equity interests to the public, any amendments, restatements or revocations of its organizational documents, execution, amendment or termination of a material contract, and any amendment to or deviation from the dividend policy of the joint venture or any of its subsidiaries. Under the terms of the BKV-BPP Power LLC Agreement:

•

we do not have the power to unilaterally cause BKV-BPP Power to make distributions;

•

we may be required to make additional capital contributions to fund items approved in the annual budget or other matters approved by the board of BKV-BPP Power at the request of BPPUS, which would reduce the amount of cash otherwise available for dividend payments by us on our common stock or require us to incur additional indebtedness; and

•

BKV-BPP Power may incur additional indebtedness in an amount greater than $1,500,000 if approved by the board of BKV-BPP Power, which debt payments would reduce the amount of cash that might otherwise be available for distributions to us.

In December 2021, we entered into an Administrative Service Agreement (the “Administrative Services Agreement”) with BKV-BPP Power. Under the Administrative Service Agreement, we provide certain operational, accounting, tax and other services as required by the Administrative Services Agreement and in return receive an annual fee of $2.6 million until December 1, 2022, with options to extend. In addition to the annual fee, we are entitled to receive reimbursement for all (i) reasonable, ordinary and necessary out-of-pocket expenses actually incurred in connection with travel, (ii) actual costs of audits, legal fees, tax return preparations and other third-party professional fees approved by BKV-BPP Power and (iii) reasonable, ordinary and necessary out-of-pocket expenses actually incurred by us in connection with the services provided by us under the Administrative Services Agreement. During the six months ended June 30, 2022 and the year ended December 31, 2021, we recognized $1.3 million and $0.2 million, respectively, of revenues related to the services provided under the Administrative Services Agreement.

Loan Agreements

Intercompany Loan Agreements

On December 17, 2019, BKV O&G entered into the $10 Million Loan Agreement with BNAC, which allowed for a single drawdown in the amount of $10.0 million. On June 23, 2020, we entered into a novation agreement with BKV O&G and BNAC, which transferred all of BKV O&G’s rights and obligations under the $10 Million Loan Agreement to us. Also on June 23, 2020, we entered into the First Amendment to the Loan Agreement. On July 1, 2020, we borrowed $10.0 million thereunder for working capital purposes. During the year ended December 31, 2020, we paid $0.2 million in interest on the loan, and on December 31, 2020, we repaid $5.0 million of the outstanding principal amount of the loan. During the year ended December 31, 2021, we paid $0.1 million in interest on the loan and repaid the remaining outstanding principal amount of the loan in full. The First Amendment to $10 Million Loan Agreement terminated on June 20, 2021.

On September 28, 2020, we borrowed $119.0 million under the $119 Million Loan Agreement with BNAC to partially fund the Devon Barnett Acquisition and for working capital. During the year ended December 31, 2020, we paid $1.5 million in interest on the loan, and on December 16, 2020, we repaid

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$100.0 million of the outstanding principal amount of the loan. During the year ended December 31, 2021, we paid $0.2 million in interest on the loan, and on March 15, 2021, we repaid the remaining outstanding principal amount of the loan in full. The $119 Million Loan Agreement terminated concurrently with repayment of the remaining principal amount.

On November 8, 2021, we borrowed $50.0 million under the $50 Million Loan Agreement with BNAC. On January 11, 2022, we repaid $15.0 million of the outstanding principal amount of the loan. On June 1, 2022, we paid $1.3 million in interest on the loan and repaid the remaining $35.0 million of the outstanding principal amount of the loan in full. The $50 Million Loan Agreement terminated concurrently with repayment of the remaining principal amount.

For additional information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Loan Agreements and Credit Facilities —  Intercompany Loan Agreements.”

Subordinated Intercompany Loan Agreements

On October 14, 2021, we borrowed $116.0 million under the $116 Million Loan Agreement with BNAC to redeem all of the outstanding preferred and common stock of the company owned by OCM BKV Holdings, LLC, an affiliate of Oaktree Capital Management L.P. Following such redemption, we do not have any issued and outstanding preferred stock. On June 15, 2022, we entered into the $116 Million A&R Loan Agreement, which amended and restated the $116 Million Loan Agreement to, among other things, subordinate the $116.0 million term loan owed to BNAC thereunder to the term loans we borrowed under the Term Loan Credit Agreement. On August 24, 2022, BNAC entered into a Subordination Agreement with Bangkok Public Company Limited, New York Branch, which subordinated the $116.0 million term loan owed to BNAC to the revolving loans at any time outstanding under the Revolving Credit Agreement (the “August 2022 Subordination Agreement”).

On March 10, 2022, we borrowed $75.0 million under the $75 Million Loan Agreement with BNAC to fund the deposit for the Exxon Barnett Acquisition. On June 15, 2022, we entered into the $75 Million A&R Loan Agreement, which amended and restated the $75 Million Loan Agreement to, among other things, subordinate the $75.0 million term loan owed to BNAC thereunder to the term loans we borrowed under the Term Loan Credit Agreement. The August 2022 Subordination Agreement provides for the subordination of the $75.0 million term loan owed to BNAC thereunder to the revolving loans at any time outstanding under the Revolving Credit Agreement.

For additional information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Loan Agreements and Credit Facilities —  Subordinated Intercompany Loan Agreements.”

Tax Sharing Agreement

Since our inception, BNAC has owned, directly and indirectly, in excess of 80% of the outstanding shares of our common stock, with the result that we have been included in BNAC’s consolidated federal income tax group (as well as in certain consolidated, combined and unitary state and local income tax returns filed by BNAC). If and when BNAC’s ownership of our common stock falls below 80%, we will cease to be part of BNAC’s consolidated federal income tax group (a “deconsolidation event”). We are party to a Tax Sharing Agreement, dated as of May 1, 2020 (the “Existing Tax Sharing Agreement”), with BNAC, providing for payment by us to BNAC of the amounts payable by us in respect of U.S. federal income taxes and certain state and local taxes, and for certain payments by BNAC to us. We made no payments to BNAC under the Existing Tax Sharing Agreement in 2020, 2021 and as of June 30, 2022.

At the completion of this offering, we anticipate BNAC will own less than 80% of the outstanding shares of our common stock and, as a result, we will generally be deconsolidated from BNAC for federal and, in most cases, state, income tax purposes for periods beginning after completion of the offering. In anticipation of this offering, we will enter into an Amended and Restated Tax Sharing Agreement with BNAC, which sets forth the principles and responsibilities (i) governing the allocation of consolidated U.S. federal income tax liabilities and consolidated, combined and unitary state and local income tax liabilities

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between us and BNAC during the periods in which we have been and are included in any consolidated or combined income tax return filed by BNAC, (ii) specifying the allocation of tax attributes and tax liabilities in connection with deconsolidation and (iii) setting forth agreements with respect to certain other tax matters.

The Amended and Restated Tax Sharing Agreement contains provisions that we believe are customary for tax sharing agreements between members of a consolidated group. In particular, we make payments to BNAC in respect of our allocable share of the U.S. federal income consolidated tax liability and state and local combined tax liability, in each case as determined on a separate return basis. In addition, we are compensated for the use of our net operating losses and other tax assets to the extent such assets reduce the U.S. federal income consolidated tax liability or state and local combined tax liability, as applicable, during the periods in which we have been and are included in any consolidated or combined income tax return filed by BNAC. The Amended and Restated Tax Sharing Agreement also includes customary indemnification clauses and survives until all obligations and liabilities of the parties arising under the agreement are satisfied.

Registration Rights

Our Stockholders’ Agreement will provide BNAC and its affiliates with the right, in certain circumstances, to require us to register their shares of our common stock constituting registrable securities under the Securities Act for sale into the public markets and with certain piggyback rights, as described below. Our Stockholders’ Agreement will also provide that we will pay certain expenses of BNAC and its affiliates relating to such registrations and indemnify them against certain liabilities that may arise under the Securities Act.

Demand Rights/Shelf Registration Rights

Subject to certain limitations, following the date that is six months after the consummation of this offering, BNAC and its affiliates will have the right, by delivering written notice to us, to require us to register the number of their registrable securities requested under the Securities Act. In no event later than 45 days after receiving a valid demand request, we are required to file or confidentially submit, at our discretion, with the SEC a registration statement covering all of the registrable securities covered by such demand request, subject to the limitations discussed below. We will not be obligated to effect more than two such registered offerings in any twelve-month period.

Upon the delivery of written notice to us by BNAC and its affiliates from time to time after a shelf registration statement has been declared effective by the SEC, we will facilitate a takedown of registrable securities off of an effective shelf registration statement. We will not be required to effect (i) an underwritten shelf takedown unless the offering includes securities with a total offering price (including piggyback securities and before deducting underwriting discounts) reasonably expected to exceed, in the aggregate, $5.0 million and (ii) more than two offerings demanded pursuant to this paragraph or the preceding paragraph in any twelve-month period.

In addition, if we are eligible to file a shelf registration statement on Form S-3, BNAC and its affiliates can request that we register their registrable securities for resale on a shelf registration statement.

Piggyback Rights

BNAC and its affiliates will be entitled to request to participate in, or “piggyback” on, registrations of common stock for sale by us or underwritten shelf takedowns. This piggyback right does not apply to, among other things, a registration relating to our employee benefit plans, a registration on Form S-4 or Form S-8 (or any similar successor forms) or a registration where the registrable securities are not being sold for cash.

Conditions and Limitations

The rights outlined above will be subject to conditions and limitations, including the right of the underwriters to limit the number of shares of our common stock to be included in a registration statement and our right to postpone or suspend a registration statement under specified circumstances.

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Indemnification Agreements with our Directors and Officers

We intend to enter into indemnification agreements, to be effective upon the completion of this offering, with each of our directors and officers. The indemnification agreements and our governing documents will require us to indemnify our directors and officers to the fullest extent permitted by Delaware law. Subject to certain limitations, the indemnification agreements and our governing documents will also require us to advance expenses incurred by our directors and officers. For more information regarding these agreements, see “Description of Capital Stock — Limitations of Liability and Indemnification.”

Policies and Procedures Regarding Related Party Transactions

Upon completion of this offering, we expect that our board of directors will adopt a new written Code of Business Conduct and Ethics that complies with all applicable requirements of the SEC and NYSE and that contains conflict of interest policies governing transactions involving any director, executive officer or beneficial owner of more than 5% of any class of our voting securities that could be deemed to present a conflict of interest.

Upon completion of this offering, we expect that our board of directors will adopt a written related party transactions policy, pursuant to which our Audit & Risks Committee will be responsible for reviewing and either approving, ratifying or disapproving such transactions with our directors, officers or beneficial owners of more than 5% of any class of our voting securities, or any immediate family member of any of the foregoing persons. In considering a related party transaction, our Audit & Risks Committee will take into account relevant facts and circumstances relating to whether the transaction is in the best interests of the Company, including the following:

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the materiality of the transaction to the related party and the Company;

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the business purpose for and reasonableness of the transaction; and

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whether the transaction is comparable to a transaction that could be available with an unrelated party or is on terms that the Company offers generally to persons who are not related parties.

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DESCRIPTION OF CAPITAL STOCK

General

The following description summarizes certain important terms of our capital stock and of our governing documents, as each will be in effect upon the completion of this offering. For a complete description of the matters set forth in this section titled “Description of Capital Stock,” you should refer to our governing documents, which are included as exhibits to the registration statement of which this prospectus forms a part, and to the applicable provisions of Delaware law.

Upon completion of this offering, our authorized capital stock will consist of 500,000,000 shares of common stock, $0.01 par value per share, of which       shares (or       shares if the underwriters exercise in full their option to purchase additional shares) will be issued and outstanding and 80,000,000 shares of preferred stock, $0.01 par value per share, of which no shares will be issued and outstanding. In addition,           shares of our common stock will be reserved for issuance under our equity compensation plans. See “Executive Compensation — BKV Corporation 2022 Equity and Incentive Compensation Plan.”

As of the date of this prospectus, BNAC owns approximately 96.1% of our common stock.

Common Stock

Holders of shares of our common stock are entitled to one vote for each share held of record on all matters on which stockholders are entitled to vote generally, including the election or removal of directors elected by our stockholders generally. Holders of our common stock do not have cumulative voting rights in the election of directors. Subject to certain nomination rights of BNAC under our Stockholders’ Agreement, holders of our common stock will be entitled to elect all directors to our board of directors. See “Certain Relationships and Related Party Transactions — Stockholders’ Agreement.”

Holders of shares of our common stock are entitled to receive dividends when, as and if declared by our board of directors out of funds legally available therefor, subject to any statutory or contractual restrictions on the payment of dividends and to any restrictions on the payment of dividends imposed by the terms of any outstanding preferred stock. See “Dividend Policy.”

Upon our liquidation, dissolution or winding up and after payment in full of all amounts required to be paid to creditors and to the holders of preferred stock having liquidation preferences, if any, the holders of shares of our common stock will be entitled to receive pro rata our remaining assets available for distribution.

All shares of our common stock that will be outstanding at the time of the completion of the offering will be fully paid and non-assessable. Our common stock will not be subject to further calls or assessments by us. Holders of shares of our common stock do not have preemptive, subscription, redemption or conversion rights. There will be no redemption or sinking fund provisions applicable to our common stock. The rights powers, preferences and privileges of our common stock will be subject to those of the holders of any shares of our preferred stock or any other series or class of stock we may authorize and issue in the future.

Preferred Stock

No shares of preferred stock will be issued or outstanding immediately after the offering contemplated by this prospectus. Our certificate of incorporation authorizes our board of directors to establish one or more series of preferred stock (including convertible preferred stock). Unless required by law or any stock exchange, the authorized shares of preferred stock will be available for issuance without further action by the holders of our common stock. Our board of directors is able to determine, with respect to any series of preferred stock, the powers (including voting powers), preferences and relative, participating, optional or other special rights, and the qualifications, limitations or restrictions thereof, including, without limitation:

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the designation of the series;

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the number of shares of the series, which our board of directors may, except where otherwise provided in the preferred stock designation, increase (but not above the total number of authorized shares of the class) or decrease (but not below the number of shares then outstanding);

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•

whether dividends, if any, will be cumulative or non-cumulative and the dividend rate of the series;

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the dates at which dividends, if any, will be payable;

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the redemption or repurchase rights and price or prices, if any, for shares of the series;

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the terms and amounts of any sinking fund provided for the purchase or redemption of shares of the series;

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the amounts payable on shares of the series in the event of any voluntary or involuntary liquidation, dissolution or winding-up of our affairs;

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whether the shares of the series will be convertible into shares of any other class or series, or any other security, of us or any other entity, and, if so, the specification of the other class or series or other security, the conversion price or prices or rate or rates, any rate adjustments, the date or dates as of which the shares will be convertible and all other terms and conditions upon which the conversion may be made;

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restrictions on the issuance of shares of the same series or of any other class or series; and

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the voting rights, if any, of the holders of the series.

Dividends

The DGCL permits a corporation to declare and pay dividends on shares of its capital stock out of “surplus” or, if there is no “surplus,” out of its net profits for the fiscal year in which the dividend is declared and/or the preceding fiscal year. “Surplus” is defined as the excess of the net assets of the corporation over the amount determined to be the capital of the corporation by its board of directors. The capital of the corporation is typically calculated to be (and cannot be less than) the aggregate par value of all issued shares of capital stock. Net assets equals the fair value of the total assets minus total liabilities. The DGCL also provides that dividends may not be paid out of net profits if, after the payment of the dividend, remaining capital would be less than the capital represented by the outstanding stock of all classes having a preference upon the distribution of assets. Declaration and payment of any dividend will be subject to the discretion of our board of directors. See “Dividend Policy.”

Annual Stockholder Meetings

Our bylaws provide that annual stockholder meetings will be held at a date, time and place, if any, as determined by our board of directors or a duly authorized committee thereof. To the extent permitted under applicable law, we may conduct meetings by remote communications, including by webcast.

Anti-Takeover Provisions

Our governing documents and the DGCL contain provisions, which are summarized in the following paragraphs, that are intended to enhance the likelihood of continuity and stability in the composition of our board of directors. These provisions are intended to avoid costly takeover battles, reduce our vulnerability to a hostile or abusive change of control and enhance the ability of our board of directors to maximize stockholder value in connection with any unsolicited offer to acquire us. However, these provisions may have an anti-takeover effect and may delay, deter or prevent a merger or acquisition of the Company by means of a tender offer, a proxy contest or other takeover attempt that a stockholder might consider in its best interest, including those attempts that might result in a premium over the prevailing market price for the shares of common stock held by stockholders.

Authorized but Unissued Capital Stock

Delaware law does not require stockholder approval for any issuance of shares that are authorized and available for issuance. However, the listing requirements of the NYSE, which would apply so long as our common stock remains listed on the NYSE, require stockholder approval of certain issuances equal to or exceeding 20% of the then outstanding voting power of our capital stock or then outstanding number of shares of common stock. These additional shares may be used for a variety of corporate purposes, including future public offerings, to raise additional capital or to facilitate acquisitions.

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Our board of directors may generally issue shares of one or more series of preferred stock on terms calculated to discourage, delay or prevent a change of control of the Company or the removal of our management. Moreover, our authorized but unissued shares of preferred stock will be available for future issuances in one or more series without stockholder approval and could be utilized for a variety of corporate purposes, including future offerings to raise additional capital, to facilitate acquisitions and employee benefit plans.

One of the effects of the existence of authorized and unissued and unreserved common stock or preferred stock may be to enable our board of directors to issue shares to persons friendly to current management, which issuance could render more difficult or discourage an attempt to obtain control of the Company by means of a merger, tender offer, proxy contest or otherwise, and thereby protect the continuity of our management and possibly deprive our stockholders of opportunities to sell their shares of common stock at prices higher than prevailing market prices.

Classified Board of Directors

Our certificate of incorporation provides that our board of directors will be divided into three classes of directors, with each class to be as equal in number as possible, and with the directors serving staggered three-year terms. As a result, approximately one-third of our board of directors will be elected each year. The classification of directors will have the effect of making it more difficult for stockholders to change the composition of our board of directors. Our certificate of incorporation provides that, subject to any rights of holders of preferred stock to elect additional directors under specified circumstances, the total number of directors will be determined from time to time by the affirmative vote of a majority of the total number of directors then in office.

Delaware Law

We will be subject to the provisions of Section 203 of the DGCL regulating corporate takeovers. Section 203 of the DGCL provides that, subject to exceptions specified therein, an “interested stockholder” of a Delaware corporation shall not engage in any “business combination,” including general mergers or consolidations or acquisitions of additional shares of the corporation, with the corporation for a three-year period following the time that such stockholder becomes an interested stockholder unless:

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prior to such time, the board of directors of the corporation approved either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder;

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upon consummation of the transaction that resulted in the stockholder becoming an “interested stockholder,” the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced (excluding specified shares); or

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at or subsequent to such time, the business combination is approved by the board of directors of the corporation and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 662∕3% of the outstanding voting stock not owned by the interested stockholder.

Under Section 203 of the DGCL, the restrictions described above also do not apply to specified business combinations proposed by an interested stockholder following the announcement or notification of one of specified transactions involving the corporation and a person who had not been an interested stockholder during the previous three years or who became an interested stockholder with the approval of a majority of the corporation’s directors, if such transaction is approved or not opposed by a majority of the directors who were directors prior to any person becoming an interested stockholder during the previous three years or were recommended for election or elected to succeed such directors by a majority of such directors.

Except as otherwise specified in Section 203 of the DGCL, an “interested stockholder” is defined to include:

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any person that is the owner of 15% or more of the outstanding voting stock of the corporation, or is an affiliate or associate of the corporation and was the owner of 15% or more of the outstanding voting stock of the corporation at any time within three years immediately prior to the date of determination; and

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•

the affiliates and associates of any such person.

Under some circumstances, Section 203 of the DGCL makes it more difficult for a person who is an interested stockholder to effect various business combinations with us for a three-year period following the time such stockholder became an interested stockholder.

A Delaware corporation may “opt out” of Section 203 of the DGCL with an express provision in its original certificate of incorporation or an express provision in its certificate of incorporation or bylaws resulting from amendments approved by the holders of at least a majority of the corporation’s outstanding voting shares. We do not intend to “opt out” of the provisions of Section 203 of the DGCL. The statute could prohibit or delay mergers or other takeover or change in control attempts and, accordingly, may discourage attempts to acquire us.

Removal of Directors; Vacancies and Newly Created Directorships

Under the DGCL, unless otherwise provided in our certificate of incorporation, directors serving on a classified board may be removed by the stockholders only for cause. Our certificate of incorporation provides that directors may be removed only for cause and only by the affirmative vote of the holders of at least 60% in voting power of all the then-outstanding shares of our stock entitled to vote generally in the election of directors, voting together as a single class. In addition, our certificate of incorporation provides that, subject to the rights granted to the holders of one or more series of preferred stock then outstanding or the rights granted under our Stockholders’ Agreement, any vacancies on our board of directors, and any newly created directorships, will be filled by a majority of the total number of directors then in office, even if less than a quorum, or by a sole remaining director, and not by the stockholders.

No Cumulative Voting

Under the DGCL, the right to vote cumulatively does not exist unless the certificate of incorporation specifically authorizes cumulative voting. Our certificate of incorporation does not authorize cumulative voting. Therefore, stockholders holding a majority in voting power of the shares of our stock entitled to vote generally in the election of directors will be able to elect all our directors, subject to certain nomination rights of BNAC under our Stockholders’ Agreement. See “Certain Relationships and Related Party Transactions — Stockholders’ Agreement.”

Special Stockholder Meetings

Our certificate of incorporation provides that, subject to the rights of the holders of any series of preferred stock, special meetings of our stockholders may be called at any time only by or at the direction of our board of directors by the affirmative vote of a majority of the total number of directors then in office, the chairman of our board of directors or our Chief Executive Officer, and may not be called by any other person or persons. Our bylaws prohibit the conduct of any business at a special meeting other than as specified in the notice for such meeting. These provisions may have the effect of deterring, delaying or discouraging hostile takeovers, or changes in control or management of the Company.

Director Nominations and Stockholder Proposals

Our bylaws establish advance notice procedures with respect to stockholder proposals and the nomination of candidates for election as directors, other than nominations made by or at the direction of the board of directors or a committee of the board of directors. In order for any matter to be “properly brought” before a meeting, a stockholder will have to comply with advance notice requirements and provide us with certain information. Generally, to be timely, a stockholder’s notice must be received at our principal executive offices not later than the close of business on the 90th day nor earlier than the close of business on the 120th day prior to the first anniversary date of the immediately preceding annual meeting of stockholders. Our bylaws also specify requirements as to the form and content of a stockholder’s notice. Our bylaws allow the chairman of the meeting at a meeting of the stockholders to adopt rules and regulations for the conduct of meetings which may have the effect of precluding the conduct of certain business at a meeting if the rules and regulations are not followed. These provisions may also defer, delay or discourage a

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potential acquirer from conducting a solicitation of proxies to elect the acquirer’s own slate of directors or otherwise attempting to influence or obtain control of the Company.

Stockholder Action by Written Consent

Under the DGCL, any action required to be taken at any annual or special meeting of the stockholders may be taken without a meeting, without prior notice and without a vote if a consent or consents in writing, setting forth the action so taken, is or are signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares of our stock entitled to vote thereon were present and voted, unless our certificate of incorporation provides otherwise. Our certificate of incorporation precludes stockholder action by written consent at any time when BNAC and its affiliates and subsidiaries (excluding the Company and its subsidiaries) own, in the aggregate, less than 35% in voting power of our stock entitled to vote generally in the election of directors.

Supermajority Provisions

Our governing documents provide that our board of directors is expressly authorized to make, repeal, alter, amend and rescind, in whole or in part, our bylaws by the affirmative vote of a majority of the total number of directors then in office, without the assent or vote of the stockholders in any matter not inconsistent with the laws of the State of Delaware or our certificate of incorporation. Any amendment, alteration, rescission or repeal of any provision of our bylaws, or the adoption of any provision inconsistent with our bylaws, by our stockholders requires the affirmative vote of the holders of at least 662∕3% in voting power of all the then-outstanding shares of our stock entitled to vote thereon, voting together as a single class, in addition to any vote of the holders of any class or series of our capital stock required by our governing documents or applicable law or securities exchange rule or regulation.

The DGCL provides generally that the affirmative vote of a majority of the outstanding shares entitled to vote thereon, voting together as a single class, is required to amend a corporation’s certificate of incorporation, unless the certificate of incorporation requires a greater percentage.

Our certificate of incorporation provides that, in addition to any vote required by our governing documents or applicable law or securities exchange rule or regulation, the following provisions in our certificate of incorporation may be amended, altered, repealed or rescinded, in whole or in part, or any provision inconsistent therewith may be adopted, only by the affirmative vote of the holders of at least 662∕3% in voting power all the then-outstanding shares of our stock entitled to vote thereon, voting together as a single class (except that, in the case of any proposed amendment, alteration, repeal or rescission of, or the adoption of any provision inconsistent with, the following provisions, as to which the DGCL does not require the consent or vote of the stockholders or that is approved by at least 60% of our board of directors, then only the affirmative vote of the holders of a majority in voting power of all the then-outstanding shares of our stock entitled to vote thereon, voting together as a single class (in addition to any vote required by our governing documents or applicable law or securities exchange rule or regulation), will be required to amend, alter, repeal or rescind, or adopt any provision inconsistent with, the following provisions:

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the provisions requiring a 662∕3% supermajority vote for stockholders to amend our bylaws;

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the provisions providing for a classified board of directors (the election and term of our directors);

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the provisions regarding removal of directors;

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the provisions regarding filling vacancies on our board of directors and newly-created directorships;

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the provisions eliminating monetary damages for breaches of fiduciary duty by a director or officer;

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the provisions regarding indemnification and advancement of expenses to certain indemnitees in connection with certain proceedings;

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the provisions regarding stockholder action by written consent;

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the provisions regarding calling special meetings of stockholders;

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the provisions regarding competition and corporate opportunities; and

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•

the amendment provision requiring that the above provisions be amended with a majority vote or a 662∕3% supermajority vote, as applicable, of stockholders.

The combination of the classification of our board of directors, the lack of cumulative voting and the supermajority voting requirements in certain circumstances will make it more difficult for our existing stockholders to replace our board of directors as well as for another party to obtain control of us by replacing our board of directors. Because our board of directors has the power to retain and discharge our officers, these provisions could also make it more difficult for existing stockholders or another party to effect a change in management.

These provisions may have the effect of deterring hostile takeovers or delaying or preventing changes in control of us or our management, such as a merger, reorganization or tender offer. These provisions are intended to enhance the likelihood of continued stability in the composition of our board of directors and its policies and to discourage certain types of transactions that may involve an actual or threatened acquisition of the Company. These provisions are designed to reduce our vulnerability to an unsolicited acquisition proposal. The provisions are also intended to discourage certain tactics that may be used in proxy fights. However, such provisions could have the effect of discouraging others from making tender offers for our shares and, as a consequence, they also may inhibit fluctuations in the market price of our shares that could result from actual or rumored takeover attempts. Such provisions may also have the effect of preventing changes in management.

Dissenters’ Rights of Appraisal and Payment

Under the DGCL, with certain exceptions, our stockholders will have appraisal rights in connection with a merger or consolidation of the Company. Pursuant to the DGCL, stockholders who properly request and perfect appraisal rights in connection with such merger or consolidation will have the right to receive payment of the fair value of their shares as determined by the Delaware Court of Chancery.

Stockholders’ Derivative Actions

Under the DGCL, any of our stockholders may bring an action in our name to procure a judgment in our favor, also known as a derivative action, provided that the stockholder bringing the action is a holder of our shares at the time of the transaction to which the action relates or such stockholder’s stock thereafter devolved by operation of law.

Choice of Forums

Our certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by law, be the sole and exclusive forum for any (i) derivative action or proceeding brought on behalf of the Company, (ii) action asserting a claim of breach of a fiduciary duty owed by any director, officer or employee of the Company to the Company or our stockholders, (iii) action asserting a claim against the Company or any director or officer of the Company arising pursuant to any provision of the DGCL or our governing documents, or (iv) action asserting a claim against the Company or any director, officer or employee of the Company, which claim is governed by the internal affairs doctrine. Notwithstanding the foregoing sentence, the federal district courts of the United States of America will be the exclusive forum for the resolution of any complaint asserting a cause of action arising under U.S. federal securities laws, including the Securities Act and the Exchange Act. Any person or entity purchasing or otherwise acquiring any interest in shares of capital stock of the Company will be deemed to have notice of and consented to the forum provisions in our certificate of incorporation. However, the enforceability of similar forum provisions in other companies’ certificates of incorporation has been challenged in legal proceedings, and it is possible that a court could find these types of provisions to be unenforceable.

Corporate Opportunity

The DGCL permits corporations to adopt provisions renouncing any interest or expectancy of the corporation in, or in being offered an opportunity to participate in, specified business opportunities that are presented to the corporation or its officers, directors or stockholders. Our certificate of incorporation, to

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the fullest extent permitted by law, renounces any interest or expectancy that we have in, or right to be offered an opportunity to participate in, specified business opportunities that are from time to time presented to our officers, directors or stockholders or their respective affiliates, other than those officers, directors, stockholders or affiliates who are our or our subsidiaries’ employees. Our certificate of incorporation provides that, to the fullest extent permitted by law, neither BNAC nor its affiliates or any director who is not employed by us (including any non-employee director who serves as one of our officers in both his or her director and officer capacities) or his or her affiliates will have any duty to refrain from (i) engaging in the same or similar business activities or lines of business in which we or our affiliates now engage or propose to engage or (ii) otherwise competing with us or our affiliates. In addition, to the fullest extent permitted by law, in the event that BNAC or its affiliates or any non-employee director acquires knowledge of a potential transaction or other business opportunity that may be a corporate opportunity for itself, himself or herself or its or his or her affiliates or for us or any of our affiliates, such person will have no duty to communicate or offer such transaction or business opportunity to us or any of our affiliates and they may take any such opportunity for themselves or offer it to another person or entity. Our certificate of incorporation does not renounce our interest in any corporate opportunity that is expressly offered to a non-employee director solely in his or her capacity as a director or officer of the Company. To the fullest extent permitted by law, a business opportunity will not be deemed to be a potential corporate opportunity for us if we would not be financially or legally able, or contractually permitted to undertake, the opportunity; the opportunity, from its nature, would not be in the line of our business; or the opportunity is one in which we would have no interest or reasonable expectancy.

Limitations of Liability and Indemnification

The DGCL authorizes corporations to limit or eliminate the personal liability of directors to corporations and their stockholders for monetary damages for breaches of directors’ fiduciary duties, subject to certain exceptions. Our certificate of incorporation includes a provision that eliminates the personal liability of our directors and officers for monetary damages to the Company or its stockholders for any breach of fiduciary duty as a director or an officer, to the fullest extent permitted by the DGCL. The effect of these provisions is to eliminate the rights of us and our stockholders, through stockholders’ derivative suits on our behalf, to recover monetary damages from a director or an officer for breach of fiduciary duty as a director or an officer, including breaches resulting from grossly negligent behavior. However, exculpation does not apply to any breaches of the duty of loyalty, any acts or omissions not in good faith or that involve intentional misconduct or knowing violation of law, any authorization of dividends or stock redemptions or repurchases paid or made in violation of the DGCL, or for any transaction from which the director derived an improper personal benefit.

Our certificate of incorporation and our bylaws generally provide that we must defend, indemnify and advance expenses to our directors and officers to the fullest extent permitted by the DGCL. We also are expressly authorized to carry directors’ and officers’ liability insurance providing indemnification for our directors, officers and certain employees for some liabilities. We believe that these indemnification and advancement provisions and insurance are useful to attract and retain qualified directors and executive officers.

The limitation of liability, indemnification and advancement provisions in our certificate of incorporation and our bylaws may discourage stockholders from bringing a lawsuit against directors or officers for breach of their fiduciary duty. These provisions also may have the effect of reducing the likelihood of derivative litigation against directors and officers, even though such an action, if successful, might otherwise benefit us and our stockholders. In addition, your investment may be adversely affected to the extent we pay the costs of settlement and damage awards against directors and officers pursuant to these indemnification provisions.

There is currently no pending material litigation or proceeding involving any of our directors, officers or employees for which indemnification is sought.

Indemnification Agreements

We intend to enter into an indemnification agreement with each of our directors and officers as described in “Certain Relationships and Related Person Transactions — Indemnification Agreements with our

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Directors and Officers.” Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors or officers, we have been informed that in the opinion of the SEC such indemnification is against public policy and is therefore unenforceable.

Registration Rights

Our Stockholders’ Agreement will provide BNAC and its affiliates with the right, in certain circumstances, to require us to register their shares of our common stock constituting registrable securities under the Securities Act for sale into the public markets and with certain piggyback rights. Our Stockholders’ Agreement will also provide that we will pay certain expenses of BNAC and its affiliates relating to such registrations and indemnify them against certain liabilities that may arise under the Securities Act. See “Certain Relationships and Related Party Transactions — Registration Rights” for a description of these registration rights.

Transfer Agent and Registrar

Upon completion of this offering, the transfer agent and registrar for our common stock will be Broadridge Corporate Issuer Solutions, Inc. The transfer agent and registrar’s address is 51 Mercedes Way, Edgewood, New York 11717.

Listing

We intend to apply for the listing of our common stock on NYSE under the symbol “BKV.”

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock, and we cannot predict the effect, if any, that market sales of shares of our common stock or the availability of shares of our common stock for sale will have on the market price of our common stock prevailing from time to time. Future sales of our common stock in the public market, or the perception that those sales may occur, could adversely affect the prevailing market price of our common stock at such time, which could make it more difficult for you to sell your shares of common stock at a time and price that you consider appropriate, and could impair our ability to raise equity capital or use our common stock as consideration for acquisitions of other businesses, investments or other corporate purposes in the future.

Sale of Restricted Securities

Immediately upon completion of this offering, there will be outstanding            shares of common stock (or          if the underwriters exercise in full their option to purchase additional shares). Of these outstanding shares,                 shares of our common stock to be sold in this offering (or                 shares if the underwriters exercise in full their option to purchase additional shares) will be freely tradable without further restriction or registration under the Securities Act. Any shares purchased in this offering by our affiliates, as that term is defined in Rule 144 under the Securities Act, may be sold in the public market only if registered or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

BNAC’s shares of common stock will be deemed “restricted securities” as defined in Rule 144 under the Securities Act. These restricted securities may be sold in the public market only if they are registered or if they qualify for an exemption from registration under Rule 144 under the Securities Act. BNAC will agree to certain lock-up restrictions with the underwriters pursuant to which it will agree, subject to specific exceptions, not to sell any of our stock for 180 days following the date of this prospectus. See “— Lock-Up Arrangements” below and “Underwriting.”

As a result of the lock-up agreements described below and the provisions of Rule 144 and Rule 701 under the Securities Act, the shares of our common stock (excluding the shares to be sold in this offering) that will be available for sale in the public market are as follows:

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no shares will be eligible for sale on the date of this prospectus or prior to 180 days after the date of this prospectus; and

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       shares will be eligible for sale upon the expiration of the lock-up agreements beginning 180 days after the date of this prospectus and when permitted under Rule 144 or Rule 701.

Lock-Up Arrangements

In connection with the completion of this offering, BNAC and all of our directors and executive officers will enter into lock-up agreements with the underwriters pursuant to which they will agree not to offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend or otherwise transfer or dispose of, directly or indirectly, any shares of common stock or any securities convertible into or exercisable or exchangeable for shares of common stock for a period of at least 180 days following the date of this prospectus, subject to certain exceptions. As a result of these contractual restrictions, shares of our common stock and the other securities subject to lock-up agreements will not be eligible for sale until these agreements expire or the restrictions are waived by the underwriters. The representatives of the underwriters may, in their discretion, release any of the securities subject to lock-up restrictions with the underwriters in whole or in part at any time. See “Underwriting.”

Shares of our common stock which were issued in satisfaction of awards granted under the 2021 Plan are subject to resale restrictions. The holder may not, without the consent of the Company or the representatives of the underwriters (for 180 days from the date of the final prospectus), (1) sell, pledge, offer to sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase or otherwise transfer or dispose of, any shares of common stock or any securities convertible into or exercisable or exchangeable for common stock, or (2) enter into any

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swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the common stock. See “Executive Compensation — BKV Corporation 2021 Long Term Incentive Plan.”

Rule 144

In general, under Rule 144 as in effect on the date of this prospectus, once we have been subject to public company reporting requirements for at least 90 days, a person who has beneficially owned shares proposed to be sold for at least six months, including the holding period of any prior owner other than an affiliate of us, and who is not deemed to have been one of our affiliates for purposes of the Securities Act at any time during the 90 days preceding a sale, will be entitled to sell, upon expiration of the lock-up agreements described above, such shares without complying with the manner of sale, volume limitation or notice provisions of Rule 144, subject to compliance with the public information requirements of Rule 144. Such a non-affiliated person who has beneficially owned the shares proposed to be sold for at least one year, including the holding period of any prior owner other than an affiliate of us, will be entitled to sell these shares without limitation.

In general, under Rule 144, our affiliates or persons selling shares on behalf of our affiliates will be entitled to sell upon expiration of the 180-day lock-up period described above, within any three-month period, a number of shares that does not exceed the greater of:

•

1% of the number of shares of our common stock then outstanding, which will equal approximately           shares immediately after this offering (or                 shares if the underwriters elect to exercise in full their option to purchase additional shares); or

•

the average weekly trading volume of our common stock on the NYSE during the four calendar weeks before a notice of the sale is filed on Form 144 with respect to such sale.

Sales by our affiliates or persons selling shares on behalf of our affiliates under Rule 144 also are subject to manner of sale and notice provisions and to the availability of public information about us.

Rule 701

In general, under Rule 701 under the Securities Act, any of our employees, directors, officers, consultants or advisors who purchases shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering is entitled to sell such shares 90 days after the effective date of this offering in reliance on Rule 144, without having to comply with the holding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144. The SEC has indicated that Rule 701 will apply to typical stock options granted by an issuer before it becomes subject to the reporting requirements of the Exchange Act, along with the shares acquired upon exercise of such options, including exercises after the date of this prospectus.

Registration Statement on Form S-8

We intend to file with the SEC a registration statement on Form S-8 under the Securities Act promptly after the completion of this offering to register shares of our common stock subject to equity-based incentive awards which were granted under the 2021 Plan, and which are reserved for future issuance under our 2022 Plan. See “Executive Compensation — BKV Corporation 2021 Long Term Incentive Plan” and “Executive Compensation — BKV Corporation 2022 Equity and Incentive Compensation Plan.” The Form S-8 will also register shares of our common stock purchased under the BKV Corporation 2020 Employee Stock Purchase Plan and shares of our common stock reserved for future purchase under our 2022 Employee Stock Purchase Plan. See “Executive Compensation — BKV Corporation Employee Stock Purchase Plan.” The registration statement on Form S-8 is expected to become effective immediately upon filing, and shares of our common stock covered by the registration statement will then become eligible for sale in the public market, subject to the Rule 144 limitations applicable to affiliates and vesting restrictions. See “Executive Compensation — BKV Corporation 2021 Long Term Incentive Plan,” “Executive Compensation — BKV Corporation 2022 Equity and Incentive Compensation Plan” and “Executive Compensation — BKV Corporation Employee Stock Purchase Plan.”

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Registration Rights

Our Stockholders’ Agreement will provide BNAC and its affiliates with the right, in certain circumstances, to require us to register their shares of our common stock constituting registrable securities under the Securities Act for sale into the public markets at any time following the date that is six months after the consummation of this offering. BNAC and its affiliates will also be entitled to certain piggyback rights with respect to future registrations or underwritten shelf takedowns, subject to certain limitations. “Certain Relationships and Related Party Transactions — Registration Rights” contains additional information regarding such rights.

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CERTAIN ERISA CONSIDERATIONS

The following is a summary of certain considerations associated with the acquisition and holding of shares of our common stock by employee benefit plans that are subject to Title I of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), plans, individual retirement accounts and other arrangements that are subject to Section 4975 of the Code or employee benefit plans that are governmental plans (as defined in Section 3(32) of ERISA), certain church plans (as defined in Section 3(33) of ERISA), non-U.S. plans (as described in Section 4(b)(4) of ERISA) or other plans that are not subject to the foregoing but may be subject to provisions under any other federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of ERISA or the Code (collectively, “Similar Laws”), and entities whose underlying assets are considered to include “plan assets” of any such plan, account or arrangement (each, a “Plan”).

This summary is based on the provisions of ERISA and the Code (and related regulations and administrative and judicial interpretations) as of the date of this registration statement. This summary does not purport to be complete, and no assurance can be given that future legislation, court decisions, regulations, rulings or pronouncements will not significantly modify the requirements summarized below. Any of these changes may be retroactive and may thereby apply to transactions entered into prior to the date of their enactment or release. This discussion is general in nature and is not intended to be all inclusive, nor should it be construed as investment or legal advice.

General Fiduciary Matters

ERISA and the Code impose certain duties on persons who are fiduciaries of a Plan subject to Title I of ERISA or Section 4975 of the Code (an “ERISA Plan”) and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Code, any person who exercises any discretionary authority or control over the administration of an ERISA Plan or the management or disposition of the assets of an ERISA Plan, or who renders investment advice for a fee or other compensation to an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan.

In considering an investment in shares of our common stock with a portion of the assets of any Plan, a fiduciary should consider the Plan’s particular circumstances and all of the facts and circumstances of the investment and determine whether the acquisition and holding of shares of our common stock is in accordance with the documents and instruments governing the Plan and the applicable provisions of ERISA, the Code, or any Similar Law relating to the fiduciary’s duties to the Plan, including, without limitation:

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

•

whether, in making the investment, the ERISA Plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

•

whether the investment is permitted under the terms of the applicable documents governing the Plan;

•

whether in the future there may be no market in which to sell or otherwise dispose of the shares of our common stock;

•

whether the acquisition or holding of the shares of our common stock will constitute a “prohibited transaction” under Section 406 of ERISA or Section 4975 of the Code (see discussion under “— Prohibited Transaction Issues”); and

•

whether the Plan will be considered to hold, as plan assets, (i) only shares of our common stock or (ii) an undivided interest in our underlying assets (see the discussion under “— Plan Asset Issues”).

Prohibited Transaction Issues

Section 406 of ERISA and Section 4975 of the Code prohibit ERISA Plans from engaging in specified transactions involving plan assets with persons or entities who are “parties in interest,” within the meaning of ERISA, or “disqualified persons,” within the meaning of Section 4975 of the Code, unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction

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may be subject to excise taxes and other penalties and liabilities under ERISA and the Code. In addition, the fiduciary of the ERISA Plan that engages in such a non-exempt prohibited transaction may be subject to excise taxes, penalties and liabilities under ERISA and the Code. The acquisition and/or holding of shares of our common stock by an ERISA Plan with respect to which the issuer, the initial purchaser, or a guarantor is considered a party in interest or a disqualified person may constitute or result in a direct or indirect prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code, unless the investment is acquired and is held in accordance with an applicable statutory, class or individual prohibited transaction exemption.

Because of the foregoing, shares of our common stock should not be acquired or held by any person investing “plan assets” of any Plan, unless such acquisition and holding will not constitute a non-exempt prohibited transaction under ERISA and the Code or a similar violation of any applicable Similar Laws.

Plan Asset Issues

Additionally, a fiduciary of a Plan should consider whether the Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that we would become a fiduciary of the Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code and any other applicable Similar Laws.

The Department of Labor (the “DOL”) regulations provide guidance with respect to whether the assets of an entity in which ERISA Plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets generally would not be considered to be “plan assets” if, among other things:

(a)

the equity interests acquired by ERISA Plans are “publicly offered securities” ​(as defined in the DOL regulations) — i.e., the equity interests are part of a class of securities that is widely held by 100 or more investors independent of the issuer and each other, are freely transferable, and are either registered under certain provisions of the federal securities laws or sold to the ERISA Plan as part of a public offering under certain conditions;

(b)

the entity is an “operating company” ​(as defined in the DOL regulations) — i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

(c)

there is no significant investment by “benefit plan investors” ​(as defined in the DOL regulations) — i.e., immediately after the most recent acquisition by an ERISA Plan of any equity interest in the entity, less than 25% of the total value of each class of equity interest (disregarding certain interests held by persons (other than benefit plan investors) with discretionary authority or control over the assets of the entity or who provide investment advice for a fee (direct or indirect) with respect to such assets, and any affiliates thereof) is held by ERISA Plans, individual retirement accounts and certain other Plans (but not including governmental plans, foreign plans and certain church plans), and entities whose underlying assets are deemed to include plan assets by reason of a Plan’s investment in the entity.

Due to the complexity of these rules and the excise taxes, penalties and liabilities that may be imposed upon persons involved in non-exempt prohibited transactions, it is particularly important that fiduciaries, or other persons considering acquiring and/or holding shares of our common stock on behalf of, or with the assets of, any Plan, consult with their counsel regarding the potential applicability of ERISA, Section 4975 of the Code and any Similar Laws to such investment and whether an exemption would be applicable to the acquisition and holding of shares of our common stock. Purchasers of shares of our common stock have the exclusive responsibility for ensuring that their acquisition and holding of shares of our common stock complies with the fiduciary responsibility rules of ERISA and does not violate the prohibited transaction rules of ERISA, the Code or applicable Similar Laws. The sale of shares of our common stock to a Plan is in no respect a representation by us or any of our affiliates or representatives that such an investment meets all relevant legal requirements with respect to investments by any such Plan or that such investment is appropriate for any such Plan.

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES
TO NON-U.S. HOLDERS OF OUR COMMON STOCK

The following is a general discussion of material U.S. federal income tax consequences to non-U.S. holders (as defined herein) with respect to the ownership and disposition of our common stock. This discussion applies only to non-U.S. holders that acquire our common stock in this offering and hold such stock as a capital asset within the meaning of Section 1221 of the Code (generally, property held for investment purposes). This discussion is based on current provisions of the Code, U.S. Treasury regulations promulgated under the Code, and administrative rulings and court decisions in effect as of the date of this prospectus, all of which are subject to change at any time, possibly with retroactive effect. We have not sought and will not seek any rulings from the IRS regarding the matters discussed below.

For purposes of this discussion, the term “non-U.S. holder” means a beneficial owner of our common stock that is not, for U.S. federal income tax purposes, an entity or arrangement treated as a partnership or any of the following:

•

a citizen or individual resident of the United States;

•

a corporation, or other entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

•

an estate the income of which is subject to U.S. federal income tax regardless of its source; or

•

a trust (1) if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more “United States persons” ​(as defined in Section 7701(a)(30) of the Code) has or have the authority to control all substantial decisions of the trust, or (2) that has a valid election in effect under applicable U.S. Treasury regulations to be treated as a “United States person.”

This discussion is for general information only and does not address all aspects of U.S. federal income taxation that may be important to a non-U.S. holder in light of that holder’s particular circumstances or that may be applicable to holders subject to special treatment under U.S. federal income tax law (including, for example, financial institutions, brokers or dealers in securities, traders in securities that elect mark-to-market treatment, insurance companies, controlled foreign corporations, passive investment companies, holders who acquire our common stock pursuant to the exercise of employee stock options or otherwise as compensation, entities or arrangements treated as partnerships for U.S. federal income tax purposes (and partners or beneficial owners therein), holders liable for the alternative minimum tax, certain former citizens or former long-term residents of the U.S., persons who hold or are deemed to hold our common stock as part of a hedge, straddle, constructive sale, conversion transaction or other risk-reduction transaction, persons required for U.S. federal income tax purposes to conform the timing of income accruals with respect to the common stock to their financial statements under Section 451 of the Code, tax-qualified retirement plans, tax-exempt organizations, and governmental organizations, and “qualified foreign pension funds” as defined in Section 897(l)(2) of the Code and entities all of the interests of which are held by qualified foreign pension funds). In addition, this discussion does not address U.S. federal tax laws other than those pertaining to the U.S. federal income tax, nor does it address any aspects of the Medicare contribution tax on net investment income, or U.S. state or local or non-U.S. taxes. This discussion also does not specifically address any tax treaties. Accordingly, prospective investors should consult their own tax advisors regarding the U.S. federal, state, local, and non-U.S. income and other tax considerations of acquiring, holding and disposing of shares of our common stock.

If a partnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership generally will depend upon the status of the partner, the activities of the partnership and certain determinations made at the partner level. Accordingly, we urge partners in partnerships (including entities or arrangements treated as partnerships for U.S. federal income tax purposes) considering the purchase of our common stock to consult their tax advisors regarding the U.S. federal income tax considerations of the ownership and disposition of our common stock by such partnership.

THIS SUMMARY IS FOR GENERAL INFORMATION ONLY. IT IS NOT TAX ADVICE. INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON STOCK ARE URGED TO

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CONSULT THEIR TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL, STATE, LOCAL AND NON-U.S. INCOME AND OTHER TAX LAWS AND ANY APPLICABLE TAX TREATIES TO THEIR PARTICULAR SITUATIONS.

Distributions on Common Stock

At or prior to the closing of this offering, our board of directors will adopt a policy pursuant to which we intend to pay dividends to stockholders.

In general, any distributions we make to a non-U.S. holder with respect to shares of our common stock that constitute dividends for U.S. federal income tax purposes will be subject to U.S. withholding tax at a rate of 30% (or such lower rate as may be specified by an applicable income tax treaty) of the gross amount distributed, unless the dividends are effectively connected with a trade or business carried on by the non-U.S. holder within the United States and, if required by an applicable income tax treaty, are attributable to a permanent establishment of the non-U.S. holder within the United States. A distribution will constitute a dividend for U.S. federal income tax purposes to the extent of our current or accumulated earnings and profits as determined for U.S. federal income tax purposes. Any distribution not constituting a dividend will be treated as first reducing the adjusted basis in the non-U.S. holder’s shares of our common stock, but not below zero, and, to the extent it exceeds the adjusted basis in the non-U.S. holder’s shares of our common stock, as capital gain and will be treated as described below under “— Sale, Exchange or Other Taxable Disposition of Common Stock.” However, except to the extent that we elect (or the paying agent or other intermediary through which you hold your shares of common stock elects) to withhold with respect to the taxable portion of the distribution only, we (or the applicable paying agent or intermediary) must generally withhold on the entire distribution, in which case you generally would be entitled to a refund from the IRS by timely filing an appropriate claim for a refund, to the extent the withholding exceeds your tax liability with respect to the distribution.

A non-U.S. holder who wishes to claim the benefit of an applicable treaty rate on dividends will be required (a) to provide the applicable withholding agent with a properly executed IRS Form W-8BEN or W-8BEN-E (or other applicable form) certifying under penalties of perjury that such holder is not a U.S. person as defined under the Code and is eligible for treaty benefits or (b) if our common stock is held through certain foreign intermediaries, to satisfy the relevant certification requirements of applicable U.S. Treasury regulations. A non-U.S. holder that does not timely furnish the required documentation, but that is eligible for a lower rate of U.S. federal withholding tax pursuant to an income tax treaty, may obtain a refund or credit of any excess amounts withheld by filing an appropriate claim for a refund with the IRS. Non-U.S. holders are urged to consult their own tax advisors regarding their possible entitlement to benefits under an applicable income tax treaty.

Dividends effectively connected with a non-U.S. holder’s conduct of a U.S. trade or business (and, if required by an applicable income tax treaty, attributable to such non-U.S. holder’s U.S. permanent establishment) generally will not be subject to U.S. withholding tax if the non-U.S. holder complies with applicable certification requirements. More particularly, to claim this exemption from U.S. withholding tax, the non-U.S. holder must furnish to the applicable withholding agent a valid IRS Form W-8ECI, certifying that the dividends are effectively connected with the non-U.S. holder’s conduct of a trade or business within the United States. Such effectively connected dividends, although not subject to withholding tax (provided the IRS Form W-8ECI certification requirements are satisfied), generally will be subject to U.S. federal income tax on a net income basis, at the regular graduated rates applicable to U.S. persons. A non-U.S. holder that is a corporation may be subject to an additional “branch profits tax” at a rate of 30% (or such lower rate as may be specified by an applicable income tax treaty) on its “effectively connected earnings and profits,” subject to certain adjustments.

The foregoing is subject to the discussion below under “— Information Reporting and Backup Withholding” and “— Foreign Account Tax Compliance Act.”

Sale, Exchange or Other Taxable Disposition of Common Stock

Subject to the discussion below under “— Information Reporting and Backup Withholding” and “— Foreign Account Tax Compliance Act,” a non-U.S. holder will generally not be subject to U.S. federal

232

income or withholding tax with respect to gain recognized on the sale, exchange or other taxable disposition of our common stock unless:

•

the gain is effectively connected with a trade or business carried on by the non-U.S. holder within the United States and, if required by an applicable income tax treaty, is attributable to a U.S. permanent establishment of such non-U.S. holder,

•

the non-U.S. holder is a nonresident alien individual and is present in the United States for 183 days or more in the taxable year of the sale, exchange or other taxable disposition and certain other conditions are satisfied, or

•

we are or have been a “United States real property holding corporation” ​(“USRPHC”) for U.S. federal income tax purposes at any time within the shorter of the five-year period ending on the date of the disposition of the common stock and the non-U.S. holder’s holding period, and certain other conditions are satisfied.

Gain described in the first bullet point above (i.e., gain that is effectively connected with the conduct of a trade or business in the United States) generally will be subject to U.S. federal income tax, net of certain deductions, at the regular graduated rates applicable to U.S. persons. If the non-U.S. holder is a foreign corporation, the branch profits tax at a rate of 30% (or such lower rate as may be specified by an applicable income tax treaty) also may apply to such effectively connected gain.

A non-U.S. holder described in the second bullet point above (i.e., who is subject to U.S. federal income tax because the non-U.S. holder was present in the United States for 183 days or more during the taxable year of the sale, exchange or other taxable disposition of our common stock) will be subject to U.S. federal income tax at a rate of 30% (or such lower rate as may be specified under an applicable income tax treaty) on the gain derived from such sale, exchange or other taxable disposition, which may be offset by U.S. source capital losses, provided the non-U.S. holder has timely filed U.S. federal income tax returns with respect to such losses.

With respect to the third bullet point above, we are currently, and expect to continue to be for the foreseeable future, a USRPHC (and the remainder of this discussion assumes we are and will be a USRPHC). However, if our common stock is “regularly traded on an established securities market” ​(as defined by the U.S. Treasury regulations), a non-U.S. holder will be taxed on gain recognized on the disposition of our common stock as a result of our status as a USRPHC only if the non-U.S. holder actually or constructively holds or held more than 5% of our common stock at any time during the five-year period ending on the date of disposition or, if shorter, during the entire period the non-U.S. holder has held our common stock. If our common stock were not considered to be regularly traded on an established securities market, all non-U.S. holders would be subject to U.S. federal income tax on the sale, exchange or other taxable disposition of our common stock and a 15% withholding tax would apply to the gross proceeds from such sale, exchange or other taxable disposition of our common stock by a non-U.S. holder. Such withholding tax is not an additional tax but, rather, is credited against the actual U.S. federal income taxes owed by the non-U.S. holder (and such non-U.S. holder may obtain a refund of any amounts so withheld which exceed the non-U.S. holder’s actual U.S. federal income tax liability, if any, provided that the non-U.S. holder makes the necessary filings with the IRS in a timely manner).

Information Reporting and Backup Withholding

We (or the applicable paying agent or intermediary) must report annually to the IRS and to each non-U.S. holder the amount of distributions paid to, and the tax withheld (if any) with respect to, each non-U.S. holder of our common stock. These reporting requirements apply regardless of whether withholding was reduced or eliminated by an applicable tax treaty. Copies of this information also may be made available under the provisions of a specific treaty or agreement with the tax authorities in the country in which the non-U.S. holder resides or is established.

U.S. backup withholding tax, at a rate that is currently 24%, is imposed on certain payments to persons that fail to furnish the information required under the U.S. information reporting rules. Dividends paid to a non-U.S. holder generally will be exempt from backup withholding if the non-U.S. holder provides a properly executed applicable IRS Form W-8, or otherwise establishes an exemption.

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Under U.S. Treasury regulations, the payment of proceeds from the disposition of our common stock by a non-U.S. holder effected at a U.S. office of any broker (U.S. or non-U.S.), generally will be subject to information reporting and backup withholding, unless the beneficial owner certifies its status as a non-U.S. holder (generally by providing a properly executed applicable IRS Form W-8), or otherwise establishes an exemption. The payment of proceeds from the disposition of our common stock by a non-U.S. holder effected at a non-U.S. office of a broker that is neither a U.S. person nor a person having certain relationships with the United States generally will not be subject to backup withholding or information reporting. However, the payment of proceeds from a disposition of our common stock by a non-U.S. holder effected at a non-U.S. office of a broker that is a U.S. person or has certain relationships with the United States will generally be subject to information reporting, unless the beneficial owner certifies its status as a non-U.S. holder (generally by providing a properly executed applicable IRS Form W-8), or the broker has other documentary evidence in its files that the beneficial owner is a non-U.S. holder and certain other conditions are satisfied, or the beneficial owner otherwise establishes an exemption (and the broker has no knowledge or reason to know to the contrary). If the payment described in the preceding sentence is subject to information reporting, it will be subject to backup withholding if the broker has actual knowledge or reason to know that the payee is a U.S. person.

Backup withholding is not an additional tax but, rather, is credited against the actual U.S. federal income taxes owed by the non-U.S. holder. A non-U.S. holder may obtain a refund of any amounts withheld under the backup withholding rules which exceed the non-U.S. holder’s actual U.S. federal income tax liability, if any, provided that the non-U.S. holder makes the necessary filings with the IRS in a timely manner.

Foreign Account Tax Compliance Act

Under Sections 1471 through 1474 of the Code and the U.S. Treasury regulations promulgated thereunder (collectively, “FATCA”), a U.S. federal withholding tax of 30% generally will be imposed on certain payments made to a “foreign financial institution” ​(as specifically defined under these rules) unless such institution enters into an agreement with the U.S. tax authorities to withhold on certain payments and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution or meets other exceptions. Under FATCA and administrative guidance, a U.S. federal withholding tax of 30% generally also will be imposed on certain payments made to a “non-financial foreign entity” ​(as specifically defined under these rules) unless such entity provides the withholding agent with a certification identifying its direct and indirect U.S. owners or meets other exceptions. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the U.S. governing these withholding and reporting requirements may be subject to different rules.

These withholding taxes would be imposed on dividends with respect to our common stock to foreign financial institutions or non-financial foreign entities (including in their capacity as agents or custodians for beneficial owners of our common stock) that fail to satisfy the above requirements. Prior to the issuance of proposed U.S. Treasury regulations, withholding taxes under FATCA also would have applied to gross proceeds from the disposition of our common stock. However, the proposed U.S. Treasury regulations provide that such gross proceeds are generally not subject to withholding taxes under FATCA. Taxpayers (including withholding agents) may currently rely on these proposed U.S. Treasury regulations until they are revoked or final U.S. Treasury regulations are issued.

Under certain circumstances, a non-U.S. holder might be eligible for refunds or credits of such taxes. Prospective non-U.S. holders should consult their tax advisors regarding the possible implications of FATCA on their investment in our common stock.

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement dated as of the date of this prospectus (the “Underwriting Agreement”), we have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC, BofA Securities, Inc. and Barclays Capital Inc. are acting as representatives, the following respective numbers of shares of common stock:

Underwriter	Number of Shares
Credit Suisse Securities (USA) LLC	​	​
BofA Securities, Inc.	​	​
Barclays Capital Inc.	​
Total	​

The Underwriting Agreement provides that the underwriters are obligated to purchase all the shares of common stock in the offering if any are purchased, other than those shares covered by the over-allotment option described below. The Underwriting Agreement also provides that if an underwriter defaults the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated.

We have agreed to indemnify the underwriters and certain of their controlling persons against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make in respect of those liabilities.

We have granted to the underwriters a 30-day option to purchase on a pro rata basis up to        additional shares at the initial public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common stock.

The underwriters propose to offer the shares of common stock initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of up to $      per share. After the initial public offering the underwriters may change the public offering price and concession.

The following table summarizes the underwriting discounts and commissions payable by us to the underwriters in connection with this offering, assuming both no exercise and full exercise of the underwriters’ over-allotment option.

​

Per Share

Total

​

Without Over-allotment

With Over-allotment

Without Over-allotment

With Over-allotment

Underwriting discounts and commissions payable by us

​

$

​

$

​

$

​

$

The expenses of this offering that have been paid or are payable by us are estimated to be approximately $      million (excluding underwriting discounts and commissions). We have also agreed to reimburse the underwriters for certain of their expenses incurred in connection with this offering in an amount up to $      .

We have agreed that, subject to certain exceptions, we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the SEC a registration statement under the Securities Act relating to, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of the representatives for a period of 180 days after the date of this prospectus.

The representatives of the underwriters may, in their discretion, release the shares of our common stock or other securities subject to the lock-up agreements described above in whole or in part at any time.

Our officers and directors and certain of our stockholders have agreed that they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any shares of our common stock or

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securities convertible into or exchangeable or exercisable for any shares of our common stock, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common stock, whether any of these transactions are to be settled by delivery of our common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any such offer, sale, pledge or disposition, or to enter into any such transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of the representatives for a period of 180 days after the date of this prospectus, subject to certain exceptions.

We have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.

We intend to apply to list the shares of common stock on the NYSE.

In connection with the listing of the common stock on the NYSE, the underwriters will undertake to sell round lots of 100 shares or more to a minimum of 400 beneficial owners.

Prior to this offering, there has been no public market for our common stock. The initial public offering price was determined by negotiations among us and the representatives and will not necessarily reflect the market price of the common stock following this offering. The principal factors that were considered in determining the initial public offering price included:

•

the information presented in this prospectus and otherwise available to the underwriters;

•

the history of, and prospects for, the industry in which we will compete;

•

the ability of our management;

•

the prospects for our future earnings;

•

the present state of our development, results of operations and our current financial condition;

•

the general condition of the securities markets at the time of this offering; and

•

the recent market prices of, and the demand for, publicly traded common stock of generally comparable companies.

We cannot assure you that the initial public offering price will correspond to the price at which the common stock will trade in the public market subsequent to this offering or that an active trading market for the common stock will develop and continue after this offering.

In connection with the offering the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Exchange Act.

•

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

•

Over-allotment involves sales by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares that they may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing shares in the open market.

•

Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the

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underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

•

Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing transaction or a syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result, the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NYSE or otherwise and, if commenced, may be discontinued at any time.

The underwriters and certain of their affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. The underwriters and certain of their affiliates have, from time to time, performed, and may in the future perform, various commercial and investment banking and financial advisory services for the issuer and its affiliates, for which they received, or may in the future receive, customary fees and expenses.

In the ordinary course of their various business activities, the underwriters and certain of their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of the issuer or its affiliates. If the underwriters or their affiliates have a lending relationship with us, certain of those underwriters or their affiliates may hedge their credit exposure to us consistent with their customary risk management policies. Typically, the underwriters and their affiliates would hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities or the securities of our affiliates, including potentially the shares of common stock offered hereby. Any such credit default swaps or short positions could adversely affect future trading prices of the shares of common stock offered hereby. The underwriters and certain of their affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

A prospectus in electronic format will be made available on the web sites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representatives may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make internet distributions on the same basis as other allocations.

Notice to Prospective Investors in Canada

The common stock may be sold only to purchasers purchasing, or deemed to be purchasing, as principal that are accredited investors, as defined in National Instrument 45-106 Prospectus Exemptions or subsection 73.3(1) of the Securities Act (Ontario), and are permitted clients, as defined in National Instrument 31-103 Registration Requirements, Exemptions and Ongoing Registrant Obligations. Any resale of the common stock must be made in accordance with an exemption from, or in a transaction not subject to, the prospectus requirements of applicable securities laws.

Securities legislation in certain provinces or territories of Canada may provide a purchaser with remedies for rescission or damages if this prospectus (including any amendment thereto) contains a misrepresentation, provided that the remedies for rescission or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser’s province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser’s province or territory for particulars of these rights or consult with a legal advisor.

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Pursuant to section 3A.3 (or, in the case of securities issued or guaranteed by the government of a non-Canadian jurisdiction, section 3A.4) of National Instrument 33-105 Underwriting Conflicts, or NI 33-105, the underwriter is not required to comply with the disclosure requirements of NI 33-105 regarding underwriter conflicts of interest in connection with this offering.

Notice to Prospective Investors in the European Economic Area

In relation to each Member State of the European Economic Area (each an “EEA State”), no common stock has been offered or will be offered pursuant to the offering to the public in that EEA State prior to the publication of a prospectus in relation to the common stock which has been approved by the competent authority in that EEA State or, where appropriate, approved in another EEA State and notified to the competent authority in that EEA State, all in accordance with the EU Prospectus Regulation, except that it may make an offer to the public in that EEA State of any shares of common stock at any time under the following exemptions under the EU Prospectus Regulation:

•

to any legal entity which is a qualified investor as defined under the EU Prospectus Regulation;

•

to fewer than 150 natural or legal persons (other than qualified investors as defined under the EU Prospectus Regulation), subject to obtaining the prior consent of Credit Suisse Securities (USA) LLC for any such offer; or

•

in any other circumstances falling within Article 1(4) of the EU Prospectus Regulation,

provided that no such offer of the common stock shall require the Issuer or any underwriter to publish a prospectus pursuant to Article 3 of the EU Prospectus Regulation or supplement a prospectus pursuant to Article 23 of the EU Prospectus Regulation.

For the purposes of this provision, the expression an “offer to the public” in relation to the common stock in any EEA State means the communication in any form and by any means of sufficient information on the terms of the offer and any shares of common stock to be offered so as to enable an investor to decide to purchase or subscribe for any shares of common stock, and the expression “EU Prospectus Regulation” means Regulation (EU) 2017/1129.

Notice to Prospective Investors in the United Kingdom

In relation to the United Kingdom, no shares of common stock have been offered or will be offered pursuant to the offering to the public in the United Kingdom prior to the publication of a prospectus in relation to the common stock which has been approved by the Financial Conduct Authority in accordance with the transitional provision in Regulation 74 of the Prospectus (Amendment etc.) (EU Exit) Regulations 2019, except that it may make an offer to the public in the United Kingdom of any shares of common stock at any time under the following exemptions under the UK Prospectus Regulation:

•

to any legal entity which is a qualified investor as defined under the UK Prospectus Regulation;

•

to fewer than 150 natural or legal persons (other than qualified investors as defined under the UK Prospectus Regulation), subject to obtaining the prior consent of the representatives for any such offer; or

•

in any other circumstances falling within Section 86 of the Financial Services and Markets Act 2000 (the “FSMA”),

provided that no such offer of the common stock shall require the Issuer or any underwriter to publish a prospectus pursuant to Section 85 of the FSMA or supplement a prospectus pursuant to Article 23 of the UK Prospectus Regulation.

In the United Kingdom, the offering is only addressed to, and is directed only at, “qualified investors” within the meaning of Article 2(e) of the UK Prospectus Regulation, who are also (i) persons having professional experience in matters relating to investments who fall within the definition of “investment professionals” in Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”); (ii) high net worth bodies corporate, unincorporated associations and partnerships and trustees of high value trusts as described in Article 49(2) of the Order; or (iii) persons to whom it may

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otherwise lawfully be communicated (all such persons being referred to as “relevant persons”). This document must not be acted on or relied on by persons who are not relevant persons. Any investment or investment activity to which this document relates is available only to relevant persons and will be engaged in only with relevant persons.

For the purposes of this provision, the expression an “offer to the public” in relation to the common stock in the United Kingdom means the communication in any form and by any means of sufficient information on the terms of the offering and any shares of common stock to be offered so as to enable an investor to decide to purchase or subscribe for any shares of common stock, and the expression “UK Prospectus Regulation” means the UK version of Regulation (EU) No 2017/1129 as amended by The Prospectus (Amendment etc.) (EU Exit) Regulations 2019, which is part of UK law by virtue of the European Union (Withdrawal) Act 2018.

Notice to Prospective Investors in the Dubai International Financial Centre

This prospectus relates to an Exempt Offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority (the “DFSA”). This prospectus is intended for distribution only to persons of a type specified in the Offered Securities Rules of the DFSA. It must not be delivered to, or relied on by, any other person. The DFSA has no responsibility for reviewing or verifying any documents in connection with Exempt Offers. The DFSA has not approved this prospectus nor taken steps to verify the information set forth herein and has no responsibility for the prospectus. The securities to which this prospectus relates may be illiquid and/or subject to restrictions on their resale. Prospective purchasers of the securities offered should conduct their own due diligence on the securities. If you do not understand the contents of this prospectus you should consult an authorized financial advisor.

Notice to Prospective Investors in Australia

No placement document, prospectus, product disclosure statement or other disclosure document has been lodged with the Australian Securities and Investments Commission, in relation to the offering. This prospectus does not constitute a prospectus, product disclosure statement or other disclosure document under the Corporations Act 2001 (the “Corporations Act”), and does not purport to include the information required for a prospectus, product disclosure statement or other disclosure document under the Corporations Act.

Any offer in Australia of the securities may only be made to persons (the “Exempt Investors”) who are “sophisticated investors” ​(within the meaning of section 708(8) of the Corporations Act), “professional investors” ​(within the meaning of section 708(11) of the Corporations Act) or otherwise pursuant to one or more exemptions contained in section 708 of the Corporations Act so that it is lawful to offer the securities without disclosure to investors under Chapter 6D of the Corporations Act.

The securities applied for by Exempt Investors in Australia must not be offered for sale in Australia in the period of 12 months after the date of allotment under the offering, except in circumstances where disclosure to investors under Chapter 6D of the Corporations Act would not be required pursuant to an exemption under section 708 of the Corporations Act or otherwise or where the offer is pursuant to a disclosure document which complies with Chapter 6D of the Corporations Act. Any person acquiring securities must observe such Australian on-sale restrictions. This prospectus contains general information only and does not take account of the investment objectives, financial situation or particular needs of any particular person. It does not contain any securities recommendations or financial product advice. Before making an investment decision, investors need to consider whether the information in this prospectus is appropriate to their needs, objectives and circumstances, and, if necessary, seek expert advice on those matters.

Notice to Prospective Investors in Switzerland

The common stock may not be publicly offered, directly or indirectly, in Switzerland within the meaning of the Swiss Financial Services Act (the “FinSA”) and no application has or will be made to admit the common stock to trading on any trading venue (exchange or multilateral trading facility) in Switzerland. Neither this prospectus nor any other offering or marketing material relating to the common stock constitutes

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a prospectus pursuant to the FinSA, and neither this prospectus nor any other offering or marketing material relating to the common stock may be publicly distributed or otherwise made publicly available in Switzerland.

Notice to Prospective Investors in Hong Kong

The common stock may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong) and no advertisement, invitation or document relating to the common stock may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to common stock which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

Notice to Prospective Investors in Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the common stock may not be circulated or distributed, nor may the common stock be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”), (ii) to a relevant person pursuant to Section 275(1), or any person pursuant to Section 275(1A), and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to compliance with conditions set forth in the SFA.

Solely for the purposes of its obligations pursuant to sections 309B(1)(a) and 309B(1)(c) of the SFA and the Securities and Futures (Capital Markets Products) Regulations 2018 of Singapore (the “CMP Regulations 2018”), the Issuer has determined, and hereby notifies all relevant persons (as defined in Section 309A of the SFA) that the shares of common stock are (A) prescribed capital markets products (as defined in the CMP Regulations 2018) and (B) Excluded Investment Products (as defined in MAS Notice SFA 04-N12: Notice on the Sale of Investment Products and MAS Notice FAA-N16: Notice on Recommendations on Investment Products).

Notice to Prospective Investors in Thailand

This prospectus does not, and is not intended to, constitute a public offering in Thailand. The common stock may not be offered or sold to persons in Thailand, unless such offering is made under the exemptions from approval and filing requirements under applicable laws, or under circumstances which do not constitute an offer for sale of the common stock to the public for the purposes of the Securities and Exchange Act of 1992 of Thailand, nor require approval from the Office of the Securities and Exchange Commission of Thailand.

Where the shares of common stock are subscribed or purchased under Section 275 of the SFA by a relevant person which is:

•

a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or

•

a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor,

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shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust will not be transferred within six months after that corporation or that trust has acquired the shares pursuant to an offer made under Section 275 of the SFA except:

•

to an institutional investor (for corporations, under Section 274 of the SFA) or to a relevant person defined in Section 275(2) of the SFA, or to any person pursuant to an offer that is made on terms that such shares, debentures and units of shares and debentures of that corporation or such rights and interest in that trust are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets, and further for corporations, in accordance with the conditions specified in Section 275 of the SFA;

•

where no consideration is or will be given for the transfer; or

•

where the transfer is by operation of law.

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LEGAL MATTERS

The validity of the common stock offered hereby and certain other legal matters in connection with this offering will be passed upon for us by Baker Botts L.L.P., Dallas, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas. Baker Botts L.L.P. has from time to time represented and may continue to represent BKV and some of its affiliates in connection with various legal matters.

EXPERTS

The consolidated financial statements of BKV Corporation as of December 31, 2021 and 2020 and for each of the two years in the period ended December 31, 2021 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP (“PwC”), an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

In connection with this registration statement, PwC completed an independence assessment to evaluate the services and relationships with the Company and its affiliates that may bear on PwC’s independence under the SEC and the PCAOB independence rules for an audit period commencing January 1, 2020. PwC informed the Company’s Audit & Risks Committee that one of its member firms within PricewaterhouseCoopers International Limited, each member firm of which is a separate legal entity (a “PwC member firm”), provided non-audit services during the audit period to two sister entities under common control with BKV Corporation. The services that occurred from January 2020 to June 2021, which are inconsistent with the SEC and PCAOB independence rules, involved the provision of corporate secretarial services and the disbursement of incidental payments on behalf of client management. The fees for these services totaled approximately $8,500 and $10,000, respectively, for the years ended December 31, 2021 and 2020. The provision of corporate secretarial services and the incidental payments made on behalf of client management are in contravention of SEC Rule 2-01(c)(4)(vi) of Regulation S-X.

PwC informed the Company’s Audit & Risks Committee of the facts and circumstances surrounding the impermissible services, noting that (i) the PwC member firm did not make any decisions or judgments on management’s behalf, and management reviewed and approved all documentation prepared by the PwC member firm, (ii) no aspect of the financial results of the sister entities or the provision of the services is included in (or has any impact on) the financial results of the Company, (iii) the services were performed by persons who were not part of the PwC audit engagement team, and (iv) the fees for the services were not material to the Company, the sister entities, the PwC member firm, or PwC. Additionally, the services do not create a mutual or conflicting interest between PwC and the Company, do not place PwC in a position of auditing its own work, and do not place PwC in a position of being an advocate for the Company.

After considering the facts and circumstances, the Company’s Audit & Risks Committee concurred with PwC’s conclusion that, for the reasons described above, the impermissible services did not impair PwC’s objectivity and impartiality with respect to the planning and execution of the audits of the Company’s consolidated financial statements as of December 31, 2021 and 2020 and for each of the two years in the period ended December 31, 2021, and that no reasonable investor would conclude otherwise.

The statements of revenues and direct operating expenses of the Barnett Assets of XTO Energy Inc. and Barnett Gathering, LLC for the years ended December 31, 2021 and 2020 included in this prospectus have been so included in reliance on the report (which contained an explanatory paragraph relating to the basis of presentation of the statements of revenues and direct operating expenses as described in Note 1 to the financial statements) of PricewaterhouseCoopers LLP, independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

Estimates of our natural gas reserves, related future net cash flows and the present values thereof related to our properties as of September 30, 2022 and December 31, 2021 and 2020 included elsewhere in this prospectus were based upon reserve reports prepared by independent petroleum engineers Ryder Scott Company, L.P. We have included these estimates in reliance on the authority of such firms as experts in such matters.

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WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act with respect to the shares of common stock offered by this prospectus. This prospectus, which constitutes a part of the registration statement, does not contain all of the information set forth in the registration statement, some of which is contained in exhibits to the registration statement as permitted by the rules and regulations of the SEC. For further information with respect to us and our common stock, we refer you to the registration statement, including the exhibits filed as part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other document are not necessarily complete, and each such statement is qualified in all respects by reference to the full text of such contract or other document filed as an exhibit to the registration statement.

The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at www.sec.gov. Our filings with the SEC, including the registration statement, are available to you for free on the SEC’s internet website.

Upon completion of this offering, we will become subject to the informational and reporting requirements of the Exchange Act and, in accordance with those requirements, will file reports and proxy and information statements with the SEC. We intend to furnish to our stockholders our annual reports containing audited consolidated financial statements and the notes thereto certified by an independent public accounting firm.

We also maintain an internet website at www.bkvcorp.com. Information on or accessible through our website is not part of this prospectus.

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INDEX TO FINANCIAL STATEMENTS

BKV CORPORATION

Audited Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2021 and 2020	F-3
Consolidated Statements of Operations and Comprehensive Loss for the Years Ended December 31, 2021 and 2020	F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2021 and 2020	F-6
Consolidated Statements of Stockholders’ Equity, Partners’ Capital and Mezzanine Equity for the Years Ended December 31, 2021 and 2020	F-8
Notes to the Consolidated Financial Statements	F-9
Unaudited Condensed Consolidated Financial Statements	​
Consolidated Balance Sheets as of a June 30, 2022 and December 31, 2021	F-53
Consolidated Statements of Operations and Comprehensive Income (Loss) for the three and six months ended June 30, 2022 and 2021	F-55
Consolidated Statements of Cash Flows for the three and six months ended June 30, 2022 and 2021	F-57
Consolidated Statements of Stockholders’ Equity and Mezzanine Equity for the three and six months ended June 30, 2022 and 2021	F-59
Notes to the Condensed Consolidated Financial Statements.	F-61
EXXONMOBIL BARNETT ASSETS	​
Report of Independent Auditors	F-82
Statements of Revenues and Direct Operating Expenses for the Years Ended December 31, 2021 and 2020 and the six months ended June 30, 2022 and 2021	F-84
Notes to the Statements of Revenues and Direct Operating Expenses.	F-85
Supplemental Oil and Gas Information (Unaudited)	F-87

F-1

 

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of BKV Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of BKV Corporation and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of operations and comprehensive loss, of stockholders’ equity, partners’ capital and mezzanine equity and of cash flows for the years then ended, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP
Denver, Colorado
August 12, 2022

We have served as the Company’s auditor since 2020.

F-2

BKV Corporation

Consolidated Balance Sheets
(In thousands, except per share amounts)

​	December 31,
​	2021			2020
Assets	​	​	​	​	​	​
Current assets	​	​	​	​	​	​
Cash and cash equivalents	​	$	134,667	​	$	17,445
Accounts receivable, net	​	​	104,143	​	​	79,454
Accounts receivable, related parties	​	​	3,498	​	​	—
Prepaid expenses	​	​	4,109	​	​	3,770
Inventory	​	​	4,975	​	​	2,878
Commodity derivative assets	​	​	9,986	​	​	15,484
Total current assets	​	​	261,378	​	​	119,031
Natural gas properties and equipment	​	​	​	​	​	​
Developed properties	​	​	1,378,629	​	​	1,297,112
Undeveloped properties	​	​	16,835	​	​	13,265
Midstream assets	​	​	55,363	​	​	55,313
Accumulated depreciation, depletion, and amortization	​	​	(274,710)	​	​	(196,393)
Total natural gas properties, net	​	​	1,176,117	​	​	1,169,297
Other property and equipment, net	​	​	22,124	​	​	23,168
Commodity derivative assets	​	​	—	​	​	15
Right of use assets	​	​	14,233	​	​	9,860
Goodwill	​	​	18,417	​	​	18,417
Investment in joint venture	​	​	89,320	​	​	—
Deferred tax asset	​	​	35,504	​	​	—
Other noncurrent assets	​	​	3,735	​	​	2,704
Total assets	​	$	1,620,828	​	$	1,342,492
Liabilities, mezzanine equity and stockholders’ equity	​	​	​	​	​	​
Current liabilities	​	​	​	​	​	​
Accounts payable and accrued liabilities	​	$	166,836	​	$	16,930
Right of use liabilities	​	​	10,713	​	​	6,534
Contingent consideration payable	​	​	65,000	​	​	—
Commodity derivative liabilities	​	​	91,156	​	​	—
Income taxes payable to related party	​	​	30,660	​	​	1,217
Notes payable to related party	​	​	166,000	​	​	24,000
Total current liabilities	​	​	530,365	​	​	48,681
Asset retirement obligations	​	​	158,968	​	​	148,826
Contingent consideration	​	​	142,533	​	​	12,565
Other contingent liabilities	​	​	5,669	​	​	5,329
Commodity derivative liabilities	​	​	23,662	​	​	5,170
Right of use liabilities	​	​	4,692	​	​	4,604
Deferred tax liability	​	​	—	​	​	37,249
Total liabilities	​	​	865,889	​	​	262,424

The accompanying notes are an integral part of the consolidated financial statements.

F-3

BKV Corporation

Consolidated Balance Sheets
(In thousands, except per share amounts)

​	December 31,
​	2021			2020
Commitments and contingencies (Note 15)	​	​	​	​	​	​
Mezzanine equity	​	​	​	​	​	​
Preferred stock, $10 par value; 80,000 authorized shares; 0 and 9,900 shares issued and outstanding at December 31, 2021 and 2020, respectively	​	​	—	​	​	94,924
Common stock – Minority ownership puttable shares, 4,357 authorized shares; 4,357 and 4,229 shares issued and outstanding at December 31, 2021 and 2020, respectively	​	​	49,841	​	​	42,288
Equity-based compensation	​	​	34,006	​	​	—
Total mezzanine equity	​	​	83,847	​	​	137,212
Stockholders’ equity	​	​	​	​	​	​
Common stock, $.01 par value; 300,000 authorized shares; 112,745 and 112,855 shares issued and outstanding at December 31, 2021 and 2020, respectively	​	​	1,132	​	​	1,129
Treasury stock, shares at cost; 385 and 0 shares at December 31, 2021 and 2020, respectively	​	​	(3,970)	​	​	—
Additional paid-in capital	​	​	933,622	​	​	968,500
Accumulated deficit	​	​	(259,692)	​	​	(26,773)
Total stockholders’ equity	​	​	671,092	​	​	942,856
Total liabilities, mezzanine equity and stockholders’ equity	​	$	1,620,828	​	$	1,342,492

The accompanying notes are an integral part of the consolidated financial statements.

F-4

BKV Corporation

Consolidated Statements of Operations and Comprehensive Loss
(In thousands, except per share amounts)

​	Year Ended December 31,
​	2021			2020
Revenues and other operating income	​	​	​	​	​	​
Natural gas, NGL and oil sales	​	$	829,745	​	$	115,043
Non-operated midstream revenues	​	​	6,917	​	​	7,458
Derivative (losses) gains, net	​	​	(383,847)	​	​	20,755
Marketing revenues	​	​	52,616	​	​	—
Other	​	​	251	​	​	33
Total revenues and other operating income	​	​	505,682	​	​	143,289
Operating expenses	​	​	​	​	​	​
Lease operating and workover	​	​	88,105	​	​	31,260
Taxes other than income	​	​	45,650	​	​	5,151
Gathering and transportation	​	​	173,587	​	​	—
Accretion of asset retirement obligations	​	​	10,030	​	​	3,211
Depreciation, depletion and amortization	​	​	81,986	​	​	83,388
Exploration and impairment	​	​	34	​	​	560
General and administrative	​	​	85,740	​	​	29,442
Accretion of right of use liabilities	​	​	227	​	​	184
Total operating expenses	​	​	485,359	​	​	153,196
Income (loss) from operations	​	​	20,323	​	​	(9,907)
Other income and expense	​	​	​	​	​	​
(Loss) gain on contingent consideration liabilities	​	​	(194,968)	​	​	7,135
Interest expense	​	​	(2,134)	​	​	(1,713)
Other income	​	​	872	​	​	—
Income from equity affiliates	​	​	910	​	​	—
Interest income	​	​	8	​	​	121
Loss before income taxes	​	​	(174,989)	​	​	(4,364)
Income tax benefit (expense)	​	​	40,526	​	​	(38,982)
Net loss and comprehensive loss attributable to BKV Corporation	​	​	(134,463)	​	​	(43,346)
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 loss and comprehensive loss attributable to common stockholders	​	$	(170,714)	​	$	(43,806)
Net loss and comprehensive loss per common share:	​	​	​	​	​	​
Basic and diluted	​	$	(1.46)	​	$	(0.42)
Weighted average number of common shares outstanding:	​	​	​	​	​	​
Basic and diluted	​	​	116,904	​	​	105,275

The accompanying notes are an integral part of the consolidated financial statements.

F-5

BKV Corporation

Consolidated Statements of Cash Flows
(In thousands)

​	Year Ended December 31,
​	2021			2020
Cash flows from operating activities:	​	​	​	​	​	​
Net loss	​	$	(134,463)	​	$	(43,346)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:	​	​	​	​	​	​
Depreciation, depletion and amortization	​	​	88,473	​	​	86,644
Equity-based compensation expense	​	​	30,387	​	​	—
Accretion of asset retirement obligations	​	​	10,030	​	​	3,211
Accretion of right of use liabilities	​	​	330	​	​	336
Deferred income tax (benefit) expense	​	​	(72,753)	​	​	37,750
Unrealized derivative losses (gains), net	​	​	115,161	​	​	(10,329)
Loss (gain) on contingent consideration liabilities	​	​	194,968	​	​	(7,135)
Income from equity affiliates	​	​	(910)	​	​	—
Loss on the sale of assets	​	​	48	​	​	—
Changes in operating assets and liabilities, net of effect of business acquired:	​	​	​	​	​	​
Accounts receivable, net	​	​	(19,568)	​	​	(38,991)
Accounts receivable, related parties	​	​	(3,498)	​	​	—
Prepaid expenses	​	​	(339)	​	​	(1,628)
Inventory	​	​	(2,097)	​	​	(95)
Other noncurrent assets	​	​	(1,030)	​	​	92
Accounts payable and accrued liabilities	​	​	94,299	​	​	(25,221)
Commodity derivative settlements payable/receivable	​	​	38,130	​	​	(5,489)
Right of use liabilities	​	​	(7,313)	​	​	(3,910)
Income taxes payable to related party	​	​	29,443	​	​	1,217
Payable to related party	​	​	—	​	​	(511)
Asset retirement expenditures	​	​	(1,165)	​	​	—
Net cash provided by (used in) operating activities	​	​	358,133	​	​	(7,405)
Cash flows from investing activities:	​	​	​	​	​	​
Investment in joint venture	​	​	(88,410)	​	​	—
Acquisition of natural gas properties	​	​	(2,528)	​	​	(501,712)
Business combination, net of cash acquired	​	​	—	​	​	311
Acquisition of undeveloped natural gas properties	​	​	(5,024)	​	​	(2,064)
Investment in other property and equipment	​	​	(2,249)	​	​	(1,187)
Development of natural gas properties	​	​	(63,932)	​	​	(9,340)
Proceeds from the sale of other property and equipment	​	​	285	​	​	—
Net cash used in investing activities	​	​	(161,858)	​	​	(513,992)

The accompanying notes are an integral part of the consolidated financial statements.

F-6

BKV Corporation

Consolidated Statements of Cash Flows
(In thousands)

​	Year Ended December 31,
​	2021			2020
Cash flows from financing activities:	​	​	​	​	​	​
Proceeds from notes payable from related party	​	​	166,000	​	​	129,000
Payments on notes payable to related party	​	​	(24,000)	​	​	(105,000)
Proceeds from the issuance of common stock and other equity contributions	​	​	—	​	​	323,799
Proceeds from the issuance of preferred stock	​	​	—	​	​	94,924
Redemption of minority ownership puttable shares	​	​	(2,754)	​	​	—
Issuance of minority ownership puttable shares	​	​	3,177	​	​	—
Dividends paid to preferred stock shareholders	​	​	(10,330)	​	​	—
Redemption of preferred stock	​	​	(121,275)	​	​	—
Dividends paid to common stock shareholders	​	​	(88,126)	​	​	—
Redemption of common stock	​	​	(1,106)	​	​	—
Purchase of common stock issued through equity-based compensation plan	​	​	(110)	​	​	—
Net share settlements, equity-based compensation	​	​	(529)	​	​	—
Net cash (used in) provided by financing activities	​	​	(79,053)	​	​	442,723
Net increase (decrease) in cash, cash equivalents and restricted cash	​	​	117,222	​	​	(78,674)
Cash and cash equivalents, beginning of period	​	​	17,445	​	​	96,119
Cash and cash equivalents, end of period	​	$	134,667	​	$	17,445
Supplemental cash flow information:	​	​	​	​	​	​
Cash payments for:	​	​	​	​	​	​
Interest	​	$	393	​	$	1,523
Non-cash investing and financing activities:	​	​	​	​	​	​
Increase (decrease) in accrued capital expenditures	​	$	12,297	​	$	(1,377)
Additions to asset retirement obligations	​	$	923	​	$	772
Additions to operating assets and liabilities for business combination, net of cash acquired	​	$	—	​	$	19,689
Additions to right of use assets and liabilities	​	$	11,249	​	$	7,093
Adjustment of minority ownership puttable shares to redemption value	​	$	7,042	​	$	—
Adjustment of equity-based compensation to redemption value	​	$	4,236	​	$	—
Impact of redemption of minority interest puttable shares on additional paid-in capital, common stock and treasury stock	​	$	2,754	​	$	—
Accretion of preferred stock to redemption value	​	$	3,745	​	$	—

The accompanying notes are an integral part of the consolidated financial statements.

F-7

BKV Corporation

Consolidated Statements of Stockholders’ Equity, Partners’ Capital and Mezzanine Equity
(In thousands, except per share amounts)

​

Stockholders’ Equity and Partners’ Capital

Mezzanine Equity

​

Common Stock

Treasury

Additional Paid-in Capital

Accumulated Deficit

Total Stock-holders’ Equity

Total Partners’ Capital

Preferred Stock

Common Stock

Equity-based compensation

Total Mezzanine Equity

​

Shares

Amount

Shares

Amount

Balances, January 1, 2020

​

—

​

$

—

​

$

—

​

$

—

​

$

—

​

$

—

​

$

684,190

​

$

—

​

—

​

$

—

​

$

—

​

$

—

Contributed capital

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

100,000

​

​

—

​

—

​

​

—

​

​

—

​

​

—

Net loss

​

—

​

​

—

​

​

—

​

​

—

​

​

(26,773)

​

​

(26,773)

​

​

(16,573)

​

​

—

​

—

​

​

—

​

​

—

​

​

—

Corporatization

​

90,471

​

​

905

​

​

—

​

​

744,424

​

​

—

​

​

745,329

​

​

(767,617)

​

​

—

​

2,229

​

​

22,288

​

​

—

​

​

22,288

Shares issued in business combination

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

2,000

​

​

20,000

​

​

—

​

​

20,000

Issuance of common stock

​

22,384

​

​

224

​

​

—

​

​

223,575

​

​

—

​

​

223,799

​

​

—

​

​

—

​

—

​

​

—

​

​

—

​

​

—

Issuance of preferred stock

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

94,924

​

—

​

​

—

​

​

—

​

​

94,924

Other, net

​

—

​

​

—

​

​

—

​

​

501

​

​

—

​

​

501

​

​

—

​

​

—

​

—

​

​

—

​

​

—

​

​

—

Balances, December 31, 2020

​

112,855

​

$

1,129

​

$

—

​

$

968,500

​

$

(26,773)

​

$

942,856

​

$

—

​

$

94,924

​

4,229

​

$

42,288

​

$

—

​

$

137,212

Net loss

​

—

​

​

—

​

​

—

​

​

—

​

​

(134,463)

​

​

(134,463)

​

​

—

​

​

—

​

—

​

​

—

​

​

—

​

​

—

Dividend declared, preferred stock shareholders ($0.25 per share)

​

—

​

​

—

​

​

—

​

​

—

​

​

(10,330)

​

​

(10,330)

​

​

—

​

​

—

​

—

​

​

—

​

​

—

​

​

—

Accretion of preferred stock to redemption value

​

—

​

​

—

​

​

—

​

​

(3,745)

​

​

—

​

​

(3,745)

​

​

—

​

​

3,745

​

—

​

​

—

​

​

—

​

​

3,745

Deemed dividend, preferred stock shareholders

​

—

​

​

—

​

​

—

​

​

(22,606)

​

​

—

​

​

(22,606)

​

​

—

​

​

—

​

—

​

​

—

​

​

—

​

​

—

Redemption of preferred stock

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

(98,669)

​

—

​

​

—

​

​

—

​

​

(98,669)

Redemption of common stock

​

(100)

​

​

—

​

​

(1,106)

​

​

—

​

​

—

​

​

(1,106)

​

​

—

​

​

—

​

—

​

​

—

​

​

—

​

​

—

Purchase of vested equity-based compensation award shares of common stock

​

(10)

​

​

—

​

​

(110)

​

​

—

​

​

—

​

​

(110)

​

​

—

​

​

—

​

—

​

​

—

​

​

—

​

​

—

Redemption of minority ownership puttable common stock shares

​

—

​

​

3

​

​

(2,754)

​

​

2,751

​

​

—

​

​

—

​

​

—

​

​

—

​

(275)

​

​

(2,754)

​

​

—

​

​

(2,754)

Dividend declared ($0.75 per share)

​

—

​

​

—

​

​

—

​

​

—

​

​

(88,126)

​

​

(88,126)

​

​

—

​

​

—

​

—

​

​

—

​

​

—

​

​

—

Issuance of common stock from employee stock purchase plan

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

287

​

​

3,265

​

​

—

​

​

3,265

Adjustment of minority ownership puttable shares to redemption value

​

—

​

​

—

​

​

—

​

​

(7,042)

​

​

—

​

​

(7,042)

​

​

—

​

​

—

​

—

​

​

7,042

​

​

—

​

​

7,042

Issuance of common stock upon vesting of equity-based compensation awards

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

116

​

​

—

​

​

—

​

​

—

Impact of modification of equity-based compensation plan

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

—

​

​

—

​

​

25,342

​

​

25,342

Capital contribution from modification of equity-based compensation plan

​

—

​

​

—

​

​

—

​

​

780

​

​

—

​

​

780

​

​

—

​

​

—

​

—

​

​

—

​

​

—

​

​

—

Equity-based compensation

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

—

​

​

—

​

​

3,648

​

​

3,648

Adjustment of equity-based compensation to redemption value

​

—

​

​

—

​

​

—

​

​

(5,016)

​

​

—

​

​

(5,016)

​

​

—

​

​

—

​

—

​

​

—

​

​

5,016

​

​

5,016

Balances, December 31, 2021

​

112,745

​

$

1,132

​

$

(3,970)

​

$

933,622

​

$

(259,692)

​

$

671,092

​

$

—

​

$

—

​

4,357

​

$

49,841

​

$

34,006

​

$

83,847

The accompanying notes are an integral part of the consolidated financial statements.

F-8

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

Note 1 — General Information

General

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

Upon its incorporation, BKV Corp entered into certain agreements to acquire the net assets of BKV Oil and Gas Capital Partners, L.P. (“BKV O&G”) in a common control transaction. BKV Corp also entered into a transaction to acquire Kalnin Ventures LLC (“KV”) in a business combination. These two transactions resulted in the formation of a new consolidated corporate entity. The associated series of transactions further described in Note 18 — Corporatization Event are collectively referred to as the “Corporatization Event.”

Together BKV Corp and its wholly owned subsidiaries are referred to collectively as “BKV” or the “Company.” The Corporatization Event resulted in a change in reporting entity. The change in reporting entity under common control requires retrospective presentation of BKV O&G and BKV for the period presented as if the change had been in effect since the beginning of the period being presented. Accordingly, the accompanying Consolidated Statement of Operations and Comprehensive Loss for the year ended December 31, 2020 represents the consolidation of BKV O&G’s results of operations for the four months ended April 30, 2020 and BKV Corp’s results of operations for the eight months ended December 31, 2020.

The majority shareholder of BKV Corp is Banpu North America Corporation (“BNAC”), which owns 96.3% of BKV Corp’s shares. BKV Corp’s ultimate parent company is Banpu Public Company Limited, a public company listed in the Stock Exchange of Thailand. The remaining 3.7% of shares are owned by non-controlling management, director, employee and non-employee shareholders who hold shares with contingent put rights that may be exercised according to conditions stipulated in the Shareholders’ Agreement.

Basis of Preparation of the Consolidated Financial Statements

The accompanying consolidated financial statements have been prepared on the accrual basis of accounting in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts for BKV Corp’s direct and indirect wholly owned subsidiaries and entities in which BKV Corp has a controlling financial interest.

These consolidated financial statements include BKV Corp and its wholly owned subsidiaries which include:

•

KV, a limited liability company formed September 19, 2013 and registered with the State of Colorado;

•

BKV O&G, a limited partnership formed June 1, 2015 with the State of Delaware;

•

BKV Chaffee Corners, LLC (“Chaffee”), a limited liability company formed March 28, 2016, wholly owned subsidiary of BKV O&G, and registered with the State of Delaware;

•

BKV Chelsea LLC (“Chelsea”), a limited liability company formed November 10, 2016, wholly owned subsidiary of BKV O&G, and registered with the State of Delaware;

•

BKV Operating LLC (“Operating”), a limited liability company formed October 12, 2017, wholly owned subsidiary of BKV O&G, and registered with the State of Delaware; and

•

BKV Barnett LLC (“Barnett”), a limited liability company formed December 5, 2019, wholly owned subsidiary of BKV O&G, and registered with the State of Delaware.

F-9

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

Significant Judgments and Accounting Estimates

The preparation of these consolidated financial statements in accordance with GAAP as of and for the years ended December 31, 2021 and 2020 requires Company management to make estimates using assumptions and judgements considered reasonable, which affect the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to the Company’s consolidated financial statements include estimates of proved hydrocarbon reserves used in calculating depletion; estimates of unpaid revenues and unbilled costs; future cash flows from natural gas reserves on proved properties used in impairment assessments; valuation of commodity derivative instruments; the estimation of future decommissioning obligations; assignment of fair value to assets acquired and liabilities assumed in connection with acquisitions that are considered business combinations and allocating purchase price in connection with acquisitions that are considered asset acquisitions; valuation of ownership puttable shares; valuation of the Company’s common stock relative to the grant date fair value of equity-based compensation, valuation of market-based performance conditions; valuation of contingent consideration associated with potential bonus payments for certain assets acquired; and valuation of deferred income tax assets.

Liquidity

As of December 31, 2021, the Company held $134.7 million of cash in operating accounts. The Company’s working capital deficit as of December 31, 2021 is $269.0 million, which is largely driven by notes payable to BNAC of $166.0 million due in 2022, contingent consideration payable of $65.0 million, and current derivative liabilities of $91.2 million. For the year ended December 31, 2021, the Company’s cash flows from operations was $358.1 million. In 2022, the Company paid $50.0 million of the $166.0 million of notes payable and extended the maturity of the remaining $116.0 million to December 31, 2027 (see Note 7 — Related Parties). As discussed in Note 15 — Commitments and Contingencies, the $65.0 million of contingent consideration payable as of December 31, 2021 was paid on January 18, 2022. The current derivative liabilities will settle monthly during the year ended December 31, 2022, in conjunction with the corresponding commodity sales. The Company intends to use the proceeds from the corresponding commodity sales to pay the settlements of the derivative liabilities.

In June 2022, the Company entered into a term loan and used the proceeds to fund the acquisition of operated and non-operated interests in proved reserves and certain midstream support assets in the Barnett formation. Refer to Note 20 — Subsequent Events for additional information regarding the acquisition. The term loan is due in five equal installments beginning in June 2023. The Company intends to make this payment with cash flows from existing and newly acquired operations.

On August 4, 2022, the Company entered an amendment to its ISDA Master Agreement with a counterparty to its derivative contracts pursuant to which the Company has agreed to terminate or novate, at the election of the Company, $100.0 million of its derivative contracts with the counterparty. To the extent the Company elects to terminate any such derivative contracts, the Company will be required to make cash payments in the applicable amount to the counterparty, which payments would be due in the aggregate by November 30, 2022. The Company intends to make such payments with cash flows from operations, inclusive of the recent acquisition of assets from XTO Energy, Inc. Refer to Note 20 — Subsequent Events for additional information regarding this agreement.

Note 2 — Summary of Significant Accounting Policies

The consolidated financial statements have been prepared on the historical cost basis with the exception of certain derivative financial liabilities, derivative financial assets, mezzanine equity, and certain contingent payments measured at fair value, as required by GAAP.

F-10

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

(a) Principles of Consolidation

These consolidated financial statements include financial information for BKV Corp, KV, BKV O&G, Chaffee, Chelsea, Operating, and Barnett. Accordingly, all intercompany balances and transactions between these entities have been eliminated within the consolidated financial statements. Undivided interests in natural gas properties and midstream assets are consolidated on a proportionate basis.

(b) Accounting Estimates

The preparation of these consolidated financial statements in accordance with GAAP as of and for the years ended December 31, 2021 and 2020 requires Company management to make estimates using assumptions and judgements considered reasonable, which affect the consolidated financial statements and accompanying notes. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Estimates which are particularly significant to the Company’s consolidated financial statements include estimates of proved hydrocarbon reserves used in calculating depletion; estimates of unpaid revenues and unbilled costs; future cash flows from natural gas reserves on proved properties used in impairment assessments; valuation of commodity derivative instruments; the estimation of future decommissioning obligations; assignment of fair value to assets acquired and liabilities assumed in connection with acquisitions that are considered business combinations and allocating purchase price in connection with acquisitions that are considered asset acquisitions; valuation of ownership puttable shares; valuation of the Company’s common stock relative to the grant date fair value of equity-based compensation, valuation of market-based performance conditions; valuation of contingent consideration associated with potential bonus payments for certain assets acquired; and valuation of deferred income tax assets. While Management is not aware of any significant revisions to any of its current estimates, there will likely be future revisions to its estimates resulting from matters such as revisions in estimated oil and natural gas volumes, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and natural gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period in which the adjustment occurs.

(c) Acquisitions

Acquisitions are accounted for either as Business Combinations or Asset Acquisitions in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 805 Business Combinations.

Business Combinations

If the assets acquired and liabilities assumed constitute a business, the transaction is accounted for as a business combination. This method requires the recognition of the acquired identifiable assets, assumed liabilities and any non-controlling interest in the companies acquired at their fair value.

The value of the purchase price may be finalized up to a maximum of one year from acquisition date.

The acquirer shall recognize goodwill at the acquisition date, being the excess of:

•

The consideration transferred, the amount of non-controlling interests and, in business combinations achieved in stages, the fair value at acquisition date of the investment previously held in the acquired company;

•

Over fair value at acquisition date of acquired identifiable assets and assumed liabilities.

Factors giving rise to goodwill generally include operational synergies that are anticipated as a result of the business combination and growth expected to result in economic benefits from access to new customers

F-11

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

and markets. If the consideration transferred is lower than the fair value of acquired identifiable assets and assumed liabilities, an additional analysis is performed on the identification and valuation of the identifiable elements of the assets and liabilities. After having completed such additional analysis, any residual negative goodwill is recorded as a bargain purchase gain.

Asset Acquisitions

When substantially all of the gross assets acquired are concentrated in a single identifiable asset, or a group of similar identifiable assets, the acquisition is treated as an asset acquisition.

The Company accounts for asset acquisitions by performing purchase price allocations wherein the total transaction value is determined by aggregating the base purchase price, certain closing adjustments, and contingent consideration, if any. The total transaction value is then allocated to the acquired assets pro-rata based on their fair values. This allocation may cause identified assets to be recognized at amounts that are greater than their fair values. However, “non-qualifying” assets, which include financial assets and other current assets, should not be assigned an amount greater than their fair value. The determination of fair values of assets acquired requires the Company to make estimates and use valuation techniques. The transaction costs associated with asset acquisitions are capitalized as part of the assets acquired. Subsequent changes to the fair value of contingent consideration are recorded in the Other income and expense section of the Consolidated Statements of Operations and Comprehensive Loss.

(d) Cash and Cash Equivalents

Cash represents cash deposits held at financial institutions. Cash equivalents include short-term highly liquid investments of sufficient credit quality that are readily convertible to known amounts of cash and have original maturities of three months or less.

(e) Inventory

Inventories are stated at the lower of cost or net realizable value. The cost of inventories is based upon the average cost method.

(f) Income Taxes

The Company accounts for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, the Company determines deferred tax assets and liabilities on the basis of the differences between the financial statement and tax bases of assets and liabilities by using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

The Company regularly reviews its deferred tax assets for recoverability and establishes a valuation allowance if it is more likely than not that some portion, or all, of a deferred tax asset will not be realized. The determination as to whether a deferred tax asset will be realized is made on a jurisdictional basis and is based on both positive and negative evidence. This evidence includes historic taxable income, projected future taxable income, the expected timing of the reversal of existing temporary differences and the implementation of tax planning strategies.

The Company records uncertain tax positions in accordance with Accounting Standards Codification (“ASC”) Topic 740 on the basis of a two-step process in which (1) the Company determines whether it is more-likely-than-not that the tax positions will be sustained on the basis of the technical merits of the position and (2) for those tax positions that meet the more-likely-than-not recognition threshold, the Company

F-12

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

recognizes the largest amount of tax benefit that is more than 50 percent likely to be realized upon ultimate settlement with the related tax authority.

The Company evaluates its tax positions that have been taken or are expected to be taken on income tax returns to determine if an accrual is necessary for uncertain tax positions. The Company recognizes interest and penalties as a component of tax expense. Refer to Note 17 — Income Taxes for further discussion.

(g) Natural Gas Properties

The Company uses the successful efforts method of accounting for natural gas producing activities, as defined within ASC 932 Extractive Activities — Oil and Gas. Costs to acquire mineral interests in natural gas properties, to drill and equip exploratory leases that find proved reserves, and to drill and equip development leases and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized, or suspended, pending determination of whether the wells have proved reserves. If the Company determines the wells do not have proved reserves, the costs are charged to expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If the Company determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. There were no exploratory wells capitalized pending determinations of whether the wells have proved reserves at December 31, 2021 and 2020. Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to expense as incurred. The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to intended use. For the years ended December 31, 2021 and 2020, the Company had no capitalized interest costs. Costs incurred to maintain wells and related equipment are charged to expense as incurred. Capitalized amounts attributable to developed gas properties are depleted by the unit-of-production method over proved developed reserves.

Capitalized costs related to proved gas properties, including wells and related support equipment and facilities, are evaluated for impairment on an analysis of undiscounted future cash flows in accordance with ASC 360 Property, Plant, and Equipment. If undiscounted future cash flows are insufficient to recover the net capitalized costs related to proved properties, then the Company recognizes an impairment charge in its results of operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. The Company had no impairment of proved properties during the years ended December 31, 2021 and 2020.

Undeveloped natural gas properties are tested for impairment on a regular basis, based on the results of the exploratory activity and management’s evaluation. In the event of a discovery, the undeveloped natural gas properties are transferred to developed natural gas properties at net book value as soon as proved reserves are recognized. During the years ended December 31, 2021 and 2020, the Company recognized no impairments related to undeveloped natural gas properties.

(h) Midstream Assets

Midstream assets are recorded at historical cost, less depreciation. Hydrocarbon transportation and processing assets (midstream assets) are depreciated using the straight-line method over twenty-five years for compressor and meter stations, and forty years for pipelines. Routine maintenance and repairs are charged to operating expenses as incurred. Realization of the carrying value of midstream assets is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the assets, including any disposal value, is less than the carrying amount

F-13

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flows. There were no impairments recognized during the periods ended December 31, 2021 and 2020.

(i) Other Property and Equipment

Other property and equipment is stated at cost, net of accumulated depreciation. Cost includes the purchase price and, where relevant, any costs directly attributable to bringing the asset to the location and condition necessary. When significant costs are incurred subsequent to the purchase of the asset that extends the life of the asset, such costs are included in the cost of the applicable asset and depreciated over their respective useful lives. All other subsequent costs are recognized in the Consolidated Statements of Operations and Comprehensive Loss as either lease operating expense or general and administrative expense.

Realization of the carrying value of other properties and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including any disposal value, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flows. There were no material impairments recognized during the periods ended December 31, 2021 and 2020, respectively.

The Company incurs costs in developing, configuring, integrating, and implementing a cloud computing environment for hosting internal-use software. Costs which are able to be capitalized are amortized on a straight-line basis over the useful life of the software.

Depreciation and amortization expense is included within Depreciation, depletion and amortization on the Consolidated Statements of Operations and Comprehensive Loss. Following is a listing of useful lives for other property and equipment and cloud computing costs:

​	Useful Life
Buildings	39 years
Furniture, fixtures, equipment, vehicles and other	5 years
Computer hardware and software	3 – 5 years
Leasehold improvements	7 – 10 years

(j) Asset Retirement Obligations

The Company follows the provisions of ASC 410-20 Asset Retirement Obligations, which requires entities to record the fair value of obligations associated with the retirement of tangible, long-lived assets in the period in which they are incurred. When a liability is initially recorded, the Company capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value, and the capitalized cost is depleted over the useful life of the related asset. During the years ended December 31, 2021 and 2020, accretion expense of $10.0 million and $3.2 million, respectively, was recognized.

Revisions to estimated asset retirement obligations will result in an adjustment to the related capitalized asset and corresponding liability. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss. The Company’s asset retirement obligation relates to the plugging, dismantling, removal, site reclamation and similar activities of its natural gas properties.

Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using the Company’s credit adjusted risk free rate. The Company uses unobservable inputs

F-14

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

in the estimation of asset retirement obligations that include, but are not limited to: costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and discount rate. Due to the subjectivity of assumptions and the relative long lives of the Company’s leases, the costs to ultimately retire the Company’s obligations may vary significantly from prior estimates. Assumptions used in determining estimates are reviewed annually.

(k) Leases

The Company adopted ASC 842 — Leases on January 1, 2020. ASC 842 requires lessees to recognize a right of use asset and corresponding lease liability on the Consolidated Balance Sheets for all leases. The Company determines if an arrangement is a lease at inception of the arrangement and if such lease will be classified as an operating lease or a finance lease. As of December 31, 2021 and 2020, all of the Company’s leases are accounted for as operating leases. The Company makes use of the practical expedient that permits combining lease and non-lease components.

Right of use (“ROU”) assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent the Company’s obligation to make lease payments arising from the leases. ROU assets and ROU liabilities are recognized at the lease commencement date based on the present value of minimum lease payments over the lease term. Most leases do not provide an implicit interest rate; therefore, the Company used its incremental borrowing rate based on the information available at the inception date to determine the present value of the lease payments. Lease terms include options to extend the lease when it is reasonably certain that the Company will exercise that option. Lease cost for lease payments is recognized on a straight-line basis over the lease term. Certain leases have payment terms that vary based on the usage of the underlying assets.

The Company has ROU assets, and current and non-current ROU liabilities related to office space, a pipe yard, and compressor leases requiring balance sheet presentation. As of December 31, 2021 and 2020, the Company had $14.2 million and $9.9 million, respectively, of ROU assets. At December 31, 2021 and 2020, the related current ROU liabilities measured at $10.7 million and $6.5 million, respectively, and non-current ROU liabilities measured at $4.7 million and $4.6 million, respectively.

(l) Revenue Recognition

The Company recognizes revenue in accordance with ASC 606 Revenue from Contracts with Customers (“ASC 606”). The core principle of ASC 606 is that an entity should recognize revenue for the transfer of goods or services equal to the amount of consideration that it expects to be entitled to receive for those goods or services. The Company derives the majority of revenues from natural gas, NGL and oil sales contracts. The contracts specify each party’s rights regarding the goods or services to be transferred and contain commercial substance as they impact the Company’s financial statements. A high percentage of receivables balance is current, and the Company has not historically entered into contracts with counterparties that pose a credit risk without requiring adequate economic protection to ensure collection. The Company determines revenue recognition through the following five step model:

•

Identification of the contract(s) with a customer

•

Identification of the performance obligation(s) in the contract

•

Determination of the transaction price

•

Allocation of the transaction price to the performance obligation(s) in the contract

•

Recognition of revenue when or as performance obligation(s) are satisfied

Natural Gas, NGLs and Oil Revenue

The Company’s revenues are primarily derived from the sale of natural gas and NGLs that are extracted from the Company’s natural gas wells as well as the sale of oil. Sales of natural gas, NGLs and oil

F-15

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

are recognized when the Company satisfies a performance obligation by transferring control of a product to a customer. Payment is generally received in the month following the sale. Timing of revenue recognition may differ from the timing of invoicing to customers; however, as the right to consideration after delivery is unconditional based on only the passage of time before payment of the consideration is due, upon delivery the Company records a receivable on the Consolidated Balance Sheets.

Under the Company’s natural gas sales contracts, it delivers natural gas to the purchaser at an agreed upon delivery point for a specified index price adjusted for pricing differentials. To deliver natural gas to the agreed upon delivery point, the Company or other third parties gather, compress, process and transport the Company’s natural gas. The Company maintains control of the natural gas during gathering, compression, processing, and transportation. Upon delivery of the product, the Company transfers control and recognizes revenue based on the contract price. In this scenario, the Company is the principal, and revenues are recognized on a gross basis or based on the contract price.

The Company enters into certain contracts for gathering and transportation of natural gas, NGL and oil products to deliver the products to customers. Fees incurred prior to control transfer are considered shipping and handling costs and are classified as gathering and transportation expense. Fees incurred after control transfer are included as a reduction to the transaction price. In this scenario, the Company is the agent, and revenues are recognized on a net basis.

Typically, the Company’s natural gas, NGL, and oil sales contracts define the price as a formula based on the average market price, as specified on set dates each month, for the specific commodity during the month of delivery. Given the industry practice to invoice customers the month following the month of delivery and the Company’s payment terms which are typically within 30 to 60 days of control transfer, no significant financing component is included within the contracts.

Non-operated Midstream Revenue

Non-operated midstream revenues are generated from the Company’s undivided interest in certain midstream assets. As a non-operator the Company recognizes revenues when services are rendered by the operator based on quantities transported and measured, and contractual rates in accordance with the joint operating agreement between the Company and the operator. Revenues is recognized revenue based on the actual (known) consideration obtained from the operator because the Company does not have immediate visibility of all quantities transported. Consequently, revenue is recorded when the data is available.

Marketing Revenue

In conjunction with certain contracts for the sales of natural gas and NGLs, the Company recognizes the Company’s share of net profits related to marketing revenues generated from a profit sharing agreement with a marketer. The contract includes variable components of consideration that are settled upon satisfaction of performance obligations which occurs at the point which control of the natural gas or NGL’s is transferred by the purchaser to a third party. Revenues are recognized based on the underlying variable consideration pricing, and delivered volumes.

Other Considerations

In addition to revenues from natural gas, NGL and oil contracts from the Company’s operated assets, BKV Corp entered into joint operating agreements as a non-operator for the sale of hydrocarbons through other operators. As a non-operator, BKV Corp recognizes revenue based on the actual (known) consideration that is obtained from the operator because BKV Corp does not have visibility into the terms of the sale. Consequently, non-operated revenue is recorded when the data is available.

The recognition of gains or losses on derivative instruments is not considered revenue from contracts with customers. The Company may use financial contracts accounted for as derivatives as economic hedges

F-16

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

to manage price risk associated with normal sales or in limited cases may use them for contracts the Company intends to physically settle but that do not meet all of the criteria to be treated as normal sales.

Transaction Price Allocated to Remaining Performance Obligations

For the Company’s product sales that have a contract term greater than one year, the Company utilized the practical expedient in ASC 606, which does not require the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s product sales contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. For the Company’s product sales that have a contract term of one year or less, the Company utilized the practical expedient in ASC 606, which does not require the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Contract Costs

Costs to obtain a contract are generally immaterial but the Company has elected the practical expedient to expense these costs as incurred if the duration of the contract is one year or less.

Please refer to Note 9 — Revenue from Contracts with Customers for additional disclosure.

(m) Lease Operating and Workover Expense

Lease operating expenses represent certain field employees’ salaries, salt water disposal, repairs and maintenance, and other standard operating expenses. Lease operating expenses are expensed as incurred.

Workover expenses include those costs incurred to perform more substantial maintenance or remedial treatments on a well to enhance production. These costs are also expensed as incurred.

(n) Derivative Financial Instruments

The Company enters into commodity derivative instruments to reduce the effect of price volatility on a portion of the Company’s future natural gas and NGL production. These activities may prevent the Company from realizing the full benefits of price increases above the levels of the derivative instruments on a portion of its future natural gas and NGL production. The commodity derivative instruments are measured at fair value and are included in the Consolidated Balance Sheets as commodity derivative assets and commodity derivative liabilities. The fair value of the Company’s commodity derivative instruments are calculated using industry standard models using assumptions and inputs which are substantially observable in active markets throughout the full term of the instruments. These include market price curves, contract terms and prices, credit risk adjustments, implied market volatility and discount factors. The Company has not designated any of the derivative contracts as fair value or cash flow hedges. Therefore, the Company does not apply hedge accounting to the commodity derivative instruments. Net unsettled gains and losses on commodity derivative instruments are recorded based on the changes in the fair values of the derivative instruments and are recorded in the derivatives (losses) gains, net line on the Consolidated Statements of Operations and Comprehensive Loss. The Company’s cash flow is only impacted when the actual settlements under the commodity derivative contracts result in making or receiving a payment to or from the counterparty. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s Consolidated Statements of Cash Flows.

Derivative instruments (Note 5 — Derivative Financial Instruments) are with counterparties of high credit quality and are subject to master netting agreements, therefore the risk of nonperformance by the

F-17

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

counterparties is low. Risk of nonperformance of the Company, relative to counterparties liabilities is recognized accordingly in the consolidated financial statements.

(o) Accounts Receivable and Allowance for Expected Credit Losses

In June 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-13, Financial Instruments — Credit Losses (Topic 326): “Measurement of Credit Losses on Financial Instruments.” For public business entities, the new standard became effective for annual reporting periods beginning after December 15, 2019, including interim periods within that reporting period. The Company adopted this standard effective January 1, 2020. The standard changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires entities to use a new forward-looking expected loss model that will result in earlier recognition of allowance for losses. The Company’s receivables consist mainly of trade receivables from commodity sales and joint interest billings due from owners on properties the Company operates. The majority of these receivables have payment terms of 30 days or less. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. From an evaluation of the Company’s existing credit portfolio, historical credit losses have been de minimis and are expected to remain so in the future assuming no substantial changes to the business or creditworthiness of BKV Corp’s business partners. There was no material impact on the Company’s consolidated financial statements or disclosures upon adoption of this ASU.

(p) Fair Value of Financial Instruments

The Company follows ASC 820 Fair Value Measurements and Disclosures (“ASC 820”) for financial and non-financial assets and liabilities. ASC 820 establishes a framework for measuring fair value and expands disclosure about fair value measurements. The standard characterizes inputs used in determining fair value based on a hierarchy that prioritizes inputs depending on the degree to which they are observable.

Level 1 Fair Value Measurements — Observable, unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 Fair Value Measurements — Observable inputs such as: (i) quoted prices for similar assets or liabilities in active markets; (ii) quote prices for identical or similar assets or liabilities in markets that are not active; or (iii) valuations based on pricing models where significant inputs (e.g., interest rates, yield curves, etc.) are observable for the assets or liabilities, are derived principally from observable market data, or can be corroborated by observable market data.

Level 3 Fair Value Measurements — Unobservable inputs, including valuations based on pricing models where significant inputs are not observable and not corroborated by market data. Unobservable inputs used to the extent that observable inputs are not available and reflect the Company’s own assumptions about the assumptions market participants would use in pricing the assets or liabilities. Unobservable inputs are based on the best information available in the circumstances, which might include the Company’s own data.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to fair value measurement requires judgment and may affect the fair value assets and liabilities of their placement within fair value hierarchy levels.

Fair values are estimated for the majority of the Company’s financial instruments. Estimations of fair value, which are based on principles such as discounting future cash flows to present value, must be weighted by the fact that the value of a financial instrument at a given time may be influenced by the market

F-18

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

environment (particularly liquidity), and also the fact that subsequent changes in interest rates and exchange rates are not taken into account.

Fair value of derivative financial instruments is estimated through mark-to-market of all open positions. The valuations are determined on a daily basis using observable market data based on organized and over the counter markets.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

(q) Goodwill

Goodwill represents the excess of the cost of an acquisition over the fair value of the net assets acquired. Impairment may occur if the reporting unit’s carrying value exceeds its fair value. Due to the nature of the goodwill arising from the acquisition of KV, as is described further in Note 18 — Corporatization Event, the Company’s goodwill is tested at the reporting unit level, which for the Company is at the consolidated level due to the Company having one identifiable operating segment or reporting unit. Under the provisions of ASC 350 Intangibles — Goodwill and Other, the Company performs an impairment test for goodwill at least annually or when events and circumstances indicate the carrying value may not be recoverable. In performing the required impairment tests, the Company has the option to first assess qualitative factors to determine if it is necessary to perform a quantitative assessment for goodwill impairment. If the qualitative assessment concludes that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying value, a quantitative assessment is performed. The Company’s quantitative assessment utilizes present value (discounted cash flow) methods to determine the fair value of the reporting units with goodwill. Determining fair value using discounted cash flows requires considerable judgment and is sensitive to changes in underlying assumptions and market factors. Key assumptions relate to revenue growth, projected operating income growth, terminal values, and discount rates. If current expectations of future growth rates and margins are not met, or if market factors outside of the Company’s control, such as factors impacting the applicable discount rate, or economic or political conditions in key markets change significantly, then goodwill allocated to the reporting unit may be impaired. Management determined there were no circumstances indicating the carrying value may not be recoverable during the years ended December 31, 2021 and 2020. There have been no impairments recorded related to goodwill as the results of the annual quantitative impairment test indicated the fair value of the assets of the group to be greater than the carrying value as of December 31, 2021 and 2020.

(r) Equity-based Compensation

The Company recognizes compensation cost related to equity-based awards in the consolidated financial statements on a straight-line basis based on estimated grant date fair value. Equity-based compensation awards which ultimately settle in cash are accounted for as liabilities, and awards which are contingently settled in cash or shares of the Company’s common stock are accounted for as mezzanine equity. Mezzanine equity classified awards which are considered probable of becoming redeemable are carried on the Consolidated Balance Sheets at the greater of redemption value or initial carrying value. Changes in the redemption value of the awards result in a transfer from stockholders’ equity to mezzanine equity on the Consolidated Balance Sheets of the Company.

The Company is authorized to grant equity-based compensation in the form of restricted stock units which include service conditions, and performance-based restricted stock units, which include service

F-19

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

conditions, market performance conditions, and non-market performance conditions. The grant date fair value is determined based on the components of the award and utilize the estimated fair value of common stock prices on the grant date, Monte Carlo simulations, and the fair market value of common stock coupled with probability assessments relative to the satisfaction of non-market performance conditions.

Compensation cost is recognized ratably on a straight-line basis over the applicable vesting or service period, as applicable. Forfeitures are estimated and recognized over the applicable vesting or service period and are re-evaluated at the end of each reporting period. Actual forfeitures are recognized as they occur by reversing the expense previously recognized for awards that were forfeited during the period. The Company’s equity-based compensation is discussed further in Note 11 — Equity-based Compensation.

(s) Treasury Stock

The Company recognizes purchases of its own stock as a reduction to stockholders’ equity or mezzanine equity in the Consolidated Balance Sheets using the cost method. Shares are held until authorized for redistribution by the Company’s Board of Directors.

(t) Equity Method Investments

The Company applies the equity method of accounting to its investments over which it does not have the power to direct the activities that most significantly impact the investment’s economic performance. The Company’s judgment regarding the level of influence over its equity method investments includes considering key factors such as the Company’s ownership interest, representation on the board of directors and participation in the policy-making decisions of equity method investees. The carrying value of the Company’s equity method investments is recorded in Investment in joint venture on the Consolidated Balance Sheets. The Company’s pro-rata share of earnings in equity method investments is recorded in Income from equity affiliates in the Consolidated Statements of Operations and Comprehensive Loss.

The Company evaluates its investment in the equity method investee for impairment whenever events or changes in circumstances indicate that the carrying value of its investment may have experienced an “other-than-temporary” decline in value. If such conditions exist, the Company compares the estimated fair value of the investment to its carrying value to determine if an impairment is indicated. If impairment is indicated, the Company then determines whether the impairment is “other-than-temporary” based on its assessment of all relevant factors, including consideration of the Company’s intent and ability to retain its investment.

(u) Earnings (Loss) Per Common Share

Earnings (loss) per common share — basic for each period is computed by dividing net income (loss) attributable to BKV Corp by the basic weighted average number of shares outstanding during the period. The potential dilutive effect of shares is calculated using the treasury stock method or if-converted method as applicable. During periods in which the Company incurs a net loss, diluted weighted average shares outstanding are equal to basic weighted average shares outstanding because the effects of all potential shares are anti-dilutive.

(v) Business Segment Information

The Company is organized and managed and identified as one operating segment and one reportable segment.The Company measures financial performance on a consolidated basis with all operating revenues and income from operations with all operating revenues and income from operations generated in, and all assets based in the United States.

F-20

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

(w) Recently Issued Accounting Standards

In February 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-02, Leases. The objective of this ASU is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclose key information about leasing arrangements. The FASB subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up ASC 842 — Leases (“ASC 842”). For non-public companies, ASC 842 had an effective date for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2021 with early adoption permitted. The Company elected early adoption and adopted ASC 842 effective January 1, 2020 using the modified retrospective method as of the adoption date. Refer to Note 2 — Summary of Significant Accounting Policies (I) Leases and Note 16 — Leases for more information on the Company’s implementation of this standard.

In December 2019, the FASB issued ASU No. 2019-12, Simplifying the Accounting for Income Taxes. This ASU removes certain exceptions to the general principles in ASC 740 — Income Taxes (“ASC 740”) and also simplifies portions of ASC 740 by clarifying and amending existing guidance. It is effective for interim and annual reporting periods after December 15, 2020. The Company adopted this ASU on January 1, 2021, and it did not have a material impact on the Company’s consolidated financial statements.

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”), and in January 2021, issued ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. The Company has elected not to use the optional guidance provided by these ASUs. Please refer to Note 7 — Related Parties and Note 8 — Credit Facilities for discussion of the use of the LIBOR in connection with borrowings under the Loan Facility agreements with BNAC and credit facilities with banks.

In August 2020, the FASB issued ASU 2020-06, Debt with Conversion and Other Options and Derivatives and Hedging: Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. This ASU simplifies accounting for convertible instruments by removing certain separation models for convertible instruments. For convertible instruments with conversion features that are not accounted for as derivatives under ASC 815 or do not result in substantial premiums accounted for as paid-in capital, the convertible instrument’s embedded conversion features are no longer separated from the host contract. Consequently, and as long as no other feature requires bifurcation and recognition as a derivative, the convertible instrument is accounted for as a single liability (if applicable) and is measured at its amortized cost. This ASU is effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. Early adoption is permitted for fiscal years ending after December 15, 2020. The Company has elected early adoption of this ASU effective as of January 1, 2021, using the full retrospective method of adoption. The accompanying Consolidated Balance Sheet was adjusted as follows:

​	As of December 31, 2020
(in thousands)	As Reported			Adjustment			As Adjusted
Preferred Stock – mezzanine equity	​	$	396	​	$	94,528	​	$	94,924
Additional paid in capital – permanent equity	​	$	1,063,028	​	$	(94,528)	​	$	968,500

The early adoption of ASU 2020-06 did not have an impact on the Company’s Consolidated Statement of Operations and Compressive Loss for the year ended December 31, 2020.

F-21

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

As of December 31, 2021 and through the date the consolidated financial statements were available for issuance (see Note 20 — Subsequent Events), no other ASUs have been issued that are applicable to the Company and that would have a material effect on the Company’s consolidated financial statements and related disclosures.

Note 3 — Natural Gas Properties & Other Property and Equipment

Accumulated depreciation, depletion and amortization for developed gas properties as of December 31, 2021 and 2020 was $267.3 million and $190.3 million, respectively. Depreciation, depletion and amortization expense for developed gas properties for the years ended December 31, 2021 and 2020 was $78.1 million and $79.8 million, respectively. There were no exploratory well costs pending determination of proved reserves at December 31, 2021 and 2020 and no exploratory dry hole costs during the years ended December 31, 2021 and 2020.

Midstream assets consisted of the following:

​	As of December 31,
(in thousands)	2021			2020
Compressor station	​	$	6,831	​	$	6,831
Meter station	​	​	654	​	​	654
Pipelines	​	​	47,878	​	​	47,828
Total	​	​	55,363	​	​	55,313
Accumulated depreciation	​	​	(7,417)	​	​	(6,069)
Midstream assets, net	​	$	47,946	​	$	49,244

Depreciation expense on midstream assets of $1.3 million was recognized during each of the years ended December 31, 2021 and 2020.

Other property and equipment consisted of the following:

​	As of December 31,
(in thousands)	2021			2020
Buildings	​	$	12,675	​	$	12,675
Furniture, fixtures, equipment and vehicles	​	​	6,555	​	​	4,046
Computer software	​	​	4,715	​	​	4,901
Leasehold improvements	​	​	1,571	​	​	1,119
Land	​	​	3,090	​	​	3,090
Total	​	​	28,606	​	​	25,831
Accumulated depreciation	​	​	(6,482)	​	​	(2,663)
Other property and equipment, net	​	$	22,124	​	$	23,168

Depreciation expense for other property and equipment for the years ended December 31, 2021 and 2020 was $2.8 million and $1.8 million, respectively.

Barnett Asset Acquisition

On December 17, 2019, Barnett entered into a Purchase and Sale Agreement (“PSA”), which was subsequently amended, to acquire certain operated and non-operated interests in proved reserves and related upstream assets in the Barnett formation from Devon Energy Corporation (“Seller”) for $570.0 million,

F-22

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

subject to certain closing adjustments. The PSA included contingent payments totaling $260.0 million if certain commodity price thresholds are met during a four year period commencing January 1, 2021. The transaction closed on October 1, 2020. The acquisition was made to support the strategic growth of the Company.

Barnett paid $70.0 million into escrow in December 2019 and an additional $100.0 million in April 2020 for a total deposit of $170.0 million. At closing the Company paid an additional $319.8 million. As of the acquisition date, the fair value of the additional contingent payments was $19.7 million. See Note 4 — Fair Value Measurements and Note 15 — Commitments and Contingencies for discussion of the fair market value valuation methodology applied to the contingent consideration at the acquisition date and as of December 31, 2021, and 2020. Subsequent changes in the fair value of the contingent consideration are recognized in the Consolidated Statement of Operations and Comprehensive Loss.

The acquisition qualified as an asset acquisition as the fair value of substantially all the assets acquired were concentrated in a group of similar assets. Transaction costs incurred to acquire the assets, which amounted to $11.9 million, were capitalized and included in the cost basis of the acquired assets. Asset retirement liabilities were estimated to be $120.6 million as of the acquisition date.

The consideration was allocated to the assets acquired and liabilities assumed as follows:

(in thousands)	​	​
Assets acquired	​	​
Developed properties	$	624,914
Other property and equipment	​	14,264
Inventory	​	2,784
Liabilities assumed	​	​
Contingencies and contingent payments	​	(19,700)
Asset Retirement Obligations	​	(120,550)
Total	$	501,712

There were no other significant acquisitions or divestitures of natural gas properties during the years ended December 31, 2021 and 2020, and there were no transfers of exploration and evaluation assets to natural gas properties.

Note 4 — Fair Value Measurements

ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company primarily applies the income approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, the Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company can classify fair value balances based on the observability of those inputs.

The fair value of derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as natural gas and NGL forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are compared to the values given by counterparties for reasonableness. Since natural gas and NGL swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. Derivatives are also subject to

F-23

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

the risk that either party to a contract will be unable to meet its obligations. The Company factors non-performance risk into the valuation of derivatives using current published credit default swap rates. As of December 31, 2021, the impact of the non-performance risk adjustment to the Company’s on the fair value of commodity derivative liabilities was $4.2 million; the impact to the fair value as of December 31, 2020, was not material.

Derivative assets and liabilities measured at fair value as of December 31, 2021 and 2020 use Level 2 valuation techniques; contingent consideration is measured at fair value and as of these reporting dates uses Level 3 valuation techniques. There have been no transfers between fair value levels during the reporting periods. The fair value hierarchy for grouping these assets and liabilities is based on the significance level of inputs.

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

​	As of December 31, 2021
​	Fair Value Measurements Using:						​	​
(in thousands)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Financial assets	​	​	​	​	​	​	​	​
Derivative instruments	​	—	​	9,986	​	—	​	9,986
Financial liabilities	​	​	​	​	​	​	​	​
Derivative instruments	​	—	​	114,818	​	—	​	114,818
Contingent Consideration	​	—	​	—	​	142,533	​	142,533
Mezzanine equity	​	​	​	​	​	​	​	​
Minority ownership puttable shares	​	—	​	—	​	49,841	​	49,841
Equity-based compensation	​	—	​	—	​	34,006	​	34,006

​	As of December 31, 2020
​	Fair Value Measurements Using:						​	​
(in thousands)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Financial assets	​	​	​	​	​	​	​	​
Derivative instruments	​	—	​	15,499	​	—	​	15,499
Financial liabilities	​	​	​	​	​	​	​	​
Derivative instruments	​	—	​	5,170	​	—	​	5,170
Contingent Consideration	​	—	​	—	​	12,565	​	12,565
Mezzanine equity	​	​	​	​	​	​	​	​
Minority ownership puttable shares	​	—	​	—	​	42,288	​	42,288

The contingent consideration first reported in the year ended December 31, 2020 was generated from the asset acquisition described in Note 3 — Natural Gas Properties & Other Property and Equipment. The fair value of the contingent consideration as of December 31, 2021 and 2020 represents management’s best estimate if a third party were paid to assume the contingency. The fair value was determined using forecasted

F-24

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

monthly Henry Hub Prices and West Texas Intermediate prices,and applicable credit spread and risk free rates in the application of Monte Carlo simulations. This contingency, including the settlement, is described further in Note 15 — Commitments and Contingencies to the consolidated financial statements.

The minority ownership puttable shares were recorded at fair value upon initial recognition in mezzanine equity on the Consolidated Balance Sheets. The fair market value of the Company’s common stock was used to determine the carrying value of the minority ownership puttable shares in mezzanine equity on the Consolidated Balance Sheets as of December 31, 2021 and 2020. The Company’s common stock was valued using both observable (Level 2) and unobservable (Level 3) inputs. The minority ownership puttable shares are further described in Note 12 — Stockholders’ Equity and Mezzanine Equity and Note 18 —  Corporatization Event to the consolidated financial statements.

Equity-based compensation was recorded at fair value on the date of the modification of the terms of the awards. The underlying market condition was valued using the application of Monte Carlo simulations using both observable (Level 2) and unobservable (Level 3) inputs. The remaining components of the awards were valued based on the fair market value of the common stock of the Company, which is valued consistent with valuation methodologies described for the minority ownership puttable shares. The fair market value of the Company’s market condition and common stock as of December 31, 2021 were used to determine the fair market value of equity-based compensation in mezzanine equity on the Consolidated Balance Sheet as of December 31, 2021. Equity-based compensation is further described in Note 11 — Equity-based Compensation and Note 12 — Stockholders’ Equity and Mezzanine Equity to the consolidated financial statements.

Quantitative data regarding the Company’s Level 3 unobservable inputs are as follows:

(in thousands, except per share amounts)	Fair Value			Valuation Technique	Unobservable Input	Range or Actual
Common stock – per share – as of May 1, 2020(1)	​	$	10.00	Enterprise value	Discount rate	8.9 – 10%
Common stock – per share – as of December 31, 2020(1)	​	$	10.00	Enterprise value	Discount rate	8.9 – 10%
Contingent Consideration – as of December 31, 2020	​	$	12,565	Monte Carlo Simulation	Risk free Rate	0.3%
​	​	​	​	​	Credit Spread	6.7%
​	​	​	​	​	Discount Rate	7.0%
Contingent consideration – as of December 31, 2021	​	$	142,533	Monte Carlo Simulation	Risk Free Rate	1.0%
​	​	​	​	​	Credit Spread	4.0%
​	​	​	​	​	Discount Rate	5.0%
Market condition equity-based compensation per share – as of October 31, 2021	​	$	10.72	Monte Carlo Simulation	Performance period dividends	3% equity capital, annually
Market condition equity-based compensation per share – as of December 31, 2021	​	$	13.77	Monte Carlo Simulation	Performance period dividends	3% equity capital, annually
Common stock – per share value – as of October 31, 2021(1)	​	$	11.06	Enterprise value	Discount rate	10.0%
Common stock – per share value – as of December 31, 2021(1)	​	$	11.75	Enterprise value	Discount rate	7.7 – 9.5%

F-25

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

(1)

The Company uses the midpoint of valuation results when estimating the fair value of common stock.

The table below sets forth the changes in the Company’s level 3 financial instruments carried at fair value on a recurring basis:

​	Year ended December 31,
(in thousands)	2021			2020
Fair value, beginning of period	​	$	54,853	​	$	—
Contingent consideration-additions through asset acquisition (Note 3)	​	​	—	​	​	19,700
Contingent consideration – settlement (Note 15)	​	​	(65,000)	​	​	—
Minority ownership puttable share activity (Note 12)	​	​	511	​	​	42,288
Grant date fair value of equity-based compensation (Note 11)	​	​	28,990	​	​	—
Change in fair market value (all instruments)	​	​	207,026	​	​	(7,135)
Fair value, end of period	​	$	226,380	​	$	54,853

Note 5 — Derivative Financial Instruments

From time to time, the Company may utilize derivative contracts in connection with its natural gas and NGL operations to provide an economic hedge of the Company’s exposure to commodity price risk associated with anticipated future natural gas and NGL production. The Company does not hold or issue derivative financial instruments for trading purposes. The derivative contracts outstanding as of December 31, 2021 and 2020 consisted of swap, enhanced three-way collar, and collar agreements, subject to master netting agreements with each individual counterparty. The following table presents gross commodity derivative balances prior to applying netting adjustments and net balances recorded in the Consolidated Balance Sheets:

​	As of December 31, 2021
(in thousands)	Gross Amounts of Assets and Liabilities			Offset Adjustments		Net amounts of assets/liabilities
Current derivative assets	​	$	9,986	​	—	​	$	9,986
Noncurrent derivative assets	​	$	—	​	—	​	$	—
Current derivative liabilities	​	$	91,156	​	—	​	$	91,156
Noncurrent derivative liabilities	​	$	23,662	​	—	​	$	23,662

​	As of December 31, 2020
(in thousands)	Gross Amounts of Assets and Liabilities			Offset Adjustments		Net amounts of assets/liabilities
Current derivative assets	​	$	27,680	​	(12,196)	​	$	15,484
Noncurrent derivative assets	​	$	15	​	—	​	$	15
Current derivative liabilities	​	$	12,196	​	(12,196)	​	$	—
Noncurrent derivative liabilities	​	$	5,170	​	—	​	$	5,170

Enhanced Three-way Collar, Collar and Swap Contracts

Generally, enhanced three-way collar arrangements provide for a price floor, a price ceiling and either a price sub-floor or price sub-ceiling. The floating price for the enhanced three-way collar contracts is traded

F-26

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

for a fixed price when the floating price is not between the floor and ceiling, and for twice the contracted volumes within the contracted volumes, the sub-floor/ceiling. If the floating price is between these contracted prices, no trade occurs. A commodity swap agreement is an agreement whereby a floating price based on the underlying commodity is traded for a fixed price over a specified period. A commodity collar provides for a price floor and a price ceiling.The floating price for the collar contract is traded for a fixed price when the floating price is not between the floor and ceiling. If the floating price is between these contracted prices, no trade occurs.

The fair value of open enhanced three-way collars, collars and swap contracts reported in the Consolidated Balance Sheets may differ from that which would be realized in the event the Company terminated its position in the respective contract. Risks may arise as a result of the failure of the counterparty to the contract to comply with the terms of the contract. The loss incurred by the failure of the counterparties is generally limited to the aggregate fair value of the outstanding contracts in an unrealized gain position as well as any collateral posted with the counterparty. The Company considers the creditworthiness of each counterparty to a three-way collar, option, or swap contract in evaluating potential credit risk. Additional risks may arise from unanticipated movements in the fair value of the underlying investments.

Derivative Contracts

The Company records its derivative financial instruments related to natural gas and NGL production at fair value using a market approach and has not designated any derivatives as hedges. Derivative financial instruments are marked-to-market and presented on the Consolidated Balance Sheets as commodity derivative assets or commodity derivative liabilities with the amount of unsettled gain or loss reflected in derivative (losses) gains, net in the Consolidated Statements of Operations and Comprehensive Loss. Derivative financial instruments that settle throughout the year are recorded as derivative (losses) gains, net in the Consolidated Statements of Operations and Comprehensive Loss. The following table sets forth the effect of derivative instruments on the Consolidated Statement of Operations and Comprehensive Loss:

(in thousands)	Year Ended December 31,
	2021			2020
Total gain (loss) on settled derivative instruments	​	$	(268,686)	​	$	10,427
Total gain (loss) on unsettled derivative instruments	​	​	(115,161)	​	​	10,329
Total gain (loss) on derivative instruments	​	$	(383,847)	​	$	20,756

Settled derivative instrument gain (loss) for the years ended December 31, 2021, and 2020 include losses of $30.9 million and gains of $2.7 million, respectively, related to monetization of certain natural gas derivative instruments prior to their contractual settlement dates. During the year ended December 31, 2021 monetization events occurred in October and November. Pursuant to the monetization agreements, the settlements were payable in four equal installments quarterly beginning on the respective monetization dates.

As of December 31, 2021, $66.8 million of settled derivative instruments was included in accounts payable and accrued liabilities on the Company’s Consolidated Balance Sheet; which included $23.2 million related to monetizations. As of December 31, 2020, $5.5 million of settled derivative instruments receivable was included in accounts receivable, net on the Company’s Consolidated Balance Sheet.

Volume of Derivative Activities

Outstanding derivative contracts are measured at fair value using Level 2 valuation techniques and are included in the accompanying Consolidated Balance Sheets as derivative assets and derivative liabilities.

F-27

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

At December 31, 2021, the Company’s derivative activities based on volume and contract prices, categorized by primary underlying risk and related commodity, by year, were as follows:

The following table represents natural gas commodity derivatives indexed to NYMEX Henry Hub pricing:

Instrument

MMBTU

Weighted Average Price (USD)

Weighted Average Price Sub Floor

Weighted Average Price Floor

Weighted Average Price Ceiling

Weighted Average Price Sub Ceiling

Fair Value as of December 31, 2021 (In thousands)

2022

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Swap

​

28,700,000

​

$

3.74

​

​

​

​

​

​

​

​

​

​

​

​

​

$

2,302

Enhanced three-way collars

​

52,185,000

​

​

​

​

$

2.51

​

$

2.57

​

$

3.14

​

$

3.17

​

$

(75,589)

Collars

​

6,320,000

​

​

​

​

​

​

​

$

2.82

​

$

3.63

​

​

​

​

$

(4,018)

2023

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Swap

​

3,340,000

​

$

2.81

​

​

​

​

​

​

​

​

​

​

​

​

​

$

(1,512)

Three-way collars

​

8,350,000

​

​

​

​

​

​

​

$

2.45

​

$

3.15

​

$

3.15

​

$

(7,587)

Collars

​

50,100,000

​

​

​

​

​

​

​

$

2.85

​

$

3.75

​

​

​

​

$

(3,097)

The following table represents natural gas liquids commodity derivatives for contracts expiring throughout the year ended December 31, 2022 and 2023 based on the applicable index listed below:

Instrument	Commodity Reference Price	GAL		Weighted Average Price (USD)			Fair Value at December 31, 2021 (In thousands)
2022	​	​	​	​	​	​	​	​	​
Swap	OPIS Purity Ethane Mont Belvieu	​	38,325,000	​	$	0.27	​	$	(1,244)
Swap	OPIS IsoButane Mont Belvieu Non-TET	​	3,832,500	​	$	0.99	​	$	(736)
Swap	OPIS Normal Butane Mont Belvieu Non-TET	​	7,665,000	​	$	0.98	​	$	(1,554)
Swap	OPIS Pentane Mont Belvieu Non-TET	​	7,665,000	​	$	1.46	​	$	(1,698)
Swap	OPIS Propane Mont Belvieu Non-TET	​	22,995,000	​	$	0.86	​	$	(3,830)
2023	​	​	​	​	​	​	​	​	​
Swap	OPIS Purity Ethane Mont Belvieu	​	38,325,000	​	$	0.23	​	$	(984)
Swap	OPIS IsoButane Mont Belvieu Non-TET	​	3,832,500	​	$	0.80	​	$	(501)
Swap	OPIS Normal Butane Mont Belvieu Non-TET	​	3,832,500	​	$	0.80	​	$	(504)
Swap	OPIS Pentane Mont Belvieu Non-TET	​	7,665,000	​	$	1.28	​	$	(1,568)
Swap	OPIS Propane Mont Belvieu Non-TET	​	22,995,000	​	$	0.72	​	$	(2,714)

Additional Disclosures about Derivative Instruments

The use of derivative instruments involves the risk that the counterparties will be unable to meet their obligations under the agreements. The Company’s counterparties are primarily commercial banks and financial service institutions that management believes present minimal credit risk and its derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty. The Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable.

F-28

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

Subsequent activity

From December 31, 2021 and through the date the consolidated financial statements were available for issuance, the Company entered into the following commodity derivative positions for natural gas:

Instrument	MMBTU		Weighted Average Price (USD)
2022 Swaps	​	14,919,000	​	$	4.98
2023 Swaps	​	56,587,000	​	$	3.99

From December 31, 2021 and through the date the consolidated financial statements were available for issuance, the Company entered into the following commodity derivative positions for natural gas liquids:

Instrument

Commodity Reference Price

GAL

Weighted Average Price (USD)

Weighted Average Price Floor

Weighted Average Price Ceiling

2022

​

​

​

​

​

​

​

​

​

​

​

​

Swap

OPIS Purity Ethane Mont Belvieu Non-TET

​

56,019,600

​

$

0.37

​

​

​

​

​

​

Collar

OPIS IsoButane Mont Belvieu Non-TET

​

2,318,400

​

​

​

​

$

1.25

​

$

1.42

Collar

OPIS Normal Butane Mont Belvieu Non-TET

​

3,733,800

​

​

​

​

$

1.25

​

$

1.55

Collar

OPIS Pentane Mont Belvieu Non-TET

​

5,665,800

​

​

​

​

$

1.80

​

$

2.18

Collar

OPIS Propane Mont Belvieu Non-TET

​

15,582,000

​

​

​

​

$

1.14

​

$

1.30

Note 6 — Asset Retirement Obligations

The Company has recognized an estimated liability for its asset retirement obligations related to the future costs of plugging, abandonment, and remediation of natural gas producing properties. The present value of the estimated asset retirement obligations has been capitalized as part of the carrying amount of the related natural gas properties. The liability has been accreted to its present value during the years ended December 31, 2021, and 2020.

The following table summarizes the activities of the Company’s asset retirement obligations for the periods indicated:

​	Year ended December 31,
(In thousands)	2021			2020
Asset retirement obligations, beginning of period	​	$	148,826	​	$	24,293
Additions through asset acquisition (Note 3)	​	​	—	​	​	120,550
Liabilities incurred	​	​	923	​	​	772
Liabilities settled	​	​	(811)	​	​	—
Accretion of discount	​	​	10,030	​	​	3,211
Asset retirement obligations, end of period	​	​	158,968	​	​	148,826
Less current portion	​	​	—	​	​	—
Asset retirement obligation, long-term	​	$	158,968	​	$	148,826

F-29

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

Note 7 — Related Parties

During 2020, the Company entered into the First Amendment to a note payable with its majority shareholder BNAC (the “Lender”) which allowed for a single drawdown in the amount of $10.0 million. On July 1, 2020, BKV Corp received $10.0 million through a drawdown pursuant to the terms of the First Amendment to the Loan Agreement with interest at 5.3%. During the years ended December 31, 2021 and 2020 the Company recorded interest expense on this loan of $0.1 million and $0.2 million, respectively, in the Consolidated Statements of Operations and Comprehensive Loss. The full balance of the loan outstanding as of December 31, 2020 was repaid during the year ended December 31, 2021.

On September 28, 2020, BKV Corp received $119.0 million in accordance with a separate loan agreement entered into with the Lender. On December 16, 2020, $100.0 million of the original principal balance was repaid to the Lender. Interest on the outstanding principal is 5.25% + six-month LIBOR. During the years ended December 31, 2021 and 2020, the Company recorded interest expense on this loan of $0.2 million and $1.5 million, respectively, in the Consolidated Statements of Operations and Comprehensive Loss. The remaining balance of the loan outstanding as of December 31, 2020 was repaid during the year ended December 31, 2021.

On October 14, 2021, the Company entered into a Loan Facility Agreement with the Lender which allowed for a single drawdown in the amount of $116.0 million on the date of the agreement. Interest on the outstanding principal is LIBOR+ 5.25% and is payable on a semi-annual basis. The outstanding balance of $116.0 million as of December 31, 2021, as amended on June 15, 2022, is due on December 31, 2027, including any unpaid interest. The applicable interest rate as of December 31, 2021 was 5.41%. Interest payable under this Loan Facility as of December 31, 2021 was $1.4 million.

On November 8, 2021, the Company entered into a Loan Facility Agreement with the Lender which allowed for a single drawdown in the amount of $50.0 million on the date of the agreement. Interest on the outstanding principal is LIBOR+ 5.25% and is payable on a semi-annual basis. The outstanding balance of $50.0 million as of December 31, 2021 is due on June 30, 2022, including any unpaid interest. In the event the Company draws on its credit facility, described further in Note 8 — Credit Facilities, $15.0 million of the Loan Facility is required to be paid at that time. The applicable interest rate as of December 31, 2021 was 5.46%. Interest payable under this Loan Facility as of December 31, 2021 was $0.4 million. On January, 11, 2022, and June 1, 2022 the Company repaid $15.0 million and $35.0 million, respectively, repaying the entire outstanding balance as of December 31, 2021.

LIBOR was discontinued as a global reference rate for new loans and contracts after December 31, 2021. The Loan Facility Agreements with outstanding balances as of December 31, 2021 specify that if LIBOR is no longer a widely used as a reference rate in the financial market, with mutual agreement with the Company a replacement rate will be specified. As of the date the financial statements are available to be issued, no such agreement has been reached and the Company continues to be charged interest using LIBOR rates as previously stated. Please refer to Note 2 — Summary of Significant Accounting Policies for discussion of FASB ASU 2020-04 and ASU 2021-01, which provides guidance related to reference rate reform.

The Company is subject to certain financial and non-financial covenants under the Loan Facility Agreements entered into on October 14, 2021 and November 8, 2021 (“2021 Lender Agreements”). The non-financial covenants prevent the Company from: incurring a lien on its, or any of its subsidiaries, assets or related revenues; incurring additional indebtedness without written consent of the Lender; incurring additional unsecured indebtedness whereby the Lender does not rank equal to holder of the new unsecured indebtedness; or conducting any business outside of the business currently conducted by the Company. The financial covenants require the Company to maintain a net worth, as defined within the 2021 Lender Agreements, of greater than $800.0 million. The Company is also required to maintain a trailing twelve-month net borrowings to EBITDAX ratio of greater than 3.0x following each draw down. The Company was in compliance with all associated covenants under the 2021 Lender Agreements as of December 31, 2021.

F-30

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

On March 10, 2022, the Company entered into a Loan Facility Agreement with the Lender which allowed for a single drawdown in the amount of $75.0 million on the date of the agreement. Interest on the outstanding principal is SOFR + 5.25% and is payable on a semi-annual basis. The principal balance of $75.0 million, as amended on June 15, 2022, is due on December 31, 2027, including any unpaid interest. On June 15, 2022, the Company entered into a subordination agreement with the lender whereby the $75.0 million is subordinate to the term loans of the Company under the Credit Agreement further discussed in Note 20 — Subsequent Events.

As of December 31, 2021 and 2020, the Company had a $30.7 million and a $1.2 million payable, respectively, to BNAC for current tax expense reflected in the Income taxes payable to related party line item on the Consolidated Balance Sheets. The amounts due to BNAC as of December 31, 2021 and 2020, respectively, related to reimbursements for income tax related items. Separately, the Company had $0.5 million receivable from BNAC as of December 31, 2021, related to shared general and administrative expenses.

As of December 31, 2021, the Company had accounts receivable from BKV-BPP Power, LLC of $1.8 million related to reimbursement for certain expenses paid on behalf of BKV-BPP Power, LLC and amounts receivable under the Administration Services Agreement between the Company and BKV-BPP Power, LLC. See Note 13 — Equity Method Investment for further discussion.

The Company’s ultimate parent Banpu Public Company Limited is also the ultimate parent of Banpu US Power Corporation (“BPP US”), the Company’s partner in a joint venture which is discussed further in Note 13 — Equity Method Investment. As of December 31, 2021, the Company had accounts receivable from BPP US of $1.3 million related to reimbursement for expenses incurred during the formation of the joint venture.

Note 8 — Credit Facilities

On December 22, 2021 the Company entered into an agreement with a bank (the “Bank”) which provides for a revolving credit facility (the “Facility”) with a limit of $55.0 million. The Facility is not secured. Advances on the Facility are required to be repaid upon the earlier of sixty days after the date of the advance, or upon the receipt of a written demand notice from the Bank. Advances from the Facility must be greater than $1.0 million. Interest on any outstanding advances is payable monthly at a rate of LIBOR +2.0%. As of December 31, 2021, the Company had no outstanding advances under this facility. LIBOR was discontinued as a global reference rate for new loans and contracts after December 31, 2021. The Facility agreement includes a provision for transition to a SOFR based interest rate upon the Company receiving notification from the Bank.

Subsequent Activities

On January 20, 2022 the Company received an advance from the Facility in the amount of $30.0 million, which was paid in February of 2022.

On March 16, 2022, the Company entered into an agreement with another bank which provides for revolving term loans and letters of credit (“Facility II”) with a limit of $25.0 million. Of the $25.0 million, $15.0 million is available for cash draw downs, and in the absence of outstanding cash draw downs, the full $25.0 million is available for letters of credit. Facility II is not secured. Interest is agreed upon at the time of each cash drawn down. Facility II had one outstanding letter of credit for $14.4 million as of the date the consolidated financial statements were available for issuance.

On May 23, 2022, the Bank enacted the change to SOFR. Please refer to Note 2 — Summary of Significant Accounting Policies for discussion of FASB ASU 2020-04 and ASU 2021-01, which provides guidance related to reference rate reform.

On June 16, 2022, the Company received an advance from the Facility in the amount of $30.0 million. This amount was outstanding as of the date these financial statements were available for issuance.

F-31

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

Note 9 — Revenue from Contracts with Customers

The Company records sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement, which is variable based on commodity pricing. The Company estimates its sales volumes based on company-measured volume readings. Natural gas, NGL and oil sales are adjusted in subsequent periods based on data received from the Company’s purchasers that reflects actual volumes and prices received which is typically within two months of transfer of control to the purchaser. Historically, the difference between estimated and actual sales revenues have not been material. For the years ended December 31, 2021 and 2020, the impact of any natural gas imbalances was not significant.

In conjunction with its sales of natural gas, the Company records marketing revenues based on estimated underlying variable consideration pricing and delivered volumes. Marketing revenues are adjusted in subsequent periods based on data received from the Company’s purchaser or trading partner. Historically, the difference between estimated and actual marketing revenues has not been material. The Company considers the amount of marketing revenues recognized during the year ended December 31, 2021 to be unusual.

The Company also generates revenues from its non-operated midstream interests. Midstream revenues are recognized when services are rendered based on quantities transported and measured according to the underlying contract. The Company records midstream revenue based on volumes at stated contractual rates. The Company estimates its volumes based on third-party data. Midstream revenues are adjusted in subsequent periods based on data received from the operator that reflects actual volumes which is typically within three months.

All of the Company’s revenues are generated in the states of Pennsylvania and Texas. Revenues consist of the following:

​	Year ended December 31, 2021
(in thousands)	Pennsylvania			Texas			Total
Natural gas	​	$	131,207	​	$	465,843	​	$	597,050
Natural gas liquids	​	​	—	​	​	225,135	​	​	225,135
Oil	​	​	—	​	​	7,560	​	​	7,560
Total production revenues	​	$	131,207	​	$	698,538	​	$	829,745
Marketing revenues	​	​	—	​	​	52,616	​	​	52,616
Non-operated midstream revenues	​	​	6,917	​	​	—	​	​	6,917
Total	​	$	138,124	​	$	751,154	​	$	889,278

​	Year ended December 31, 2020
(in thousands)	Pennsylvania			Texas			Total
Natural gas	​	$	45,102	​	$	56,656	​	$	101,758
Natural gas liquids	​	​	—	​	​	11,952	​	​	11,952
Oil	​	​	—	​	​	1,333	​	​	1,333
Total production revenues	​	$	45,102	​	$	69,941	​	$	115,043
Non-operated midstream revenues	​	​	7,458	​	​	—	​	​	7,458
Total	​	$	52,560	​	$	69,941	​	$	122,501

Contract Balances

Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Under the

F-32

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

Company’s sales contracts, the Company invoices customers after its performance obligations have been satisfied, at which point payment is unconditional. As of December 31, 2020, and 2021, the Company’s receivables from contracts with customers were $100.4 million and $73.8 million, respectively.

Note 10 — Accounts Payable and Accrued Liabilities

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

​	As of December 31,
(in thousands)	2021			2020
Accounts payable	​	$	32,237	​	$	8,706
Commodity derivative settlements payable	​	​	43,252	​	​	—
Commodity derivative monetizations payable	​	​	23,175	​	​	​
Revenues payable	​	​	29,871	​	​	4,333
Other accrued liabilities	​	​	38,301	​	​	3,891
Total	​	$	166,836	​	$	16,930

Note 11 — Equity-based Compensation

On January 1, 2021 the BKV Corporation 2021 Long Term Incentive Plan (the “Plan”) was established by the adoption of the Plan by the Board of Directors, which allows for the grant of incentive awards to employees and non-employee directors of the Company in the form of restricted stock units (“RSU”). Each RSU represents the contingent right to receive one share of common stock of the Company. As of December 31, 2021, the maximum number of RSU’s authorized to be awarded under the Plan was 14,941,176. However, of the total authorized RSU’s under the plan, only 60% may be awarded on or before December 31, 2022 without written approval of the Board of Directors of the Company. Thereafter, no more than 80% of the total RSU’s may be awarded without the written approval of the Board of Directors of the Company. For accounting purposes, management evaluated grants of incentive awards from the Plan under ASC 718 — Compensation — Stock Compensation and determined a grant date, for all annual incentive awards, including those anticipated to be legally granted in the three years subsequent to the initial incentive award date, was established because all grant date criteria had been satisfied and compensation expense and forfeitures were accounted for accordingly. Under ASC 718 — Compensation — Stock Compensation, as of December 31, 2021, 14,882,898 RSU’s were considered to have been granted under the plan when taking into consideration performance RSU’s at the maximum performance level and time-based restricted stock units anticipated to be legally granted in the three years following the initial incentive award date. Of the awards considered granted under ASC 718 — Compensation — Stock Compensation during the year ended December 31, 2021, 1,969,801 RSU’s are not considered legally granted.

RSU’s are granted in the form of Performance-Based Restricted Stock Units (“PRSU”) and Time-Based Restricted Stock Units (“TRSU”). The shares of common stock issued in settlement of the RSU’s include a put right (the “Plan Put Right”) available to the incentive award grant recipients (the “Participants”). If a Participant’s employment is terminated due to voluntary resignation, and certain other conditions are met, a Participant is able to elect the Company to purchase the shares issued in settlement of his or her RSU’s at fair market value of the Company’s common stock at the time the election is made by the Participant. The Plan Put Right is only available to Participants upon the occurrence of certain events as defined in the Plan. As discussed below in “Modification of Terms,” this Plan Put Right was modified on November 5, 2021 to add a one hundred eighty-one-day holding period following vesting of the RSU’s. In addition, the Company has a purchase right (the “Call Right”) which allows for the purchase of shares of common stock issued in the settlement of the RSU’s from terminated participants at fair market value on the date of the purchase, at the Company’s discretion. As discussed below in “Modification of Terms,” this Call Right was modified on November 5, 2021 to add a one hundred eighty-one-day holding period following vesting of the RSU’s.

F-33

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

These features, specifically the Plan Put Right, required the Company to treat the incentive awards as cash-settled or liability classified in the Consolidated Balance Sheets of the Company until the Plan was modified as described below. Under liability treatment, the Company incurred $26.7 million of equity-based compensation expense which is included within the Consolidated Statement of Operations as general and administrative expense. Valuation methodologies used were consistent with those described below.

Modification of terms

On November 5, 2021, the Board of Directors of the Company approved the First Amendment to the BKV Corporation 2021 Long Term Incentive Plan (the “Plan Amendment”). The Plan Amendment included a provision to require all Participants of the Plan to hold vested shares of common stock issued in settlement of RSU’s for a minimum of one-hundred eighty-one days (the “Holding Period”) prior to having the ability to exercise the Plan Put Right. The Amendment also applied the Holding Period to the Call Right. Upon modification, the RSU’s under the plan are considered to be settled in equity, as the Holding Period is a reasonable period of time to experience the risk and rewards of an equity instrument. However, due to the existence of the Plan Put Right, the Company recognized the incentive awards within mezzanine equity on the Consolidated Balance Sheet as of the date of Plan Amendment. The fair market value of the RSU’s prior to the modification was $25.3 million. This amount was transferred from liabilities into mezzanine equity on the Consolidated Balance Sheets of the Company. All Participants of the plan agreed to the terms of the Plan Amendment. See Note 12 — Stockholders’ Equity and Mezzanine Equity for additional discussion of the Company’s treatment of equity-based compensation within mezzanine equity.

The Amendment also established the Sell Fund Repurchase Program (the “Sell Fund”). Under the Sell Fund, Participants are able to tender for repurchase their vested shares of common stock to the Company after the required Holding Period, to the extent expressly permitted under their respective award agreements. On December 21, 2021, the Board of Directors of the Company approved the opening of the Company’s first Sell Fund window, which closed on December 29, 2021. The opening of the Sell Fund window set forth requirements which limited participants in the number of shares that can be tendered, and a limitation whereby in aggregate, the total value of shares tendered by all Participants cannot exceed $2.0 million per year. Sell Fund windows can be opened twice per year, and the Sell Fund will remain in effect until the earlier of December 31, 2023 or the initial public offering of the Company. During the year ended December 31, 2021, the Company repurchased 9,949 shares at $11.06 per share for a total of $0.1 million.

Performance-Based Restricted Stock Units

During the year ended December 31, 2021, the Company granted 12.3 million PRSU’s under the Plan taking into consideration performance shares at the maximum performance level. The PRSU’s are subject to a three year vesting or performance period beginning January 1, 2021 and ending on the earlier of December 31, 2023 (the “Performance Period”) or the Initial Public Offering of the Company. All PRSU’s cliff vest based on and subject to the achievement of the performance criteria upon the earlier of an initial public offering of the Company, change in control, or December 31, 2023.

The table below summarizes the PRSU activity for the year ended December 31, 2021:

(in thousands, except per share amounts)	Shares		Weighted-Average Grant Date Fair Value
Unvested PRSU’s at January 1, 2021	​	—	​	$	—
Granted(1)	​	12,257	​	$	10.90
Forfeited(1)	​	(668)	​	$	(10.90)
Unvested PRSU’s as of December 31, 2021	​	11,589	​	$	10.90

(1)

Granted and forfeited award amounts take into consideration performance shares at the maximum performance level

F-34

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

The PSRU’s are eligible to be earned based on three performance conditions: (1) Annualized Total Shareholder Return (“TSR”) of fully diluted common stock during the performance period, (2) Return on Capital Employed (“ROCE”) based on the average annual performance over the Performance Period, and (3) IPO readiness which is based on the Company’s capability to be listed on a public stock exchange at certain points during the performance period. Between 0% and 100% of the PRSU’s at maximum performance level are eligible to be earned based on the Company achieving the following pre-established goals:

​	​	​	Performance Conditions
​	Weight		Minimum Threshold (0%)	Target Threshold (50%)	Maximum Threshold (100%)
TSR	​	60%	5%	12.5%	20%
ROCE	​	20%	—%	7%	14%
IPO readiness (capability dates)	​	20%	12/31/2024	12/31/2023	12/31/2022

The TSR component of the awards is a market-based condition valued utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes and establishes grant date fair value based on the most likely outcome. For the purposes of grant date fair value, the TSR component assumes a risk-free rate of 0.52% and volatility of 40.0%, see Note 2 — Summary of Significant Accounting Policies (p) Fair value of Financial Instruments, for the level 3 unobservable input used in the determination of the grant date fair value of the TSR. The weighted average grant date fair value, considering the modification date, of the TSR component was $10.72.

ROCE and IPO readiness are considered to be non-market performance conditions. Thus, the likelihood of achievement must be reassessed at every reporting period, and compensation expense is adjusted accordingly. As of December 31, 2021, management estimates IPO readiness will be achieved at the maximum performance level or 100%, and ROCE performance to be greater than the target performance level at approximately 66%. Accordingly, adjustments were made to compensation expense during the year ended December 31, 2021 to reflect the estimated levels of achievement. In addition to the level of achievement, the adjustment takes into account the per share grant date fair value of the Company’s common stock of $11.06 as of the modification date. The grant date fair value of the PSRU’s presented in the activity for the year ended December 31, 2021 takes into account the grant date fair value for ROCE, IPO readiness, and TSR due to the non-market performance conditions being probable of achievement as of the modification date which establishes a grant date fair value.

As of December 31, 2021, there was $52.2 million of unrecognized compensation expense related to the PRSU awards which will be amortized over a weighted average period of 2 years.

After the modification of terms, equity-based compensation expense related to the PRSU’s was $3.1 million during the year ended December 31, 2021.

Time-Based Restricted Stock Units

During the year ended December 31, 2021, the Company granted 2.6 million TRSU’s under the Plan. Of the 2.6 million TRSU’s granted during the year ended December 31, 2021, 2.0 million TRSU’s are not considered legally granted, but meet the grant date criteria under ASC 718 Compensation — Stock Compensation. Under the applicable provisions of the Plan, the TRSU incentive award was anticipated to be granted in the form of four annual awards. One quarter of the annual award requires no service for vesting and vests immediately upon the grant date. The remaining three quarters of the annual award vest in equal portions upon the subsequent three anniversary dates following the grant date. The remaining annual awards are anticipated to be granted on the first, second and third anniversaries of the initial TRSU award date, subject to continued employment with the Company and board approval. Vesting for these anticipated three annual awards is expected to follow the same vesting schedule as the first annual awards based on the

F-35

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

legal grant date. Upon an initial public offering of the Company, all unvested and legally granted and outstanding awards under the Plan will vest immediately. Awards accounted for as granted under ASC 718 Compensation — Stock Compensation, but not legally granted at such time, will not vest and will be treated accordingly.

The following table summarizes the TRSU activity for the year ended December 31, 2021:

(in thousands, except per share amounts)	Shares		Weighted-Average Grant Date Fair Value
Unvested TRSU’s at January 1, 2021	​	—	​	$	—
Granted(1)	​	2,626	​	$	11.06
Vested	​	(164)	​	$	—
Forfeited	​	(134)	​	$	(11.06)
Unvested TRSU’s as of December 31, 2021	​	2,328	​	$	11.06

(1)

Represents number of awards considered granted under ASC 718 Compensation — Stock Compensation. Of these, 1,969,801 are not considered legally granted.

As of December 31, 2021, there was $22.4 million of unrecognized compensation expense related to the TRSU awards which will be amortized over a weighted average period of five years. The grant date fair value for each TRSU was $11.06 per unit, which represents the fair market value of the Company’s common stock upon modification.

After the modification of terms, stock-based compensation expense related to the TRSU’s was $0.5 million during the year ended December 31, 2021.

Tax Impact

During the year ended December 31, 2021, the Company recognized $6.6 million of tax benefit related to equity-based compensation.

Subsequent Activity

From December 31, 2021 and through the date the consolidated financial statements were available for issuance, the Company granted an additional 484,500 RSU’s, comprised of 399,000 PRSU’s (assuming maximum performance) and 85,500 TRSU’s. Of the 85,500 TRSU’s granted, 64,125 are not considered legally granted. In addition, of the 1,969,801 TRSU’s considered granted under ASC 718 Compensation — Stock Compensation, but not legally granted during the year ending December 31, 2021, 620,789 of those awards have been legally granted since December 31, 2021, 134,289 of those awards were forfeited and the remaining 1,483,301 of those awards remain as considered to be granted under ASC 718 Compensation —  Stock Compensation, but not yet legally granted.

Note 12 — Stockholders’ Equity and Mezzanine Equity

On May 1, 2020, as part of the Corporatization Event described in Note 18 — Corporatization Event, the Company authorized 150,000,000 shares of common stock at $0.01 par and issued 94,700,000 of those shares in a private exchange with the partners in BKV O&G and the members of KV.

On December 15, 2020, the Company authorized an additional 150,000,000 shares of common stock and 80,000,000 shares of preferred stock, increasing the authorized shares of capital stock to 380,000,000.

F-36

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

Common Shares issued and outstanding

On October 1, 2020, the Company issued 22,284,000 shares of common stock to an existing investor for $222.8 million.

On December 15, 2020, the Company issued 100,000 shares of common stock to a new investor for $1.0 million, net of associated costs. These shares were issued in conjunction with the issuance of 9,900,000 shares of Series A Redeemable Preferred stock to the same investor.

In April of 2021, the Board of Directors of the Company declared a cash dividend of $0.75 per share of common stock at the time of the declaration for a total of $88.1 million which was paid to common stock shareholders in May of 2021.

As of December 31, 2021 and 2020, the Company had 117,102,214 and 117,084,000 common shares issued and outstanding, respectively. See discussion below in the Treasury Stock section of this note for discussion of redemptions and purchases of the Company’s own common stock during the year ended December 31, 2021.

Minority Ownership Puttable Shares — Mezzanine Equity

Of the 94,700,000 shares issued on May 1, 2020, 2,228,771 shares were issued to certain non-controlling management shareholders of BKV as a part of the Corporatization of BKV and 2,000,000 shares were issued as part of the merger with KV. The shares issued to the non-controlling management shareholders include a put and call feature which requires BKV to repurchase shares from these shareholders upon the occurrence of certain events stipulated in the Stockholders’ Agreement at either $10.00 per share or the fair value per share, depending on the type and timing of the triggering event. In addition, BKV may call and repurchase the shares issued to the non-controlling management shareholders upon the occurrence of certain events stipulated in the Shareholders’ Agreement at either $10.00 per share or the fair value per share, depending on the type and timing of the triggering event. The Stockholders’ Agreement, and these put and call features, will terminate upon completion of an initial public offering by the Company. Since the shares are not mandatorily redeemable, but can become redeemable at the option of the holder, the fair value of non-controlling management common stock shares upon issuance of $42.3 million was recognized within mezzanine equity. As of December 31, 2021 Management has determined it is probable that the shares will become redeemable at the end of the three-year period and has elected to carry the shares at redemption value, or fair value, in mezzanine equity on the Consolidated Balance Sheets. During the years ended December 31, 2021 and 2020, the Company recognized adjustments of $6.9 million and $0.0 million, respectively, to the carrying value of the shares to adjust to redemption value.

During the year ended December 31, 2021, certain shares were redeemed (see Treasury Stock for share counts and redemption prices) causing the specific redeemed shares to no longer retain the previously mentioned right. Accordingly, upon redemption the redeemed shares and associated carrying values were reclassified to permanent equity.

Employee Stock Purchase Plan — Mezzanine Equity

On July 16, 2020, the Company adopted the BKV Corporation Employee Stock Purchase Plan (the “ESPP”). The ESPP reserved 7,470,588 shares of common stock for purchase by eligible employees of the Company. The number of shares available is subject to adjustment based on anti-dilution provisions in the Shareholder’s Agreement. The ESPP was activated on November 1, 2021 through the completion of the First Amendment to the ESPP. As amended, the ESPP allows for certain eligible non-employees and members of the Board of Directors of the Company to purchase shares under the ESPP in addition to eligible employees of the Company. As of December 31, 2021, the Company had issued 287,209 shares of common stock under the ESPP. The shares sold under the ESPP include a put right which allows for holders of the ESPP shares to require the Company to the purchase the shares upon the occurrence of certain events

F-37

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

stipulated by the ESPP. The shares can also be purchased by the Company, at its discretion upon the occurrence of certain events as stipulated in the ESPP. Because the shares are not mandatorily redeemable, but can become redeemable at the option of the eligible employee, non-employee or Director, the fair value of the shares of common stock sold under the ESPP of $3.3 million was recognized within mezzanine equity as of December 31, 2021. Management has determined it is probable that the shares will become redeemable and has elected to carry the shares at redemption value, or fair value, in mezzanine equity on the Consolidated Balance Sheets. During the year ended December 31, 2021, the Company recognized an adjustment of $0.1 million to the carrying value of the shares.

Equity-based Compensation — Mezzanine Equity

As discussed in Note 11 — Equity-based Compensation, the Plan includes the Plan Put Right which provides that, if a Participant’s employment is terminated due to voluntary resignation, and certain other conditions are met, such Participant is able to elect to require the Company to purchase the shares issued in settlement of his or her RSU’s at fair market value of the Company’s common stock at the time the election is made by the Participant. Participants may not exercise this right for at least one-hundred eighty-one days after the vesting of the shares of common stock issued in settlement of the RSU’s. Management has determined it is probable the shares issued in settlement of the RSU’s upon vesting will become redeemable and has elected to carry the shares at redemption value which equals fair market value. During the year ended December 31, 2021, the Company recognized an adjustment to the pro-rata portion of the RSU’s which have vested in the amount of $5.0 million.The maturities related to the redemption feature are in accordance with the vesting terms discussed in Note 11 — Equity-based Compensation, taking into account the three year and one hundred eighty one day holding periods. During the year ended December 31, 2021, the Company issued 116,347 shares of common stock in settlement of vested incentive awards. Those shares of common stock are included in equity-based compensation within mezzanine equity on the Consolidated Balance Sheet of the Company at redemption value or $1.4 million.

Preferred Shares — Mezzanine Equity

On December 15, 2020, the Company authorized 80,000,000 shares of preferred stock at $10.00 par value per share. Of the shares of preferred stock authorized, 9,900,000 shares were designated as par Series A Redeemable Preferred Stock (“Series A”) and these designated shares were issued in a private placement for $99.0 million. Cost associated with the issuance was $4.1 million. These shares were issued in conjunction with 100,000 shares of common stock also issued on December 15, 2020.

Series A shares carry quarterly cumulative dividends at a rate of 10% per annum for the first five years, 18% per annum for years 6 through 10, and 20% per annum, thereafter. The holder may only redeem the Series A shares upon the occurrence of liquidation, winding-up, dissolution or change in control of the Company. The Company may also redeem the Series A shares, in whole or in part, at any time. Upon redemption by either party, the redemption value is at price equal to $12.25 per share plus unpaid accumulated dividends at the time of redemption. Holders of the preferred shares do not have voting rights with respect to their preferred shares, however they are allowed certain consensual rights. The Series A shares include conversion features allowing for conversion into 7,425,000 shares of a new series of preferred stock and 34,873,941 shares of common stock. However, the shares do not become convertible until 10 years from the date of issuance. The number of conversion shares are adjusted pro-rata for any redemptions prior to conversion. Since the Series A shares can become redeemable at the option of the holder, but are not mandatorily redeemable, the Series A shares are classified as mezzanine equity. As discussed in Note 2 —  Summary of Significant Accounting Policies, the Company adopted ASU 2020-06, therefore the Company has reflected the carrying value of the Series A shares as $94.9 million within mezzanine equity on the Consolidated Balance Sheet of the Company as of December 31, 2020. In addition, management has determined it is probable the Company will exercise it redemption rights prior to the increase in cumulative

F-38

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

dividends after year five, therefore the carrying value of the shares is being accreted to redemption value over the expected five year period. During the year ended December 31, 2021, the Company recognized $3.7 million in related accretion.

During April of 2021, the Board of Directors of the Company declared a dividend payable to Common Stockholders which in turn required payment of the cumulative dividends on the Series A shares. During May of 2021, the Company paid $10.3 million in dividends to preferred stock shareholders. The dividend payment represented cumulative dividends for the period of December 15 through December 31, 2020, and the year ended December 31, 2021. In conjunction with the dividend, as required by the Series A shareholders agreement, the Company redeemed 501,000 shares of outstanding preferred stock for $6.1 million, of which $1.3 million represented a deemed dividend to Series A shareholders for required premiums paid upon redemption. The deemed dividend represents the difference between the redemption amount paid by the Company and the carrying value of the preferred stock prior to redemption and is reflected as such within the Consolidated Statement of Stockholders’ Equity for the year ended December 31, 2021.

On October 8, 2021, the Company notified the holders of the remaining outstanding shares of preferred stock their shares would be redeemed on October 18, 2021. The Company paid $115.1 million in order to redeem the remaining outstanding shares for preferred stock, of which $25.0 million represented a deemed dividend to preferred shareholders for required premiums paid upon redemption. The deemed dividend represents the difference between the redemption amount paid by the Company and the carrying value of the preferred stock prior to redemption and is reflected as such within the Consolidated Statement of Stockholders’ Equity for the year ended December 31, 2021.

As of December 31, 2021 and 2020, the Company had 0 and 9,900,000 shares of Series A shares issued and outstanding, respectively.

Treasury Stock

On October 18, 2021 the Company purchased 100,000 shares of its common stock in conjunction with the redemption of the remaining outstanding shares of Series A shares on the same date. The shares were repurchased for $1.1 million at a price of $11.06 per share.

As discussed in Note 11 — Equity-based Compensation, during the year ended December 31, 2021 the Company purchased 9,949 shares of its common stock for $0.1 million at a price of $11.06 per share.

During February, April and December of 2021, the Company purchased 275,393 shares of common stock from non-controlling management shareholders for $2.8 million at a price of $10.00 per share.

Note 13 — Equity Method Investment

On July 30, 2021, the Company completed the formation of a 50/50 joint venture named BKV-BPP Power, LLC (the “Joint Venture”) with BPP US. The Joint Venture was formed for the sole purpose of purchasing and operating a power plant and other related activity. During August 2021, the Company contributed $43.0 million to the Joint Venture in the form of a deposit for the purchase of the Temple I power plant (the “Power Plant”). On November 1, 2021 the Joint Venture completed the purchase of the Power Plant for $440.9 million. To complete the purchase on November 1, 2021, the Company contributed an additional $44.0 million, and BPP US contributed an equal $87.0 million. In addition to the contributions from the members of the Joint Venture, $141.0 million was provided from BPP US in the form of a term loan, and $141.0 million was provided by the Company’s majority shareholder BNAC also in the form of a term loan. Both term loans mature on November 1, 2023. Of the total $282.0 million term loans provided by affiliates, $15.0 million was for the purposes of working capital.

In December 2021, the Company entered into an Administrative Service Agreement (the “ASA”) with the Joint Venture. Under the ASA the Company provides certain services as required by the ASA and in

F-39

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

return receives an annual fee of $2.6 million until December 1, 2022, with options to extend. During the year ended December 31, 2021, the Company recognized $0.2 million of revenues related to the services provided under the ASA which is included in other revenues on the Consolidated Statements of Operations and Comprehensive Loss.

The Joint Venture is independently operated and jointly controlled by BKV Corp and BPP US through a Board of Directors consisting of eight members, four of which are appointed by BKV Corp. The remaining four members of the Board of Directors of the Joint Venture are appointed by BPP US. The Joint Venture was determined to be a variable interest entity due to its need for additional funding from its members. BKV Corp has not been determined to be the primary beneficiary of the Joint Venture; while the majority of the ability to influence the significant activities of the Joint Venture is controlled by the Board of Directors, certain rights to influence the significant activities of the Joint Venture have been retained solely by BPP US as defined by the Joint Venture’s LLC agreement. Accordingly, the equity method of accounting is used by BKV Corp to account for its interest in the Joint Venture. BKV Corp’s initial investment, including direct transaction costs, was $88.4 million, which represents the Company’s maximum exposure to loss from the investment.

During the year ended December 31, 2021, the Company recognized, based on its 50% ownership interest in the Joint Venture, earnings of $0.9 million for the period beginning November 1, 2021 through December 31, 2021.

The tables below sets forth the summarized financial information of the Joint Venture:

Balance Sheet (in thousands)	December 31, 2021
Current assets	​	$	35,957
Noncurrent assets	​	​	454,333
Total assets	​	$	490,290
Current liabilities	​	$	24,067
Noncurrent liabilities	​	​	290,440
Total liabilities	​	​	314,507
Members’ equity	​	​	175,783
Total liabilities and members’ equity	​	$	490,290

Income Statement (in thousands)	Period beginning November 1, 2021 through December 31, 2021
Revenues	​	$	20,186
Variable operating expenses	​	​	13,388
Gross Profit	​	​	6,798
Operating expenses	​	​	9,659
Loss from operations	​	​	(2,861)
Net income	​	$	1,819

Note 14 — Credit and Other Risk

Credit risk is defined as the risk of a counterparty to a contract failing to perform or pay the amounts due.

F-40

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

BKV is exposed to credit risks in its operating and financing activities. BKV’s maximum exposure to credit risk is partially related to financial assets recorded on the Consolidated Balance Sheets, including commodity derivative instruments that have a positive market value. Additionally, BKV maintains its primary bank accounts with a single large, global bank.

The Company is not currently aware of any exceptional event, dispute, risks or contingent liabilities that could have a material impact on the assets and liabilities, results, financial position or operations of the Company.

The Company is subject to U.S. federal income tax as well as income in various state jurisdictions, and the Company’s operating cash flow is sensitive to the amount of income taxes the Company must pay. In the jurisdictions in which the Company operates or previously operated, income taxes are assessed on earnings after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs that are considered allowable deductions (such as intangible drilling costs) and the timing of such deductions, or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow. In addition, new taxes are from time to time proposed and, if enacted, could adversely impact the Company.

Substantially all of the Company’s accounts receivable result from the sale of natural gas and joint interest billings. The Company sells natural gas, NGLs and oil to fewer than five customers and bills working interest owners for costs related to development of the Company’s natural gas properties. The Company does not believe that the loss of any of these customers would have a material adverse effect on the consolidated financial statements because alternative customers are readily available. As of December 31, 2021, one purchaser accounted for more than 10% of natural gas, NGL, and oil revenues and 10% of accounts receivables, respectively. As of December 31, 2020, one purchaser accounted for more than 10% of natural gas, NGL, and oil revenues and 10% of accounts receivables.

Note 15 — Commitments and Contingencies

From time to time, the Company may be subject to various claims, title matters and legal proceedings arising in the ordinary course of business, including environmental contamination claims, personal injury and property damage claims, claims related to joint interest billings and other matters under natural gas operating agreements and other contractual disputes. The Company maintains general liability and other insurance to cover some of these potential liabilities. All known liabilities are fully accrued based on the Company’s best estimate of the potential loss. While the outcome and impact on the Company cannot be predicted with certainty, the Company believes that its ultimate liability with respect to any such matters will not have a significant impact or material adverse effect on its financial positions, results of operations or cash flows. Results of operations and cash flows, however, could be significantly impacted in the reporting periods in which such matters are resolved.

The Company was involved in an arbitration against an operator related to the breach of various provisions of a certain agreement related to the construction and operation of a midstream gathering system. On February 18, 2022 the Company agreed to a settlement with the operator, and as a result, received payment of $35.0 million to settle all past disputes and agreed to a midstream gathering rate going forward. As of December 31, 2021, no accrual has been recorded in respect to the damages, interest and reimbursable fees or agreed upon rates. Of the $35.0 million, $18.1 million will be considered as collection of accounts receivable which is included in the Company’s Consolidated Balance Sheet as of December 31, 2021.

F-41

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

The Company has volume commitments in the form of gathering, processing and transportation agreements with various third-parties that require delivery of 1,060,029,489 Dth of natural gas. The majority of the agreements terminate by 2026, with one agreement extending through 2036. As of December 31, 2021, the aggregate undiscounted future payments required under these contracts total $256.2 million. The Company expects to fulfill the commitments from existing productive wells.

The Company has committed to spend $3.5 million on a field compression related capital project during the year ended December 31, 2022.

The Company may potentially be responsible for remitting lease related payments to certain leaseholders and has recorded a liability of approximately $5.7 million. Of the $5.7 million, $0.4 million was incurred during the year ended December 31, 2021. The Company will continue to evaluate these estimates and revise any recorded obligations and contingencies as necessary. During the year ended December 31, 2021, there was no change to the estimated value of $5.3 million of liabilities previously reported in the December 31, 2020 Consolidated Balance Sheet.

As a part of the consideration paid for the asset acquisition described in Note 3 — Natural Gas Properties & Other Property and Equipment, additional cash consideration will be required to be paid if certain hurdle rates are reached related to future average closing Henry Hub natural gas and West Texas Intermediate crude oil prices during the period beginning January 2021 through December 31, 2024. As of December 31, 2021, the 2021 portion of the arrangement is considered to be settled resulting in a settlement of $65.0 million which is reflected as contingent consideration payable within current liabilities on the Consolidated Balance Sheet as of December 31, 2021 and was paid on January 18, 2022. For the remaining years ending December 31, 2022 through 2024, average Henry Hub natural gas hurdle rates are $3.00/MMBTU, $3.25/MMBTU and $3.50/MMBTU, respectively; average West Texas Intermediate crude oil hurdle rates for the years ending December 31, 2022 through 2024 are $55.00/BBL, $60.00/BBL, and $65.00/BBL, respectively. The maximum amount payable under the arrangement is $195.0 million, or $65.0 million per year, for the years ending December 31, 2022-2024. Payments are due in the month following the end of the respective measurement period for which the hurdle rates are set. As described in Note 4 —  Fair Value Measurements, management uses NYMEX forward pricing estimates for both Henry Hub and West Texas Intermediate hurdle rates and Monte Carlo simulations to determine the fair value of the contingent consideration. As of December 31, 2021 and 2020, the Company’s estimate of the fair value of the unsettled contingent consideration was $142.5 million and $12.6 million, respectively. The change in the fair value of the contingent consideration from the acquisition date of October 1, 2020 through December 31, 2020, and for the year ended December 31, 2021 resulted in a reduction and an increase, respectively, to the associated liability on the Consolidated Balance Sheets and recognition of income and loss respectively, in the change in contingent purchase liabilities on the Consolidated Statement of Operations and Comprehensive Loss of $194.9 million and $7.1 million, respectively.

A summary of the Company’s commitments, excluding leases and contingent consideration, as of December 31, 2021, is provided in the following table:

(in thousands)	2022			2023			2024			2025			2026			Thereafter			Total
Notes payable to related party	​	$	166,000	​	$	—	​	$	—	​	$	—	​	$	—	​	$	—	​	$	166,000
Interest on notes	​	​	1,787	​	​	—	​	​	—	​	​	—	​	​	—	​	​	—	​	​	1,787
Capital commitment	​	​	3,500	​	​	—	​	​	—	​	​	—	​	​	—	​	​	—	​	​	3,500
Volume commitments	​	​	56,786	​	​	52,663	​	​	36,339	​	​	19,382	​	​	14,782	​	​	76,211	​	​	256,163
Total	​	$	228,073	​	$	52,663	​	$	36,339	​	$	19,382	​	$	14,782	​	$	76,211	​	$	427,450

F-42

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

Note 16 — Leases

The Company’s operating leases consist of leases for office space and compressors. The Company does not have finance type leases. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Instead, the short-term leases are recognized in expense on a straight-line basis over the lease term. Most leases include one or more options to renew, with renewal terms generally being one year, which are not recognized as part of the lease right-of-use (ROU) assets or liabilities as they are not reasonably certain to be exercised. The exercise of lease renewal options is at the discretion of the Company.

The Consolidated Statements of Operations and Comprehensive Loss include the following amounts for right-of-use-asset depreciation expense for the Company’s operating leases within the indicated line items:

​	Year ended December 31,
(in thousands)	2021			2020
Depreciation, depletion and amortization	​	$	389	​	$	360
Lease operating and workover expense	​	​	6,876	​	​	3,145
Total	​	$	7,265	​	$	3,505

As of December 31, 2021, the Company’s undiscounted minimum cash payment obligations for its operating lease liabilities are as follows (in thousands):

2022	$	11,241
2023	​	947
2024	​	959
2025	​	972
2026	​	848
Thereafter	​	1,664
Total undiscounted future lease payments	$	16,631
Present value adjustment	​	(1,226)
Net operating lease liabilities	$	15,405

As of December 31, 2021 and 2020, the Company’s operating leases had a weighted-average remaining lease term of 3.10 and 3.10 years, respectively, and a weighted-average discount rate of 5.06% and 5.14%, respectively. The discount rate used for operating leases is based on the Company’s incremental borrowing rate at lease commencement.

F-43

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

Note 17 — Income Taxes

The Company’s income tax (benefit) expense consisted of the following:

Tax (benefit) expense

​	Year ended December 31,
(in thousands)	2021			2020
Current tax expense	​	​	​	​	​	​
United States federal income tax	​	$	29,051	​	$	1,232
Various state income taxes	​	​	3,176	​	​	—
Total current income tax expense	​	​	32,227	​	​	1,232
Deferred tax (benefit) expense	​	​	​	​	​	​
United States federal income tax	​	​	(66,362)	​	​	37,750
Various state taxes	​	​	(6,391)	​	​	—
Total deferred income tax expense	​	​	(72,753)	​	​	37,750
Provision for income taxes	​	$	(40,526)	​	$	38,982

Income tax (benefit) expense differs from the amount that would be computed by applying the U.S. statutory federal income tax rate of 21.0% to loss before taxes as a result of the following:

Reconciliation of the Effective Tax Rate

​	Year ended December 31,
(in thousands)	2021			2020
Loss before income taxes	​	$	174,989	​	$	4,364
Statutory rate	​	​	21.0%	​	​	21.0%
Income tax recovery based on statutory rate	​	$	(36,748)	​	$	(916)
(Increase) decrease in income taxes resulting from:	​	​	​	​	​	​
State tax benefit, net of federal benefit	​	​	(4,114)	​	​	(148)
Change in state tax rate, net of federal effect	​	​	227	​	​	(8,793)
Deferred tax activity	​	​	(520)	​	​	45,627
Other, including tax credits	​	​	629	​	​	3,212
Income tax (benefit) expense	​	$	(40,526)	​	$	38,982

Deferred income taxes reflect the impact of temporary differences between assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. The tax effect of the temporary differences giving rise to net deferred tax assets and liabilities is as follows:

F-44

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

Recognized Deferred Income Tax Assets and Liabilities

​	As of December 31,
(in thousands)	2021			2020
Deferred tax assets	​	​	​	​	​	​
Fair value of derivative financial instruments	​	$	31,318	​	$	—
Asset retirement obligations	​	​	36,680	​	​	1,346
Stock compensation	​	​	6,592	​	​	—
Contingent consideration	​	​	49,193	​	​	—
Other	​	​	3,482	​	​	862
Total deferred tax asset	​	$	127,265	​	$	2,208
Deferred tax liabilities	​	​	​	​	​	​
Property and equipment	​	$	(87,554)	​	$	(37,040)
Investment in joint venture	​	​	(668)	​	​	—
Fair value of derivative financial instruments	​	​	—	​	​	(2,371)
Other	​	​	(3,539)	​	​	(46)
Total deferred tax liability	​	$	(91,761)	​	$	(39,457)
Net deferred tax asset (liability)	​	$	35,504	​	$	(37,249)

In assessing the realizability of deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more-likely-than-not standard of judgment. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the Company’s temporary differences become deductible. Management considers the scheduled reversal of deferred tax assets, projected future taxable income and tax planning strategies in making this assessment. Accordingly, as of December 31, 2021 and 2020, the Company has not recognized a valuation allowance against its deferred tax assets.

The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more-likely-than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities. The Company monitors potential uncertain tax positions but does not anticipate any changes during 2022. The Company has no unrecognized tax benefit balances as of December 31, 2021, and 2020. The Company is generally subject to potential federal and state examination for the tax years on and after December 31, 2020.

Note 18 — Corporatization Event

Prior to May 1, 2020 BKV O&G, a limited partnership registered with the state of Delaware, was the sole investor in Chaffee, Chelsea, Operating, and Barnett. Together, these consolidated entities were referred to as the “Limited Partnership.” The Limited Partnership’s general partner was Kalnin Capital Partners LP (the “General Partner”), and the Limited Partnership was managed by a related party of the General Partner, KV (the “Investment Manager”).

On May 1, 2020, the Limited Partnership’s limited partner, an international investor, and the General Partner agreed to restructure the Limited Partnership and incorporate the BKV Corp entity. As there was no change in control, the assets and liabilities continued to be recorded at their carrying amounts with no adjustment to fair value and the results of operations for these entities from the beginning of the year (January 1, 2020) are included in the Consolidated Statement of Operations and Comprehensive Loss for the year ended December 31, 2020. This transaction also resulted in the measurement and recognition of

F-45

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

minority ownership puttable common stock shares valued at $22.3 million which is reflected in the Mezzanine equity section of the Consolidated Balance Sheets as of December 31, 2020 and is further described in Note 4 — Fair Value Measurements and Note 12 — Stockholders’ Equity and Mezzanine Equity.

The Investment Manager was also merged into the new corporate structure through a business combination on May 1, 2020. Consideration of $20.0 million in the form of two million shares of common stock of the Company was paid for the acquisition of KV, in exchange for full ownership of KV resulting in the recognition of $18.4 million of goodwill which is reflected on the Consolidated Balance Sheets as of December 31, 2020. The business combination occurred to retain operational expertise of KV, the primary factor for the recognized goodwill. The shares issued for the acquisition of KV were recorded as minority ownership puttable shares with a value of $20.0 million, which is reflected in the Mezzanine equity section of the Consolidated Balance Sheets and is described further in Note 4 — Fair Value Measurements and Note 12 — Stockholders’ Equity and Mezzanine Equity. The transaction costs associated with the acquisition were not material due to the nature of the business combination.

The fair value of assets acquired and liabilities assumed are as follows (in thousands):

Total consideration	$	20,000
Assets acquired and liabilities assumed:	​	​
Cash	$	311
Accounts receivable	​	526
Other assets	​	753
Prepaid expenses	​	383
Other fixed assets	​	2,445
Right-of-use assets	​	3,980
Accounts payable and accrued expenses	​	(1,488)
Right-of-use liabilities	​	(5,327)
Total identifiable net assets	$	1,583
Goodwill	$	18,417

The accompanying Consolidated Statement of Operations and Comprehensive Loss includes activity of KV for the period beginning May 1, 2020 through December 31, 2020. KV does not independently generate revenues therefore there are no revenues or earnings(losses) included in the Company’s Consolidated Statement of Operations and Comprehensive Loss from the acquisition date of May 1, 2020 to December 31, 2020 directly attributable to KV.

Note 19 — Earnings Per Share

On May 1, 2020, as part of the corporatization event described in Note 18 — Corporatization Event, the Company issued 92,700,000 shares to the partners of BKV O&G in exchange for all the assigned units of BKV O&G. The ownership levels resulting from the issuance of shares of BKV Corp upon Corporatization were consistent with those of BKV O&G prior to Corporatization. Accordingly, weighted average shares outstanding for the year ended December 31, 2020 is calculated assuming the shares issued upon Corporatization were issued and outstanding as of January 1, 2020.

F-46

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

The following securities could potentially dilute earnings per share in the future, but were excluded from the computation of diluted net income (loss) per share, as their effect would have been antidilutive:

​	As of December 31,
(in thousands)	2021		2020
Equity-based compensation – TRSU	​	2,328	​	—
Equity-based compensation – PRSU non-market condition(1)	​	4,635	​	—
Equity-based compensation – PRSU market condition(1)	​	6,953	​	—
Preferred shares	​	—	​	34,849

(1)

Potentially dilutive share count for non-market and market conditions assumes maximum performance (see Note 11 — Equity-based compensation).

Note 20 — Subsequent Events

The Company has evaluated its subsequent events occurring after December 31, 2021 through August 12, 2022, which represents the date the consolidated financial statements are available to be issued. Except as outlined below, all such subsequent events are discussed with their relevant section within these notes to the consolidated financial statements. No further subsequent events have been identified.

On May 18, 2022, the Company entered into a Purchase and Sale Agreement (“PSA II”) to acquire certain operated and non-operated interests in proved reserves and certain midstream support assets in the Barnett formation from XTO Energy Inc. for $750.0 million and additional contingent payments totaling $50.0 million if certain pricing thresholds are met in future periods. The Company paid a deposit of $75.0 million to XTO Energy Inc. in conjunction with entering into PSA II. The Company closed the transaction on June 30, 2022; the adjusted purchase price, excluding contingent consideration was $627.5 million which included the $75.0 million deposit.

On June 16, 2022 the Company entered into a Credit Agreement with a syndicate of lenders (the “Lenders”) whereby the Company can borrow up to $600.0 million in the aggregate, in the form of multiple term loans during the period commencing with the effective date and ending six (6) months thereafter. The term loans under the Credit Agreement must be equal to or greater than $5.0 million; amounts repaid by the Company in respect to the term loans may not be re-borrowed under the Credit Agreement. Once drawn, the terms loans are required to be repaid annually in five equal installments. The term loans are not secured. On June 30, 2022, the Company drew a term loan of $570.0 million to fund the purchase of operated and non-operated interests in proved reserves and certain midstream support assets from XTO Energy, Inc. Interest is adjusted term SOFR + 4.75%. The proceeds of the term loans must be used to finance the aforementioned acquisition of assets from XTO Energy Inc.

Pursuant to an ISDA Master Agreement for derivative contracts (the “Master Agreement”) between the Company and the counterparty thereto (the “Counterparty”), the Company is subject to a covenant that restricts the Company from creating, issuing, incurring, or assuming additional indebtedness in excess of $75.0 million. In June 2022, the Company entered into a term loan credit agreement and borrowed $570.0 million of term loans thereunder. In connection with the Company’s exceeding this $75.0 million indebtedness threshold, on August 4, 2022, the Company executed the 3rd Amendment to the Master Agreement (the “3rd Amendment”) with the Counterparty. Pursuant to the 3rd Amendment, the Company is required to novate or terminate, at the election of the Company, $100.0 million in derivative contracts by October 4, 2022. The terminations or novations are required to apply first to derivative contracts that relate to the period beginning January 2023 and ending March 2023 prior to electing to terminate or novate other derivative contracts outside of that period. As of December 31, 2021, the fair market value of the derivative contracts with the Counterparty for the period beginning January 2023 and ending March 2023 was $7.8 million. To the extent the Company elects to terminate any such derivative contracts, the Company

F-47

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

will be required to make cash payments in the applicable amount to the Counterparty, which payments would be due in the aggregate by November 30, 2022. The 3rd Amendment also includes a cross default provision pursuant to which a default by the Company related to the covenants under the Company’s term loan credit agreement would cause a default under the Master Agreement. In addition, from and after such time that the Company satisfies the previously described obligations with respect to the novation or termination of such derivative contracts, the debt incurrence covenant in the Master Agreement would cease to apply.

Events Subsequent to Original Issuance of Financial Statements (Unaudited)

In connection with the reissuance of the Consolidated Financial Statements, the Company has evaluated subsequent events occurring after August 12, 2022, through October 25, 2022, the date the Consolidated Financial Statements were available to be reissued. All such subsequent events are outlined below.

From August 12, 2022, through the date the Consolidated Financial Statements were available for reissuance, the Company granted an additional 81,600 RSUs, comprised of 67,200 PRSUs (assuming maximum performance) and 14,400 TRSUs. Of the 14,400 TRSUs considered granted under ASC 718 Compensation-Stock Compensation, 10,800 are not considered legally granted, see Note 11 — Equity-Based Compensation.

With respect to the 3rd Amendment to the Master Agreement with the Counterparty, the Company terminated $100.2 million of derivative contracts through the date the Consolidated Financial Statements were available for reissuance. The Company is required to pay the $100.2 million of terminated derivative contracts by November 30, 2022. In addition, on October 18, 2022, the Company terminated $57.4 million of derivative contracts which is payable on March 31, 2023.

On August 1, 2022, the Company formed it’s wholly owned subsidiary BKVerde, LLC (“BKVerde”). On August 22, 2022, the Company entered into a management services agreement with a third party to provide general administrative and management services for carbon capture projects to BKVerde. Pursuant to the management services agreement, the Company is required to make quarterly payments of $2.0 million, beginning in August 2022 through February 2024. The agreement can be terminated with mutual consent from the Company and the third party. During this time period the third party will facilitate the administration and development of carbon capture projects.

On August 19, 2022, the Company received a cash advance from Facility II in the amount of $10.0 million.

On August 24, 2022, the Company entered into an agreement with another bank which provides for a revolving credit facility (“Facility III”) with a limit of $100.0 million. Facility III is an unsecured facility committed through September 30, 2027. Cash draw downs and all applicable interest is payable at one, three, or six months from the date of the advance (“one month draw”, “three month draw” and “six month draw”, respectively). The interest period is determined by the Company at the time of the advance. The interest rate on any outstanding advances is adjusted term SOFR + 4.75%. On September 14, 2022, the Company took a six month draw of $45.0 million and a one month draw of $30.0 million. As of the date the Consolidated Financial Statements were available for reissuance, the Company had $45.0 million outstanding under Facility III. The Company repaid the one month draw of $30.0 million on Facility III on October 14, 2022.

On September 16, 2022, the Company repaid $116.0 million originally borrowed from the Lender on October 14, 2021, see Note 7 — Related Parties.

From the date the Consolidated Financial Statements were originally issued through the reissuance date of October 25, 2022, the Company received advances, and repaid advances on the Facility. As of the

F-48

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

date the Consolidated Financial Statement were available for reissuance, the outstanding balance on the Facility was $45.0 million, see Note 8 — Credit Facilities.

Supplemental Oil and Gas Disclosures (unaudited)

The Company’s operating natural gas properties are located solely in the United States.

Net capitalized costs relating to oil and gas producing activities

The following table shows the capitalized costs of natural gas properties and the related accumulated depreciation, depletion and amortization:

​	As of December 31,
(In thousands)	2021			2020
Developed properties	​	$	1,378,629	​	​	1,297,144
Undeveloped properties	​	​	16,835	​	​	13,265
Total capitalized costs	​	​	1,395,464	​	​	1,310,409
Less: Accumulated depreciation, depletion, and amortization	​	​	(267,293)	​	​	(190,356)
Net capitalized costs	​	$	1,128,171	​	$	1,120,053

Costs incurred in natural gas and oil exploration and development

The table below sets forth capitalized costs incurred in natural gas property acquisition, exploration and development activities:

​	As of December 31,
(In thousands)	2021			2020
Undeveloped property acquisition costs	​	$	3,569	​	​	2,064
Acquisitions	​	​	2,928	​	​	624,914
Development costs	​	​	77,634	​	​	10,711
Total cost incurred	​	​	84,131	​	​	637,689
Asset retirement obligations	​	​	923	​	​	772
Total costs incurred including asset retirement obligations	​	$	85,054	​	$	638,461

Natural gas, NGL and oil reserve quantities

Estimates of total proved reserves at December 31, 2021 and December 31, 2020 was based on studies performed by the Company’s internal engineering function, and Ryder Scott, the Company’s third-party reserve engineer. The estimates were computed using the 12-month average index price, calculated as the unweighted arithmetic average for the first day of the month price for each month during the respective year. The estimates were prepared by the Company’s independent third party engineers, Ryder Scott. The process of estimating quantities of “proved” and “proved developed” natural gas, NGL and oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data. The process also includes estimating the net cost of abandonment after salvage and was estimated and included for all properties for which an asset retirement obligation exists. The data may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent

F-49

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

the most accurate assessments possible, the subjective decisions and variances in available data make these estimates generally less precise than other estimates included within the consolidated financial statements.

The following table illustrates the Company’s net proved reserves, including changes, as well as proved and proved undeveloped reserves for the periods presented, as estimated by the Company’s engineering function. All reserves are located within the continental United States:

​	Natural Gas (MMcf)		NGL (MBbls)		Oil (MBbls)		Total (MMcfe)
January 1, 2020	​	948,801	​	—	​	—	​	948,801
Revision of previous estimates	​	(382,366)	​	(21)	​	(3)	​	(382,510)
Extensions and discoveries	​	—	​	—	​	—	​	—
Purchase of minerals in place	​	1,515,255	​	109,820	​	755	​	2,178,705
Improved recoveries	​	—	​	—	​	—	​	—
Production	​	(96,158)	​	(2,565)	​	(29)	​	(111,722)
December 31, 2020	​	1,985,532	​	107,234	​	723	​	2,633,274
Revision of previous estimates	​	828,360	​	45,234	​	258	​	1,101,312
Extensions and discoveries	​	645,338	​	13,722	​	58	​	728,018
Purchase of minerals in place	​	19,511	​	—	​	—	​	19,511
Improved recoveries	​	152,597	​	8,794	​	9	​	205,415
Production	​	(186,055)	​	(9,829)	​	(123)	​	(245,767)
December 31, 2021	​	3,445,283	​	165,155	​	925	​	4,441,763

​	Natural Gas (MMcf)		NGL (MBbls)		Oil (MBbls)		Total (MMcfe)
Proved developed reserves as of:	​	​	​	​	​	​	​	​
January 1, 2020	​	523,240	​	—	​	—	​	523,240
December 31, 2020	​	1,893,158	​	107,234	​	723	​	2,540,900
December 31, 2021	​	2,494,925	​	151,433	​	867	​	3,408,725
Proved undeveloped reserves as of:	​	​	​	​	​	​	​	​
January 1, 2020	​	425,561	​	—	​	—	​	425,561
December 31, 2020	​	92,374	​	​	​	​	​	92,374
December 31, 2021	​	950,358	​	58	​	13,722	​	1,033,038

2021 Activity

During the year ended December 31, 2021, the Company’s proved reserves increased by 1,808.5 Bcfe. The increase in proved reserves was primarily due to increasing commodity pricing improving economics, and additions to the drilling schedule for both proved developed and undeveloped reserves. The Company produced 245.8 Bcfe during the year ended December 31, 2021.

Revisions of previous estimates — Primarily consisted of upward revisions to proved developed reserves, and proved undeveloped reserves of 715.9 Bcfe and 245.6 Bcfe, respectively, as a result of higher average pricing during 2021 for natural gas, NGLs and oil. The remaining upward adjustment of 139.8 Bcfe relates to upward performance adjustments of 219.2 Bcfe offset by a downward revision of 79.4 Bcfe due to increased production costs.

Extensions and discoveries — Upon completing our evaluation of properties acquired through our Barnett Asset Acquisition, 550.1 Bcfe of proved undeveloped reserves was recognized for 123 gross (94.8 net) locations added to the Company’s revised drilling schedule during 2021.Additional extensions consisted of proved undeveloped reserves of 143.2 Bcfe related to 13.0 gross (9.6 net) locations in the Marcellus Basin

F-50

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

recognized from acquired acreage and the revised 2021 drilling plan. Extensions related to proved developed reserves of 34.8 Bcfe consisted of 14 gross (5.9 net) newly drilled wells.

Improved recoveries — Consisted of 205.4 Bcfe of proved undeveloped reserves recognized as a result of the application of improved recovery techniques to producing wells during the year ended December 31, 2021.

2020 Activity

During the year ended December 31, 2020, the Company’s proved reserves increased by 1,684.5 Bcfe. The increase in proved reserves was due to the Barnett Asset Acquisition offset by downward revisions primarily due to lower average pricing for natural gas during 2020.The Company produced 111.7 Bcfe during the year ended December 31, 2020.

Revisions of previous estimates — Primarily consisted of a downward revision of 83.0 Bcfe due to a combination of performance adjustments and lower average pricing of natural gas during 2020, and a downward revision of 171.5 Bcfe which removed locations due to lower average pricing of natural gas during 2020. Proved developed reserves were adjusted downward by 127.4 Bcfe due to lower average natural gas prices and performance.

Extensions and discoveries — There were no extensions and discoveries of proved developed or proved undeveloped reserves during the year ended December 31, 2020.

Standardized Measure of Discounted Future Net Cash Flows

The following information has been developed based on natural gas, NGL and oil reserve and production volumes estimated by the Company’s engineering function. It can be used for some comparisons but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Natural Gas Reserves (“Standardized Measure”) be viewed as representative of the current value of the Company.

The following table details the Standardized Measure related to proved reserve as of the periods presented:

Future cash flows

​	As of December 31,
(in thousands)	2021			2020
Future cash inflows	​	$	15,029,839	​	$	4,414,787
Future production costs	​	​	(6,840,969)	​	​	(2,954,242)
Future development costs(1)	​	​	(1,051,911)	​	​	(333,804)
Income tax expense	​	​	(1,501,984)	​	​	(98,882)
Future net cash flows	​	​	5,634,975	​	​	1,027,859
10% annual discount for estimated timing of cash flows	​	​	(3,222,086)	​	​	(517,449)
Standardized measure of discounted future net cash flows related to proved reserves	​	$	2,412,889	​	$	510,410

(1)

Includes abandonment costs.

The following table summarizes the changes in the Standardized Measure for the years ended December 31, 2021 and 2020:

F-51

BKV Corporation

Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020

​	For the Years Ended December 31,
(in thousands)	2021			2020
Balance, beginning of period	​	$	510,410	​	$	406,824
Net change in sales and transfer prices and in production (lifting) costs related to future production	​	​	1,768,893	​	​	(284,282)
Changes in estimated future development costs	​	​	(393,235)	​	​	114,330
Sales and transfers of natural gas, NGLs and oil produced during the period	​	​	(522,403)	​	​	(83,783)
Net change due to extensions, discoveries and improved recovery	​	​	183,332	​	​	—
Purchase of minerals in place	​	​	19,050	​	​	513,183
Net change due to revisions in quantity estimates	​	​	1,266,086	​	​	(161,762)
Previously estimated development costs incurred during the period	​	​	60,406	​	​	13,540
Net change in future income taxes	​	​	(611,031)	​	​	(50,548)
Accretion of discount	​	​	56,096	​	​	40,682
Changes in timing and other	​	​	75,285	​	​	2,226
Total discounted cash flow as end of period	​	$	2,412,889	​	$	510,410

F-52

BKV Corporation

Condensed Consolidated Balance Sheets
(In thousands, except per share amounts)
(Unaudited)

​	June 30, 2022			December 31, 2021
Assets	​	​	​	​	​	​
Current assets	​	​	​	​	​	​
Cash and cash equivalents	​	$	169,161	​	$	134,667
Restricted cash	​	​	17,473	​	​	—
Accounts receivable, net	​	​	136,135	​	​	104,143
Accounts receivable, related parties	​	​	3,394	​	​	3,498
Commodity derivative assets	​	​	—	​	​	9,986
Other current assets	​	​	9,061	​	​	9,084
Total current assets	​	​	335,224	​	​	261,378
Natural gas properties and equipment	​	​	​	​	​	​
Developed properties	​	​	2,140,675	​	​	1,378,629
Undeveloped properties	​	​	16,827	​	​	16,835
Midstream assets	​	​	310,259	​	​	55,363
Accumulated depreciation, depletion, and amortization	​	​	(309,872)	​	​	(274,710)
Total natural gas properties, net	​	​	2,157,889	​	​	1,176,117
Other property and equipment, net	​	​	30,449	​	​	22,124
Right of use assets	​	​	9,862	​	​	14,233
Goodwill	​	​	18,417	​	​	18,417
Investment in joint venture	​	​	65,434	​	​	89,320
Deferred tax asset	​	​	18,023	​	​	35,504
Other noncurrent assets	​	​	7,097	​	​	3,735
Total assets	​	$	2,642,395	​	$	1,620,828
Liabilities, mezzanine equity and stockholders’ equity	​	​	​	​	​	​
Current liabilities	​	​	​	​	​	​
Accounts payable and accrued liabilities	​	$	243,523	​	$	166,836
Right of use liabilities	​	​	6,518	​	​	10,713
Commodity derivative liabilities	​	​	242,253	​	​	91,156
Notes payable to related party	​	​	—	​	​	166,000
Current portion of long-term debt, net	​	​	141,903	​	​	—
Other current liabilities	​	​	100,082	​	​	95,660
Total current liabilities	​	​	734,279	​	​	530,365
Asset retirement obligations	​	​	209,279	​	​	158,968
Commodity derivative liabilities	​	​	62,715	​	​	23,662
Notes payable to related party	​	​	191,000	​	​	—
Long-term debt, net	​	​	451,491	​	​	—
Other noncurrent liabilities	​	​	139,233	​	​	152,894
Total liabilities	​	​	1,787,997	​	​	865,889

F-53

BKV Corporation

Condensed Consolidated Balance Sheets
(In thousands, except per share amounts)
(Unaudited)

​	June 30, 2022			December 31, 2021
Commitments and contingencies (Note 14)	​	​	​	​	​	​
Mezzanine equity	​	​	​	​	​	​
Common stock – Minority ownership puttable shares; 4,580 authorized shares; 4,580 and 4,357 shares issued and outstanding at June 30, 2022 and December 31, 2021, respectively	​	​	71,286	​	​	49,841
Equity-based compensation	​	​	81,577	​	​	34,006
Total mezzanine equity	​	​	152,863	​	​	83,847
Stockholders’ equity	​	​	​	​	​	​
Common stock, $.01 par value; 300,000 authorized shares; 112,745 and 112,745 shares issued and outstanding at June 30, 2022 and December 31, 2021, respectively	​	​	1,132	​	​	1,132
Treasury stock, shares at cost; 385 shares and 385 shares at June 30, 2022 and December 31, 2021, respectively	​	​	(3,970)	​	​	(3,970)
Additional paid-in capital	​	​	883,766	​	​	933,622
Accumulated deficit	​	​	(179,393)	​	​	(259,692)
Total stockholders’ equity	​	​	701,535	​	​	671,092
Total liabilities, mezzanine equity and stockholders’ equity	​	$	2,642,395	​	$	1,620,828

F-54

BKV Corporation

Condensed Consolidated Statements of Operations and
Comprehensive Income (Loss)
(In thousands, except per share amounts)
(Unaudited)

​

Three Months Ended June 30,

Six Months Ended June 30,

​

2022

2021

2022

2021

Revenues and other operating income

​

​

​

​

​

​

​

​

​

​

​

​

Natural gas, NGL and oil sales

​

$

383,513

​

$

153,117

​

$

656,431

​

$

289,342

Non-operated midstream revenues

​

​

1,459

​

​

1,896

​

​

3,344

​

​

3,972

Derivative losses, net

​

​

(85,953)

​

​

(141,563)

​

​

(450,784)

​

​

(178,275)

Marketing revenues

​

​

1,661

​

​

1,575

​

​

5,328

​

​

50,296

Other

​

​

664

​

​

—

​

​

1,327

​

​

—

Total revenues and other operating income

​

​

301,344

​

​

15,025

​

​

215,646

​

​

165,335

Operating expenses

​

​

​

​

​

​

​

​

​

​

​

​

Lease operating and workover

​

​

22,642

​

​

18,711

​

​

45,333

​

​

40,515

Taxes other than income

​

​

23,072

​

​

9,631

​

​

41,001

​

​

16,697

Gathering and transportation

​

​

51,140

​

​

48,778

​

​

98,756

​

​

76,756

Accretion of asset retirement obligations

​

​

2,695

​

​

2,486

​

​

5,320

​

​

4,904

Depreciation, depletion and amortization

​

​

18,103

​

​

20,357

​

​

36,800

​

​

40,842

Exploration and impairment

​

​

—

​

​

34

​

​

—

​

​

34

General and administrative

​

​

27,231

​

​

16,219

​

​

51,497

​

​

37,988

Accretion of right of use liabilities

​

​

56

​

​

63

​

​

135

​

​

106

Total operating expenses

​

​

144,939

​

​

116,279

​

​

278,842

​

​

217,842

Income (loss) from operations

​

​

156,405

​

​

(101,254)

​

​

(63,196)

​

​

(52,507)

Other income and expense

​

​

​

​

​

​

​

​

​

​

​

​

Loss on contingent consideration liabilities

​

​

(1,399)

​

​

(82,295)

​

​

(31,915)

​

​

(115,345)

Interest expense

​

​

(4,308)

​

​

(44)

​

​

(6,698)

​

​

(314)

Other income

​

​

153

​

​

50

​

​

516

​

​

62

Bargain purchase gain

​

​

163,653

​

​

—

​

​

163,653

​

​

—

Gain on settlement of litigation

​

​

—

​

​

—

​

​

16,866

​

​

—

Loss from equity affiliates

​

​

(10,333)

​

​

—

​

​

(23,958)

​

​

—

Interest income

​

​

116

​

​

—

​

​

128

​

​

2

Income (loss) before income taxes

​

​

304,287

​

​

(183,543)

​

​

55,396

​

​

(168,102)

Income tax benefit (expense)

​

​

(31,639)

​

​

42,203

​

​

24,903

​

​

38,648

Net income (loss) and comprehensive income (loss) attributable to BKV Corp

​

​

272,648

​

​

(141,340)

​

​

80,299

​

​

(129,454)

Less accretion of preferred stock to redemption value

​

​

—

​

​

(1,181)

​

​

—

​

​

(2,336)

Less preferred stock dividends

​

​

—

​

​

(7,425)

​

​

—

​

​

(9,900)

Less deemed dividend on redemption of preferred stock

​

​

—

​

​

(1,353)

​

​

—

​

​

(1,353)

Net income (loss) and comprehensive income (loss) attributable to common stockholders

​

$

272,648

​

$

(151,299)

​

$

80,299

​

$

(143,043)

F-55

BKV Corporation

Condensed Consolidated Statements of Operations and
Comprehensive Income (Loss)
(In thousands, except per share amounts)
(Unaudited)

​

Three Months Ended June 30,

Six Months Ended June 30,

​

2022

2021

2022

2021

Net income (loss) and comprehensive income (loss) per common share:

​

​

​

​

​

​

​

​

​

​

​

​

Basic

​

$

2.32

​

$

(1.29)

​

$

0.68

​

$

(1.22)

Diluted

​

$

2.19

​

$

(1.29)

​

$

0.65

​

$

(1.22)

Weighted average number of common shares outstanding:

​

​

​

​

​

​

​

​

​

​

​

​

Basic

​

​

117,318

​

​

116,996

​

​

117,310

​

​

117,052

Diluted

​

​

124,445

​

​

116,996

​

​

123,221

​

​

117,052

F-56

BKV Corporation

Condensed Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)

​	Six Months Ended June 30,
​	2022			2021
Cash flows from operating activities:	​	​	​	​	​	​
Net income (loss)	​	$	80,299	​	$	(129,454)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	​	​	​	​	​	​
Depreciation, depletion and amortization	​	​	42,174	​	​	43,856
Equity-based compensation expense	​	​	20,254	​	​	10,854
Accretion of asset retirement obligations	​	​	5,320	​	​	4,904
Accretion of right of use liabilities	​	​	353	​	​	172
Amortization of debt issuance costs	​	​	24	​	​	—
Deferred income tax benefit	​	​	(32,308)	​	​	(69,385)
Unrealized loss on derivatives	​	​	200,136	​	​	156,218
Loss on contingent purchase liabilities	​	​	31,915	​	​	115,345
Settlement of contingent consideration	​	​	(45,300)	​	​	—
Gain on bargain purchase	​	​	(163,653)	​	​	—
Loss from equity affiliates	​	​	23,958	​	​	—
Changes in operating assets and liabilities:	​	​	​	​	​	​
Accounts receivable	​	​	(31,992)	​	​	13,930
Accounts receivable, related parties	​	​	104	​	​	—
Accounts payable and accrued liabilities	​	​	(16,098)	​	​	27,239
Commodity derivative settlements payable/receivable	​	​	44,543	​	​	18,034
Other changes in assets and liabilities	​	​	1,029	​	​	25,973
Net cash provided by operating activities	​	​	160,758	​	​	217,686
Cash flows from investing activities:	​	​	​	​	​	​
Business combination	​	​	(627,527)	​	​	—
Development of natural gas properties	​	​	(77,278)	​	​	(9,787)
Other investing activities	​	​	(986)	​	​	(4,377)
Net cash used in investing activities	​	​	(705,791)	​	​	(14,164)
Cash flows from financing activities:	​	​	​	​	​	​
Proceeds from notes payable from related party	​	​	75,000	​	​	—
Payments on notes payable to related party	​	​	(50,000)	​	​	(24,000)
Proceeds under term loan agreement	​	​	570,000	​	​	—
Payment of debt issuance costs	​	​	(6,630)	​	​	—
Draws on credit facility	​	​	60,000	​	​	—
Payments on credit facility	​	​	(30,000)	​	​	—
Settlement of contingent consideration	​	​	(19,700)	​	​	—
Payments of deferred offering costs	​	​	(576)	​	​	—
Redemption of minority ownership puttable shares	​	​	—	​	​	(2,226)

F-57

BKV Corporation

Condensed Consolidated Statements of Cash Flows
(In thousands)
(Unaudited)

​	Six Months Ended June 30,
​	2022			2021
Issuance of minority ownership puttable shares	​	​	78	​	​	—
Dividends paid to preferred stock shareholders	​	​	—	​	​	(10,330)
Redemption of preferred stock	​	​	—	​	​	(6,138)
Dividends paid to common stock shareholders	​	​	—	​	​	(88,126)
Net share settlements, equity-based compensation	​	​	(1,172)	​	​	—
Net cash provided by (used in) financing activities	​	​	597,000	​	​	(130,820)
Net increase in cash, cash equivalents and restricted cash	​	​	51,967	​	​	72,702
Cash, cash equivalents and restricted cash, beginning of period	​	​	134,667	​	​	17,445
Cash, cash equivalents and restricted cash, end of period	​	$	186,634	​	$	90,147
Supplemental cash flow information:	​	​	​	​	​	​
Cash payments for:	​	​	​	​	​	​
Interest	​	$	4,711	​	$	360
Income tax	​	$	400	​	$	—
Non-cash investing and financing activities:	​	​	​	​	​	​
Decrease in accrued capital expenditures	​	$	(19,844)	​	$	(5,020)
Additions to asset retirement obligations	​	$	261	​	$	—
Additions to right of use assets and liabilities	​	$	1,218	​	$	1,692
Deferred offering costs included in accounts payable and accrued liabilities	​	$	2,746	​	$	—
Fair value of contingent consideration from business combination	​	$	17,150	​	$	—
Adjustment of minority ownership puttable shares to redemption value	​	$	21,367	​	$	—
Adjustment of equity-based compensation to redemption value	​	$	28,489	​	$	—
Accretion of preferred stock to redemption value	​	$	—	​	$	2,335

F-58

BKV Corporation

Condensed Consolidated Statements of Stockholders’ Equity and
Mezzanine Equity
(In thousands, except per share amounts)
(Unaudited)

​

Stockholders’ Equity

Mezzanine Equity

​

Common Stock

Treasury

Additional Paid-In Capital

Accumulated Deficit

Total Stockholders’ Equity

Common Stock

Equity-based Compensation

Total Mezzanine Equity

​

Shares

Amount

Shares

Amount

Balances, December 31, 2021

​

112,745

​

$

1,132

​

$

(3,970)

​

$

933,622

​

$

(259,692)

​

$

671,092

​

4,357

​

$

49,841

​

$

34,006

​

$

83,847

Net loss

​

—

​

​

—

​

​

—

​

​

—

​

​

(192,349)

​

​

(192,349)

​

—

​

​

—

​

​

—

​

​

—

Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

200

​

​

—

​

​

(1,054)

​

​

(1,054)

Adjustment of minority ownership puttable shares to redemption value

​

—

​

​

—

​

​

—

​

​

(14,956)

​

​

—

​

​

(14,956)

​

—

​

​

14,956

​

​

—

​

​

14,956

Adjustment of equity-based compensation to redemption value

​

—

​

​

—

​

​

—

​

​

(25,218)

​

​

—

​

​

(25,218)

​

—

​

​

—

​

​

25,218

​

​

25,218

Equity-based compensation

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

—

​

​

—

​

​

11,425

​

​

11,425

Balances, March 31, 2022

​

112,745

​

$

1,132

​

$

(3,970)

​

$

893,448

​

$

(452,041)

​

$

438,569

​

4,557

​

$

64,797

​

$

69,595

​

$

134,392

Net income

​

—

​

​

—

​

​

—

​

​

—

​

​

272,648

​

​

272,648

​

—

​

​

—

​

​

—

​

​

—

Issuance of common stock from employee stock purchase plan

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

5

​

​

78

​

​

—

​

​

78

Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income taxes

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

18

​

​

—

​

​

(118)

​

​

(118)

Adjustment of minority ownership puttable shares to redemption value

​

—

​

​

—

​

​

—

​

​

(6,411)

​

​

—

​

​

(6,411)

​

—

​

​

6,411

​

​

—

​

​

6,411

Adjustment of equity-based compensation to redemption value

​

—

​

​

—

​

​

—

​

​

(3,271)

​

​

—

​

​

(3,271)

​

—

​

​

—

​

​

3,271

​

​

3,271

Equity-based compensation

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

—

​

​

—

​

​

8,829

​

​

8,829

Balances, June 30, 2022

​

112,745

​

$

1,132

​

$

(3,970)

​

$

883,766

​

$

(179,393)

​

$

701,535

​

4,580

​

$

71,286

​

$

81,577

​

$

152,863

F-59

BKV Corporation

Condensed Consolidated Statements of Stockholders’ Equity and
Mezzanine Equity
(In thousands, except per share amounts)
(Unaudited)

​

Stockholders’ Equity

Mezzanine Equity

​

Common Stock

Treasury

Additional Paid-In Capital

Accumulated Deficit

Total Stockholders’ Equity

Preferred Stock

Common Stock

Total Mezzanine Equity

​

Shares

Amount

Shares

Amount

Balances, December 31, 2020

​

112,855

​

$

1,129

​

​

—

​

$

968,500

​

$

(26,773)

​

$

942,856

​

$

94,924

​

4,229

​

$

42,288

​

$

137,212

Net Income

​

—

​

​

—

​

​

—

​

​

—

​

​

11,886

​

​

11,886

​

​

—

​

—

​

​

—

​

​

—

Redemption of minority ownership puttable shares

​

—

​

​

2

​

​

(1,560)

​

​

1,558

​

​

—

​

​

—

​

​

—

​

(156)

​

​

(1,560)

​

​

(1,560)

Accretion of preferred stock to redemption value

​

—

​

​

—

​

​

—

​

​

(1,154)

​

​

—

​

​

(1,154)

​

​

1,154

​

—

​

​

—

​

​

1,154

Balances, March 31, 2021

​

112,855

​

​

1,131

​

​

(1,560)

​

​

968,904

​

​

(14,887)

​

​

953,588

​

​

96,078

​

4,073

​

​

40,728

​

​

136,806

Net loss

​

—

​

​

—

​

​

—

​

​

—

​

​

(141,340)

​

​

(141,340)

​

​

—

​

—

​

​

—

​

​

—

Dividend declared, preferred stock shareholders ($0.25 per share)

​

—

​

​

—

​

​

—

​

​

—

​

​

(10,330)

​

​

(10,330)

​

​

—

​

—

​

​

—

​

​

—

Dividend declared ($0.75 per share)

​

—

​

​

—

​

​

—

​

​

—

​

​

(88,126)

​

​

(88,126)

​

​

—

​

—

​

​

—

​

​

—

Redemption of minority ownership puttable shares

​

—

​

​

6

​

​

(666)

​

​

660

​

​

—

​

​

—

​

​

—

​

(67)

​

​

(666)

​

​

(666)

Redemption of preferred stock

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

—

​

​

(4,785)

​

—

​

​

—

​

​

(4,785)

Deemed dividend, preferred stock shareholders

​

—

​

​

—

​

​

—

​

​

(1,353)

​

​

—

​

​

(1,353)

​

​

—

​

—

​

​

—

​

​

—

Accretion of preferred stock to redemption value

​

—

​

​

—

​

​

—

​

​

(1,181)

​

​

—

​

​

(1,181)

​

​

1,181

​

—

​

​

—

​

​

1,181

Balances, June 30, 2021

​

112,855

​

$

1,137

​

$

(2,226)

​

$

967,030

​

$

(254,683)

​

$

711,258

​

$

92,474

​

4,006

​

$

40,062

​

$

132,536

F-60

BKV Corporation

Notes to the Condensed Consolidated Financial Statements
(Unaudited)

Note 1 — General Information

General

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

The majority shareholder of BKV Corp is Banpu North America Corporation (“BNAC”), which owns 96.1% of BKV Corp’s shares of common stock. BKV Corp’s ultimate parent company is Banpu Public Company Limited, a public company listed in the Stock Exchange of Thailand. The remaining 3.9% of shares of common stock of BKV Corp are owned by non-controlling management, director, employee and non-employee shareholders who hold shares with contingent put rights that may be exercised according to conditions stipulated in the Shareholders’ Agreement.

Basis of Presentation of the Unaudited Condensed Consolidated Financial Statements

These unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The condensed consolidated financial statements are unaudited and should be read in conjunction with the Company’s 2021 and 2020 Consolidated Financial Statements (“Annual Financial Statements”) as certain disclosures and information required by GAAP for complete consolidated financial statements has been condensed or omitted. The unaudited interim financial statements, in the opinion of management, reflect all adjustments, which include normal and recurring adjustments, necessary to fairly state the Company’s financial position as of June 30, 2022, and the results of operations and comprehensive income (loss) for the three and six months ended June 30, 2022 and 2021, and cash flows for the six months ended June 30, 2022 and 2021. The results for the six months ended June 30, 2022, are not necessarily indicative of results to be expected for the year ending December 31, 2022 or for any other future annual or interim period. The December 31, 2021 condensed consolidated balance sheet was derived from audited consolidated financial statements, but does not include all disclosures required by GAAP.

These condensed consolidated financial statements include BKV Corp and its wholly owned subsidiaries which include:

•

Kalnin Ventures LLC, a limited liability company formed September 19, 2013 and registered with the State of Colorado;

•

BKV Oil and Gas Capital Partners, L.P. (“BKV O&G”), a limited partnership formed June 1, 2015 with the State of Delaware;

•

BKV Chaffee Corners, LLC (“Chaffee”), a limited liability company formed March 28, 2016, wholly owned subsidiary of BKV O&G, and registered with the State of Delaware;

•

BKV Chelsea, LLC (“Chelsea”), a limited liability company formed November 10, 2016, wholly owned subsidiary of BKV O&G, and registered with the State of Delaware;

•

BKV Operating, LLC (“Operating”), a limited liability company formed October 12, 2017, wholly owned subsidiary of BKV O&G, and registered with the State of Delaware; and

•

BKV Barnett, LLC (“Barnett”), a limited liability company formed December 5, 2019, wholly owned subsidiary of BKV O&G, and registered with the State of Delaware.

•

BKV Midstream, LLC (“Midstream”), a limited liability company formed March 31, 2022 and registered with the State of Delaware.

F-61

•

BKV North Texas, LLC (“North Texas”), a limited liability company formed March 31, 2022 and registered with the State of Delaware.

•

BKV dCarbon Ventures, LLC (“BKV dCarbon Ventures”), a limited liability company formed May 31, 2022 and registered with the State of Delaware;

•

BKVerde, LLC (“BKVerde”), a limited liability company formed August 1, 2022, wholly owned subsidiary of BKV dCarbon Ventures, and registered with the State of Delaware.

Together, BKV Corp and its wholly owned subsidiaries are referred to collectively as “BKV” or the “Company.” All intercompany balances and transactions between these entities have been eliminated within the condensed consolidated financial statements.

Significant Judgments and Accounting Estimates

The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the financial statements and the accompanying notes. There have been no significant changes to the Company’s accounting estimates from those disclosed in the Company’s Annual Financial Statements.

Deferred Offering Costs

The Company has capitalized legal and other third-party fees directly related to the Company’s planned initial public offering (“IPO”). The deferred offering costs will be recorded as a reduction of the proceeds received from the planned offering. If the IPO is abandoned or significantly delayed, the deferred offering costs will be expensed. As of December 31, 2021, the Company had no deferred offering costs that were capitalized. As of June 30, 2022, the Company capitalized $3.3 million of deferred offering costs, which are included within other noncurrent assets on the condensed consolidated balance sheets.

Restricted Cash

Restricted cash as of June 30, 2022 consisted of cash borrowed under the Company’s credit agreement contractually obligated to be used for the Exxon Barnett Acquisition (as defined in Note 2 — Acquisition). The Company anticipates the restricted cash will be used for remaining transaction and integration costs. See Note 2 — Acquisition and Note 8 — Debt for further discussion.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash to amounts shown in the statement of cash flows:

​	As of June 30,
(in thousands)	2022			2021
Cash and cash equivalents	​	​	169,161	​	​	90,147
Restricted cash	​	​	17,473	​	​	—
Total cash, cash equivalents and restricted cash	​	$	186,634	​	$	90,147

Common Shares issued and outstanding

As of June 30, 2022 and December 31, 2021, the Company had 117,325,417 and 117,102,214 common shares issued and outstanding, respectively.

Liquidity

As of June 30, 2022, the Company held $169.2 million of unrestricted cash in operating accounts. The Company’s working capital deficit as of June 30, 2022 is $399.1 million, which is primarily driven by current commodity derivative liabilities of $242.3 million, the current portion of long-term debt of $141.9 million, and contingent consideration payable of $62.5 million. For the six months ended June 30, 2022, the Company’s cash flows from operations was $160.8 million. The payments relating to the contingent consideration and term loans are due in January and June of 2023, respectively. The Company intends to make these payments

F-62

with cash flows from existing and newly acquired operations and availability under existing and newly entered into debt facilities. The current derivative liabilities will settle monthly during the twelve month period ending June 30, 2023 in conjunction with the corresponding commodity sales other than the $100.2 million discussed below. The Company intends to use the proceeds from the corresponding commodity sales to pay the settlements of the derivative liabilities.

On August 4, 2022, the Company entered an amendment to its ISDA Master Agreement with a counterparty to its derivative contracts pursuant to which the Company has terminated, $100.2 million of its derivative contracts with the counterparty. The Company is required to make cash payments in an amount of $100.2 million, which are due in the aggregate by November 30, 2022. The Company intends to make such payments with cash flows from operations.

On September 14, 2022, the Company received an advance of $45.0 million from its Facility (defined in Note 8 — Debt) and drew $75.0 million on Facility III (defined in Note 8 — Debt), which are payable within six months of the date the condensed consolidated financial statements are available for issuance. See Note 8 — Debt. The Company intends to pay both the advance and the draw with cash flows from operations.

Significant Accounting Policies

The Company’s significant accounting policies are described in the notes to the consolidated financial statements for the year ended December 31, 2021 included in the Company’s Annual Financial Statements. There have been no significant changes in accounting policies during the six months ended June 30, 2022.

Recently Issued Accounting Standards

As of June 30, 2022 and through the date the condensed consolidated financial statements were available for issuance (see Note 17 — Subsequent Events), no other Accounting Standards Updated have been issued and not yet adopted that are applicable to the Company and that would have a material effect on the Company’s condensed consolidated financial statements and related disclosures.

Note 2 — Acquisition

On May 18, 2022, the Company entered into a Purchase and Sale Agreement to acquire certain operated and non-operated interests in proved reserves and certain midstream support assets in the Barnett formation (the “2022 Barnett Assets”) from XTO Energy, Inc and Barnett Gathering LLC, subsidiaries of Exxon Mobil Corporation (collectively”Seller”), for $750.0 million (subject to working capital and other adjustments) and additional contingent payments totaling $50.0 million if certain pricing thresholds are met in future periods (the “Exxon Barnett Acquisition”). The Company paid a deposit of $75.0 million to the Seller in conjunction with entering into the Purchase and Sale Agreement. The Company closed the transaction on June 30, 2022; the adjusted purchase price, excluding contingent consideration was $627.5 million which included the $75.0 million deposit. As of the acquisition date, the fair value of the additional contingent payments was $17.2 million. See Note 4 — Fair Value Measurements and Note 14 — Commitments and Contingencies for discussion of the fair market value valuation methodology applied to the contingent consideration at the acquisition date and details of the contingent consideration, respectively. The Company funded the cash portion of the consideration with the proceeds from its term loan, refer to Note 8 — Debt.

The Exxon Barnett Acquisition was accounted for as a business combination; therefore the assets acquired and liabilities assumed were recorded based on the respective estimated acquisition date fair values with information available at the time, and the residual difference between the net assets and the purchase price was recorded as a bargain purchase gain. A combination of discounted cash flow models and market data was used by a third-party specialist, under the direct supervision of management, in determining the fair value of the natural gas properties, and midstream assets. Significant inputs into the calculation included future commodity prices, estimated volumes of natural gas, NGL and oil reserves, expectations for the timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The Company’s assessment of the fair market value of the assets acquired and liabilities assumed is preliminary and subject to change as additional information is obtained by management. The Company expects to complete the purchase accounting, including the fair market value assessment

F-63

during the twelve month period following the date of the acquisition. The Exxon Barnett Acquisition resulted in a bargain purchase gain, which was primarily caused by the increase in commodity pricing from the date the acquisition was originally negotiated through the closing date. The Exxon Barnett Acquisition was made to support the strategic growth of the Company and to achieve operational synergies with pre-existing assets in the Barnett formation. During the three and six months ended June 30, 2022, the Company incurred $0.5 million and $3.4 million, respectively, of acquisition costs which are included in general and administrative expense on the condensed consolidated statement of operations and comprehensive income (loss). The Exxon Barnett Acquisition closed at the end of business on June 30, 2022, therefore the results of operations of the Company for three and six months ended June 30, 2022 reflected in the condensed consolidated statements of operations and comprehensive income (loss) do not include the operating results of the Exxon Barnett Acquisition.

The estimated purchase price consideration and fair value of assets acquired and liabilities assumed are as follows (in thousands):

Cash	$	627,527
Contingent consideration	​	17,150
Total consideration	$	644,677
Assets acquired and liabilities assumed:	​	​
Inventory	$	150
Natural gas properties – developed	​	664,665
Midstream assets	​	254,813
Other property and equipment	​	8,907
Property taxes	​	(9,039)
Deferred tax liability	​	(49,789)
Revenues payable	​	(16,612)
Asset retirement obligations	​	(44,765)
Total identifiable net assets	$	808,330
Bargain purchase gain	$	(163,653)

Unaudited Pro Forma Information.   The following unaudited pro forma financial information represents a summary of the historical condensed consolidated results of operations for the six months ended June 30, 2022 and 2021, giving effect to the Exxon Barnett Acquisition as if it had been completed on January 1, 2021. The pro forma financial information is provided for illustrative purposes only and are not intended to represent what the Company’s financial position or results of operations would have been had the Exxon Barnett Acquisition occurred on the assumed date nor do they purport to project the future operating results or the financial position of the Company following the Exxon Barnett Acquisition.

The information below reflects certain nonrecurring and recurring pro forma adjustments that were directly related to the business combination based on available information and certain assumptions that the Company believes are reasonable, including (i) the increase in depletion and amortization reflecting the relative fair values and production volumes attributable to the Seller’s natural gas properties and the revision to the depletion rate reflecting the reserve volumes acquired, (ii) the increase in depreciation expense reflecting the relative fair values attributable to the Seller’s midstream assets and revision of useful lives reflecting the Company’s estimate thereof, (iii) adjustments to interest expense as a result of the Company’s indebtedness incurred to fund the purchase of the 2022 Barnett Assets further described in Note 8 — Debt and Note 7 — Related Parties for the $570.0 million term loan and $75.0 million related party note, respectively, (iv) increase in accretion expense reflective of the fair market value of asset retirement obligations, and (v) the estimated tax impacts of the pro forma adjustments.

​	For the six months ended
(in thousands)	June 30, 2022			June 30, 2021
Revenues and other operating income	​	$	438,747	​	$	285,531
Net income (loss) and comprehensive income (loss) attributable to BKV Corp.	​	$	142,363	​	$	(142,342)

F-64

Note 3 — Natural Gas Properties & Other Property and Equipment

Accumulated depreciation, depletion and amortization for developed natural gas properties as of June 30, 2022 and December 31, 2021 was $301.8 million and $267.3 million, respectively. Depreciation, depletion and amortization expense for developed gas properties for the three months ended June 30, 2022 and 2021 was $17.0 million and $19.2 million, respectively, and $34.5 million and $38.6 million for the six months ended June 30, 2022 and 2021 respectively. There were no exploratory well costs pending determination of proved reserves at June 30, 2022 and December 31, 2021 and no exploratory dry hole costs during the six months ended June 30, 2022 and 2021.

Midstream assets consisted of the following as of the periods indicated:

(in thousands)	June 30, 2022			December 31, 2021
Compressor station	​	$	70,792	​	$	6,831
Meter station	​	​	654	​	​	654
Pipelines	​	​	238,813	​	​	47,878
Total	​	​	310,259	​	​	55,363
Accumulated depreciation	​	​	(8,090)	​	​	(7,417)
Midstream assets, net	​	$	302,169	​	$	47,946

Depreciation expense on midstream assets of $0.3 million and $0.4 million was recognized for the three months ended June 30, 2022 and 2021, respectively, and $0.7 million and $0.7 million for the six months ended June 30, 2022 and 2021, respectively.

Other property and equipment consisted of the following as of the periods indicated:

(in thousands)	June 30, 2022			December 31, 2021
Buildings	​	$	12,675	​	$	12,675
Furniture, fixtures, equipment and vehicles	​	​	12,118	​	​	6,555
Computer software	​	​	4,713	​	​	4,715
Leasehold improvements	​	​	1,627	​	​	1,571
Land	​	​	7,203	​	​	3,090
Total	​	​	38,336	​	​	28,606
Accumulated depreciation	​	​	(7,887)	​	​	(6,482)
Other property and equipment, net	​	$	30,449	​	$	22,124

Depreciation expense for other property and equipment for the three months ended June 30, 2022 and 2021 was $0.7 million and $0.7 million, respectively, and $1.4 million and $1.4 million for the six months ended June 30, 2022 and 2021, respectively.

Note 4 — Fair Value Measurements

Derivative assets and liabilities measured at fair value as of June 30, 2022 and December 31, 2021 use Level 2 valuation techniques; contingent consideration, minority ownership puttable shares, and equity based compensation are measured at fair value and as of these reporting dates using Level 3 valuation techniques. There have been no transfers between fair value levels during the reporting periods. In addition, derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. The Company factors non-performance risk into the valuation of derivatives using current published credit default swap rates. As of June 30, 2022, the impact of the non-performance risk adjustment to the Company’s fair value of commodity derivative liabilities was $7.6 million.

F-65

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

​	As of June 30, 2022
​	Fair Value Measurements Using:						​	​
(in thousands)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Financial assets	​	​	​	​	​	​	​	​
Derivative instruments	​	—	​	—	​	—	​	—
Financial liabilities	​	​	​	​	​	​	​	​
Derivative instruments	​	—	​	304,968	​	—	​	304,968
Contingent Consideration	​	—	​	—	​	191,598	​	191,598
Mezzanine equity	​	​	​	​	​	​	​	​
Minority ownership puttable shares	​	—	​	—	​	71,286	​	71,286
Equity-based compensation	​	—	​	—	​	81,577	​	81,577

​	As of December 31, 2021
​	Fair Value Measurements Using:						​	​
(in thousands)	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Financial assets	​	​	​	​	​	​	​	​
Derivative instruments	​	—	​	9,986	​	—	​	9,986
Financial liabilities	​	​	​	​	​	​	​	​
Derivative instruments	​	—	​	114,818	​	—	​	114,818
Contingent Consideration	​	—	​	—	​	142,533	​	142,533
Mezzanine equity	​	​	​	​	​	​	​	​
Minority ownership puttable shares	​	—	​	—	​	49,841	​	49,841
Equity-based compensation	​	—	​	—	​	34,006	​	34,006

The contingent consideration was generated from the Devon Barnett Acquisition (referred to as the Barnett Asset Acquisition in the Company’s Annual Financial Statements and the “Devon Barnett Acquisition” herein) and Exxon Barnett Acquisition further described in the Annual Financial Statements and Note 2 — Acquisition, respectively.The fair value of the contingent consideration as of June 30, 2022 and December 31, 2021 represents management’s best estimate if a third party were paid to assume the contingency. The fair value was determined using forecasted monthly Henry Hub Prices, West Texas Intermediate prices and the application of Monte Carlo simulations. The Exxon Barnett Acquisition contingency is described further in Note 14 — Commitments and Contingencies to the condensed consolidated financial statements.

The minority ownership puttable shares were recorded at fair value upon initial recognition in mezzanine equity on the condensed consolidated balance sheets. The fair market value of the Company’s common stock was used to determine the carrying value of the minority ownership puttable shares in mezzanine equity on the condensed consolidated balance sheets as of June 30, 2022 and December 31, 2021. The Company’s common stock was valued using both observable (Level 2) and unobservable (Level 3) inputs. The minority ownership puttable shares are further described in the Company’s Annual Financial Statements.

Equity-based compensation was recorded at fair value on the grant date, considering modification of the awards when classified in mezzanine equity, when liability classified it is recorded based on fair value at the end of the period. The underlying market condition was valued using the application of Monte Carlo simulations using both observable (Level 2) and unobservable (Level 3) inputs. The remaining components

F-66

of the awards were valued based on the fair market value of the common stock of the Company, which is valued consistent with valuation methodologies described for the minority ownership puttable shares. The fair market value of the Company’s market condition and common stock as of June 30, 2022 were used to determine the fair market value of equity-based compensation in mezzanine equity on the condensed consolidated balance sheet as of June 30, 2022. Equity-based compensation is further described in Note 11 — Equity-based Compensation to the condensed consolidated financial statements.

Quantitative data regarding the Company’s Level 3 unobservable inputs are as follows:

(in thousands, except per share amounts)	Fair Value			Valuation Technique	Unobservable Input	Range or Actual
Common stock – per share – as of June 30, 2021(1)	​	$	10.00	Enterprise value	Discount rate	8.9-10%
Market condition equity-based compensation per share – as of June 30, 2021	​	$	6.64	Monte Carlo Simulation	Performance period dividends	50% of projected annual net income
Contingent consideration – as of December 31, 2021	​	$	142,533	Monte Carlo Simulation	Risk Free Rate	1.0%
​	​	​	​	​	Credit Spread	4.0%
​	​	​	​	​	Discount Rate	5.0%
Market condition equity-based compensation per share – as of December 31, 2021	​	$	13.77	Monte Carlo Simulation	Performance period dividends	3% equity capital, annually
Common stock – per share value – as of December 31, 2021(1)	​	$	11.75	Enterprise value	Performance period dividends	7.7-9.5%
Market condition equity-based compensation per share – as of March 31, 2022	​	$	24.25	Monte Carlo Simulation	Performance period dividends	3% equity capital, annually
Common stock – per share value – as of March 31, 2022(1)	​	$	15.28	Enterprise value	Discount rate	7.7-9.5%
Market condition equity-based compensation per share – as of June 30, 2022	​	$	20.04	Monte Carlo Simulation	Performance period dividends	3% equity capital, annually
Common stock – per share value – as of June 30, 2022(1)	​	$	16.79	Enterprise value	Discount rate	8-12%
Contingent consideration – as of June 30, 2022	​	$	191,599	Monte Carlo Simulation	Risk Free Rate	2.6% – 2.9%
​	​	​	​	​	Credit Spread	4.8%
​	​	​	​	​	Discount Rate	7.5% – 7.7%

(1)

The Company uses the midpoint of valuation results when estimating the fair value of common stock.

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The table below sets forth the changes in the Company’s level 3 fair value measurements:

(in thousands)	June 30, 2022			December 31, 2021
Balance beginning of period	​	$	226,380	​	$	54,853
Contingent consideration-additions from business combination	​	​	17,150	​	​	—
Contingent consideration – settlement	​	​	—	​	​	(65,000)
Minority ownership puttable share activity	​	​	78	​	​	511
Grant date fair value of equity-based compensation	​	​	19,082	​	​	28,990
Change in fair market value (all instruments)	​	​	81,771	​	​	207,026
Balance end of period	​	$	344,461	​	$	226,380

Note 5 — Derivative Instruments

From time to time, the Company may utilize derivative contracts in connection with its natural gas and NGL operations to provide an economic hedge of the Company’s exposure to commodity price risk associated with anticipated future natural gas and NGL production. The Company does not hold or issue derivative financial instruments for trading purposes. The derivative contracts outstanding as of June 30, 2022 and December 31, 2021 consisted of swap, enhanced three-way collar, and option agreements, subject to master netting agreements with each individual counterparty. The following table presents gross commodity derivative balances prior to applying netting adjustments and net balances recorded in the condensed consolidated balance sheets:

​	As of June 30, 2022
(in thousands)	Gross Amounts of Assets and Liabilities			Offset Adjustments		Net amounts of assets/liabilities
Current derivative assets	​	$	630	​	(630)	​	$	—
Noncurrent derivative assets	​	$	—	​	—	​	$	—
Current derivative liabilities	​	$	242,883	​	(630)	​	$	242,253
Noncurrent derivative liabilities	​	$	62,715	​	—	​	$	62,715

​	As of December 31, 2021
(in thousands)	Gross Amounts of Assets and Liabilities			Offset Adjustments		Net amounts of assets/liabilities
Current derivative assets	​	$	9,986	​	—	​	$	9,986
Noncurrent derivative assets	​	$	—	​	—	​	$	—
Current derivative liabilities	​	$	91,156	​	—	​	$	91,156
Noncurrent derivative liabilities	​	$	23,662	​	—	​	$	23,662

Enhanced Three-way Collar, Collar and Swap Contracts

Generally, enhanced three-way collar arrangements provide for a price floor, a price ceiling and either a price sub-floor or price sub-ceiling. The floating price for the enhanced three-way collar contracts is traded for a fixed price when the floating price is not between the floor and ceiling, and for twice the contracted volumes within the contracted volumes, the sub-floor/ceiling. If the floating price is between these contracted prices, no trade occurs. A commodity swap agreement is an agreement whereby a floating price based on the underlying commodity is traded for a fixed price over a specified period. A commodity collar provides for a price floor and a price ceiling. The floating price for the collar contract is traded for a fixed price when the floating price is not between the floor and ceiling. If the floating price is between these contracted prices, no trade occurs.

The fair value of open enhanced three-way collars, collars and swap contracts reported in the condensed consolidated balance sheets may differ from that which would be realized in the event the Company terminated

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its position in the respective contract. Risks may arise as a result of the failure of the counterparty to the contract to comply with the terms of the contract. The loss incurred by the failure of the counterparties is generally limited to the aggregate fair value of the outstanding contracts in an unrealized gain position as well as any collateral posted with the counterparty. The Company considers the creditworthiness of each counterparty to an enhanced three-way collar, option, or swap contract in evaluating potential credit risk. Additional risks may arise from unanticipated movements in the fair value of the underlying investments.

Derivative Contracts

The Company records its derivative financial instruments related to natural gas and NGL production at fair value using a market approach and has not designated any derivatives as hedges. Derivative financial instruments are marked-to-market and presented on the condensed consolidated balance sheets as commodity derivative assets or commodity derivative liabilities with the amount of unsettled gain or loss reflected in derivative losses, net in the condensed consolidated statements of operations and comprehensive loss. Derivative financial instruments that settle throughout the year are recorded as derivative losses, net in the condensed consolidated statements of operations and Comprehensive Loss. The following tables set forth the effect of derivative instruments on the condensed consolidated statements of operations and comprehensive loss:

​	Three Months Ended June 30,
(in thousands)	2022			2021
Total loss on settled derivative instruments	​	$	(179,177)	​	$	(18,478)
Total gain (loss) on unsettled derivative instruments	​	​	93,224	​	​	(123,085)
Total loss on derivative instruments	​	$	(85,953)	​	$	(141,563)

​	Six Months Ended June 30,
(in thousands)	2022			2021
Total loss on settled derivative instruments	​	$	(250,648)	​	$	(22,058)
Total loss on unsettled derivative instruments	​	​	(200,136)	​	​	(156,217)
Total loss on derivative instruments	​	$	(450,784)	​	$	(178,275)

As of June 30, 2022 and December 31, 2021, $95.5 million and $66.8 million of settled derivative instruments were included in accounts payable and accrued liabilities, respectively, on the Company’s condensed consolidated balance sheets. Of these amounts, $7.7 million and $23.2 million related to monetizations, respectively.

Volume of Derivative Activities

Outstanding derivative contracts are measured at fair value using Level 2 valuation techniques and are included in the accompanying condensed consolidated balance sheets as derivative assets and derivative liabilities.

As of June 30, 2022, the Company’s derivative activities based on volume and contract prices, categorized by primary underlying risk and related commodity, by year, were as follows:

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The following table represents natural gas commodity derivatives indexed to NYMEX Henry Hub pricing:

Instrument

MMBTU

Weighted Average Price (USD)

Weighted Average Price Sub Floor

Weighted Average Price Floor

Weighted Average Price Ceiling

Weighted Average Price Sub Ceiling

Fair Value as of June 30, 2022 (In thousands)

2022

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Swap

​

33,349,000

​

$

4.33

​

​

​

​

​

​

​

​

​

​

​

​

​

$

(39,053)

Enhanced three-way collars

​

21,430,000

​

​

​

​

$

2.51

​

$

2.54

​

$

3.08

​

$

3.17

​

$

(108,025)

Collars

​

5,415,000

​

​

​

​

​

​

​

$

2.84

​

$

3.69

​

​

​

​

$

(11,189)

2023

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

​

Swap

​

54,812,000

​

$

3.91

​

​

​

​

​

​

​

​

​

​

​

​

​

$

(35,182)

Enhanced three-way collars

​

8,350,000

​

​

​

​

​

​

​

$

2.45

​

$

3.15

​

$

3.15

​

$

(24,571)

Collars

​

50,100,000

​

​

​

​

​

​

​

$

2.85

​

$

3.75

​

​

​

​

$

(51,368)

The following table represents natural gas liquids commodity derivatives for contracts expiring throughout the years ended December 31, 2022 and 2023 based on the applicable index listed below:

Instrument	Commodity Reference Price	Volumes		Weighted Average Price (USD)			Fair Value at June 30, 2022 (In thousands)
2022	​	​	​	​	​	​	​	​	​
Swaps	OPIS Purity Ethane Mont Belvieu	​	75,339,600	​	$	0.35	​	$	(8,764)
Swaps	OPIS IsoButane Mont Belvieu Non-TET	​	1,932,000	​	$	0.99	​	$	(964)
Collars	OPIS IsoButane Mont Belvieu Non-TET	​	4,636,800	​	$	1.34	​	$	(138)
Swaps	OPIS Normal Butane Mont Belvieu Non-TET	​	3,864,000	​	$	0.98	​	$	(1,642)
Collars	OPIS Normal Butane Mont Belvieu Non-TET	​	7,467,600	​	$	1.40	​	$	(68)
Swaps	OPIS Pentane Mont Belvieu Non-TET	​	3,864,000	​	$	1.46	​	$	(1,936)
Collars	OPIS Pentane Mont Belvieu Non-TET	​	11,331,600	​	$	1.99	​	$	76
Swaps	OPIS Propane Mont Belvieu Non-TET	​	11,592,000	​	$	0.86	​	$	(3,973)
Collars	OPIS Propane Mont Belvieu Non-TET	​	31,164,000	​	$	1.22	​	$	108
2023	​	​	​	​	​	​	​	​	​
Swap	OPIS Purity Ethane Mont Belvieu	​	38,325,000	​	$	0.23	​	$	(4,307)
Swap	OPIS IsoButane Mont Belvieu Non-TET	​	3,832,500	​	$	0.80	​	$	(1,610)
Swap	OPIS Normal Butane Mont Belvieu Non-TET	​	3,832,500	​	$	0.80	​	$	(1,475)
Swap	OPIS Pentane Mont Belvieu Non-TET	​	7,665,000	​	$	1.28	​	$	(4,109)
Swap	OPIS Propane Mont Belvieu Non-TET	​	22,995,000	​	$	0.72	​	$	(6,778)

Note 6 — Asset Retirement Obligations

The Company has recognized an estimated liability for its asset retirement obligations related to the future costs of plugging, abandonment, and remediation of natural gas producing properties. The present value of the estimated asset retirement obligations has been capitalized as part of the carrying amount of the related natural gas properties. The liability has been accreted to its present value during the years ended June 30, 2022 and December 31, 2021.

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The following table summarizes the activities of the Company’s asset retirement obligations for the periods indicated:

(In thousands)	June 30, 2022			December 31, 2021
Asset retirement obligations, beginning of period	​	$	158,968	​	$	148,826
Additions through business combination	​	​	44,765	​	​	—
Liabilities incurred	​	​	261	​	​	923
Liabilities settled	​	​	(35)	​	​	(811)
Accretion of discount	​	​	5,320	​	​	10,030
Asset retirement obligations, end of period	​	​	209,279	​	​	158,968
Less current portion	​	​	—	​	​	—
Asset retirement obligations, long-term	​	$	209,279	​	$	158,968

Note 7 — Related Parties

On October 14, 2021, the Company entered into a Loan Agreement with its majority shareholder BNAC (the “Lender”) and borrowed $116.0 million thereunder. Interest on the outstanding principal is SOFR + 5.25% and is payable on a semi-annual basis. The outstanding balance of $116.0 million as of June 30, 2022 is due on December 31, 2027, including any unpaid interest. On June 15, 2022, the Company entered into an Amended and Restated Loan Agreement (as amended, the “$116 Million Loan Agreement”) to, among other things, subordinate the $116.0 million term loan owed to the Lender to the term loans borrowed by the Company under the Term Loan Credit Agreement (the “Credit Agreement”) further discussed in Note 8 — Debt. The applicable interest rate as of June 30, 2022 was 6.81%. Interest payable under the $116 Million Loan Agreement as of June 30, 2022 was $1.7 million. During the three and six months ended June 30, 2022, the Company recognized interest expense of $1.9 million and $3.5 million, respectively.

On November 8, 2021, the Company entered into a Loan Agreement with the Lender and borrowed $50.0 million thereunder. On January, 11, 2022 and June 1, 2022, the Company repaid $15.0 million and $35.0 million, respectively. There was no outstanding balance on this facility as of June 30, 2022. During the three and six months ended June 30, 2022, the Company recorded Interest expense of $0.4 million and $0.9 million, respectively.

The Company is subject to certain financial and non-financial covenants under the $116 Million Loan Agreement. The non-financial covenants prevent the Company from: incurring a lien on its, or any of its subsidiaries’, assets or related revenues; incurring additional indebtedness without written consent of the Lender; incurring additional unsecured indebtedness whereby the Lender does not rank equal to holder of the new unsecured indebtedness; or conducting any business outside of the business currently conducted by the Company. The financial covenants require the Company to maintain a net worth, as defined within the $116 Million Loan Agreement, of greater than $800.0 million. The Company is also required to maintain a trailing twelve-month net borrowings to EBITDAX ratio of greater than 3.0x following each draw down. The Company was in compliance with all associated covenants under the Loan Facility Agreement as of June 30, 2022.

On March 10, 2022, the Company entered into a Loan Agreement (the “$75 Million Loan Agreement”) with the Lender and borrowed $75.0 million thereunder. Interest on the outstanding principal is SOFR + 5.25% and is payable on a semi-annual basis. The principal balance of $75.0 million is due on December 31, 2027, including any unpaid interest. On June 15, 2022, the Company entered into a subordination agreement with the Lender whereby the $75.0 million is subordinate to the term loans of the Company under the Term Loan Credit Agreement further discussed in Note 8 — Debt. Financial covenants are consistent with those of the Term Loan Credit Agreement as discussed in Note 8 — Debt. Interest payable under the $75 Million Loan Agreement as of June 30, 2022 was $1.2 million. During the three and six months ended June 30, 2022, we recorded interest expense of $1.0 million and $1.2 million, respectively.

As of June 30, 2022 and December 31, 2021, the Company had payables of $37.6 million and $30.7 million, respectively, to BNAC for current tax expense included in the other current liabilities line

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item on the condensed consolidated balance sheets. The amounts due to BNAC as of June 30, 2022 and December 31, 2021, respectively, related to reimbursements for income tax related items. Separately, the Company had a $0.5 million and a $0.5 million receivable from BNAC as of June 30, 2022 and December 31, 2021, respectively, related to shared general and administrative expenses.

As of June 30, 2022 and December 31, 2021, the Company had accounts receivable from BKV-BPP Power, LLC of $1.7 million and $1.8 million, respectively, related to reimbursement for certain expenses paid on behalf of BKV-BPP Power, LLC and amounts receivable under the Administration Services Agreement between the Company and BKV-BPP Power, LLC. See the Company’s Annual Financial Statements for further discussion of the Company’s equity method investments. During the three and six months ended June 30, 2022, the Company recognized $0.7 million and $1.3 million of revenues related to the services provided under the Administration Services Agreement which is included in other revenues on the condensed consolidated statements of operations and comprehensive loss.

The Company’s ultimate parent Banpu Public Company Limited is also the ultimate parent of Banpu Power Corporation (“BPP US”), the Company’s partner in a joint venture which is discussed further in the Company’s Annual Financial Statements. As of June 30, 2022 and December 31, 2021, the Company had accounts receivable from BPP US of $1.3 million and $1.3 million, respectively, related to reimbursement for expenses incurred during the formation of the joint venture.

Note 8 — Debt

On December 22, 2021 the Company entered into an agreement with a bank (the “Bank”) which provides for a revolving credit facility (the “Facility”) with a limit of $55.0 million. The Facility is not secured. Advances on the Facility are required to be repaid upon the earlier of 60 days after the date of the advance, or upon the receipt of a written demand notice from the Bank. Advances from the Facility must be greater than $1.0 million. Interest on any outstanding advances is payable monthly at a rate of SOFR +2.0%. On June 30, 2022, the outstanding balance of the Facility was $30.0 million, which was repaid on August 18, 2022. On September 14, 2022, the Company received an advance of $45.0 million and received an extension of payment terms whereby the advance is required to be repaid by February 15, 2023. Such advance was outstanding as of the date the condensed consolidated financial statements were available for issuance.

On March 16, 2022, the Company entered into an agreement with another bank which provides for revolving term loans and letters of credit (“Facility II”) with a limit of $25.0 million. Of the $25.0 million, $15.0 million is available for cash draw downs, and in the absence of outstanding cash draw downs, the full $25.0 million is available for letters of credit. Facility II is not secured. Interest is agreed upon at the time of each cash drawn down. Facility II had one outstanding letter of credit for $14.4 million as of the date the condensed consolidated financial statements were available for issuance. There was no outstanding balance on Facility II as of June 30, 2022. On August 19, 2022, the Company received a cash advance from Facility II in the amount of $10.0 million.

On June 16, 2022 the Company entered into a Credit Agreement with a syndicate of lenders (the “Lenders”) whereby the Company can borrow up to $600.0 million in the aggregate, in the form of multiple term loans during the period commencing with the effective date and ending six months thereafter. The term loans under the Credit Agreement must be equal to or greater than $5.0 million; amounts repaid by the Company in respect to the term loans may not be re-borrowed under the Credit Agreement. Once drawn, the term loans are required to be repaid annually in five equal installments; installment payments are due on each anniversary of the original draw for the respective term loan . The term loans are not secured. On June 30, 2022, the Company drew a term loan of $570.0 million to fund the Exxon Barnett Acquisition. Interest is adjusted term SOFR + 4.75%. The proceeds of the term loans must be used to finance the Exxon Barnett Acquisition. See Note 2 — Acquisition.

The Term Loan Credit Agreement requires the Company to maintain certain financial covenants, including requiring the asset coverage ratio to be no less than 2.00 to 1.00, the total net leverage ratio to be no greater than 2.50 to 1.00, and the consolidated fixed charge coverage ratio to be no less than 1.30 to 1.00. As of June 30, 2022, we were in compliance with all covenants of the Term Loan Credit Agreement.

F-72

The following table summarizes the long-term debt balances:

(In thousands)	June 30, 2022
Revolving credit facility	​	$	30,000
Term loan credit agreement	​	​	114,000
Current portion of unamortized debt issuance costs	​	​	(2,097)
Total current portion of long-term debt, net	​	​	141,903
Term loan credit agreement	​	​	456,000
Long-term portion of unamortized debt issuance costs	​	​	(4,509)
Total long-term debt, net	​	​	451,491
Total debt, net	​	$	593,394

Subsequent Activities

On August 24, 2022 the Company entered into an agreement with another bank which provides for a revolving credit facility (“Facility III”) with a limit of $100.0 million. Facility III is an unsecured facility committed through September 30, 2027. Cash draw downs and all applicable interest is payable at one, three, or six months from the date of the advance (“one month draw,” “three month draw” and “six month draw,” respectively). The interest period is determined by the Company at the time of the advance. The interest rate on any outstanding advances is adjusted term SOFR + 4.75%. On September 14, 2022, the Company took a six month draw of $45.0 million and a one month draw of $30.0 million. As of the date the condensed consolidated financial statements were available for issuance, the Company had $75.0 million outstanding under Facility III.

Note 9 — Revenue from Contracts with Customers

The Company records sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement, which is variable based on commodity pricing. The Company estimates its sales volumes based on company-measured volume readings. Natural gas, NGL and oil sales are adjusted in subsequent periods based on data received from the Company’s purchasers that reflects actual volumes and prices received which is typically within two months of transfer of control to the purchaser. Historically, the difference between estimated and actual sales revenues have not been material. For the three and six months ended June 30, 2022 and 2021, the impact of any natural gas imbalances was not significant.

In conjunction with its sales of natural gas, the Company records marketing revenues based on estimated underlying variable consideration pricing and delivered volumes. Marketing revenues are adjusted in subsequent periods based on data received from the Company’s purchaser or trading partner. Historically, the difference between estimated and actual marketing revenues has not been material.

The Company also generates revenues from its non-operated midstream interests. Midstream revenues are recognized when services are rendered based on quantities transported and measured according to the underlying contract. The Company records midstream revenue based on volumes at stated contractual rates. The Company estimates its volumes based on third-party data. Midstream revenues are adjusted in subsequent periods based on data received from the operator that reflects actual volumes which is typically within three months.

F-73

All of the Company’s revenues are generated in the states of Pennsylvania and Texas. Revenues consist of the following:

​	Three Months Ended June 30, 2022
(in thousands)	Pennsylvania			Texas			Total
Natural gas	​	$	66,789	​	$	226,593	​	$	293,382
Natural gas liquids	​	​	—	​	​	87,470	​	​	87,470
Oil	​	​	—	​	​	2,661	​	​	2,661
Total production revenues	​	$	66,789	​	$	316,724	​	$	383,513
Marketing revenues	​	​	—	​	​	1,661	​	​	1,661
Non-operated midstream revenues	​	​	1,459	​	​	—	​	​	1,459
Total	​	$	68,248	​	$	318,385	​	$	386,633

​	Three Months Ended June 30, 2021
(in thousands)	Pennsylvania			Texas			Total
Natural gas	​	$	17,248	​	$	79,885	​	$	97,133
Natural gas liquids	​	​	—	​	​	53,359	​	​	53,359
Oil	​	​	—	​	​	2,625	​	​	2,625
Total production revenues	​	$	17,248	​	$	135,869	​	$	153,117
Marketing revenues	​	​	—	​	​	1,575	​	​	1,575
Non-operated midstream revenues	​	​	1,896	​	​	—	​	​	1,896
Total	​	$	19,144	​	$	137,444	​	$	156,588

​	Six Months Ended June 30, 2022
(in thousands)	Pennsylvania			Texas			Total
Natural gas	​	$	111,630	​	$	376,183	​	$	487,813
Natural gas liquids	​	​	—	​	​	163,498	​	​	163,498
Oil	​	​	—	​	​	5,120	​	​	5,120
Total production revenues	​	$	111,630	​	$	544,801	​	$	656,431
Marketing revenues	​	​	—	​	​	5,328	​	​	5,328
Non-operated midstream revenues	​	​	3,344	​	​	—	​	​	3,344
Total	​	$	114,974	​	$	550,129	​	$	665,103

​	Six Months Ended June 30, 2021
(in thousands)	Pennsylvania			Texas			Total
Natural gas	​	$	41,327	​	$	132,793	​	$	174,120
Natural gas liquids	​	​	—	​	​	111,166	​	​	111,166
Oil	​	​	—	​	​	4,056	​	​	4,056
Total production revenues	​	$	41,327	​	$	248,015	​	$	289,342
Marketing revenues	​	​	—	​	​	50,296	​	​	50,296
Non-operated midstream revenues	​	​	3,972	​	​	—	​	​	3,972
Total	​	$	45,299	​	$	298,311	​	$	343,610

Contract Balances

Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Under the Company’s sales contracts, the Company invoices customers after its performance obligations have been

F-74

satisfied, at which point payment is unconditional. As of June 30, 2022 and December 31, 2021, the Company’s receivables from contracts with customers were $134.2 million and $100.4 million, respectively.

Note 10 — Accounts Payable and Accrued Liabilities

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

(in thousands)	June 30, 2022			December 31, 2021
Accounts payable	​	$	54,014	​	$	32,237
Commodity derivative settlements payable	​	​	87,794	​	​	43,252
Commodity derivative monetizations payable	​	​	7,725	​	​	23,175
Revenues payable	​	​	51,206	​	​	29,871
Other accrued liabilities	​	​	42,784	​	​	38,301
Total	​	$	243,523	​	$	166,836

Note 11 — Equity-based Compensation

On January 1, 2021 the BKV Corporation 2021 Long Term Incentive Plan (the “Plan”) was established by the adoption of the Plan by the Board of Directors, which allows for the grant of incentive awards to employees and non-employee directors of the Company in the form of restricted stock units (“RSU”). Each RSU represents the contingent right to receive one share of common stock of the Company. As of June 30, 2022, the maximum number of RSUs authorized to be awarded under the Plan was 14,941,176. However, of the total authorized RSUs under the plan, only 60% may be awarded on or before December 31, 2022 without the written approval of the Board of Directors of the Company. Thereafter, no more than 80% of the total RSUs may be awarded without the written approval of the Board of Directors of the Company. For accounting purposes, management evaluated grants of incentive awards from the Plan under ASC 718 — Compensation-Stock Compensation and determined a grant date, for all annual incentive awards, including those anticipated to be legally granted in the three years subsequent to the initial incentive award date, was established because all grant date criteria had been satisfied and compensation expense and forfeitures were accounted for accordingly. Under ASC 718 — Compensation-Stock Compensation, as of June 30, 2022, 15,367,398, were considered to have been granted under the plan since the plan inception when taking into consideration performance RSUs at the maximum performance level and time-based restricted stock units anticipated to be legally granted in the three years following the initial incentive award date. Of the awards considered granted under ASC 718 — Compensation-Stock Compensation as of June 30, 2022, 1,413,141 RSUs are not considered legally granted.

RSUs are granted in the form of Performance-Based Restricted Stock Units (“PRSU”) and Time-Based Restricted Stock Units (“TRSU”). The shares of common stock issued in settlement of the RSUs include a put right (the “Plan Put Right”) available to the incentive award grant recipients (the “Participants”). If a Participant’s employment is terminated due to voluntary resignation, and certain other conditions are met, a Participant is able to elect the Company to purchase the shares issued in settlement of his or her RSUs at fair market value of the Company’s common stock at the time the election is made by the Participant. The Plan Put Right is only available to Participants upon the occurrence of certain events as defined in the Plan. As discussed below in “Modification of Terms,” this Plan Put Right was modified on November 5, 2021 to add a one hundred eighty-one-day holding period following vesting of the RSUs. In addition, the Company has a purchase right (the “Call Right”) which allows for the purchase of shares of common stock issued in the settlement of the RSUs from terminated participants at fair market value on the date of the purchase, at the Company’s discretion. As discussed below in “Modification of Terms,” this Call Right was modified on November 5, 2021 to add a one hundred eighty-one-day holding period following vesting of the RSUs. These features, specifically the Plan Put Right, required the Company to treat the incentive awards as cash-settled or liability classified in the condensed consolidated balance sheets of the Company until the Plan was modified as described below. Under liability treatment, for the for the three and six months ended June 30, 2021, the Company incurred $10.9 million and $6.9 million of equity-based compensation expense, respectively, which is included within the condensed consolidated statement of operations and comprehensive income (loss) as general and administrative expense. Under liability treatment, expense and the corresponding

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liability is determined based on the fair market value of the underlying common stock shares for TRSUs. For PRSUs, the non-market performance condition use the fair market value of the underlying common stock shares coupled with the estimated level of achievement for each performance criteria. The market condition fair value is determined using a Monte Carlo Simulation which uses observable and unobservable inputs, see Note 4 — Fair Value Measurements for the level 3 unobservable inputs used in both the fair value of the underlying common stock and the market condition. Observable inputs used in the market condition valuation as of June 30, 2021 are a risk-free rate of 0.35% and volatility of 35%.

Modification of terms

On November 5, 2021, the Board of Directors of the Company approved the First Amendment to the BKV Corporation 2021 Long Term Incentive Plan (the “Plan Amendment”). The Plan Amendment included a provision to require all Participants of the Plan to hold vested shares of common stock issued in settlement of RSUs for a minimum of one-hundred eighty-one days (the “Holding Period”) prior to having the ability to exercise the Plan Put Right. The Amendment also applied the Holding Period to the Call Right. Upon modification, the RSUs under the plan are considered to be settled in equity, as the Holding Period is a reasonable period of time to experience the risk and rewards of an equity instrument. However, due to the existence of the Plan Put Right, the Company recognized the incentive awards within mezzanine equity on the condensed consolidated balance sheet as of the date of Plan Amendment. All Participants of the plan agreed to the terms of the Plan Amendment.

Performance-Based Restricted Stock Units

The PRSUs are subject to a three year vesting or performance period beginning January 1, 2021 and ending on the earlier of December 31, 2023 (the “Performance Period”) or IPO of the Company. All PRSUs cliff vest based on and subject to the achievement of the performance criteria upon the earlier of an initial public offering of the Company, change in control, or December 31, 2023. The table below summarizes the PRSU activity for the six months ended June 30, 2022:

(in thousands, except per share amounts)	Shares		Weighted Average Grant Date Fair Value
Unvested PRSUs at January 1, 2022	​	11,589	​	$	10.90
Granted(1)	​	399	​	$	13.68
Forfeited(1)	​	(134)	​	$	10.90
Unvested PRSUs as of June 30, 2022	​	11,854	​	$	11.03

(1)

Granted and forfeited award amounts take into consideration performance shares at the maximum performance level

The PSRU’s are eligible to be earned based on three performance conditions: (1) Annualized Total Shareholder Return (“TSR”) of fully diluted common stock during the performance period, (2) Return on Capital Employed (“ROCE”) based on the average annual performance over the Performance Period, and (3) IPO readiness which is based on the Company’s capability to be listed on a public stock exchange at certain points during the performance period. Between 0% and 100% of the PRSUs at maximum performance level are eligible to be earned based on the Company achieving the following pre-established goals:

​	Performance Conditions
​	Weight		Minimum Threshold (0%)		Target Threshold (50%)		Maximum Threshold (100%)
TSR	​	60%	​	5%	​	12.5%	​	20%
ROCE	​	20%	​	—%	​	7%	​	14%
IPO readiness (capability dates)	​	20%	12/31/2024		12/31/2023		12/31/2022

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The TSR component of the awards is a market-based condition valued utilizing the Monte Carlo Simulation pricing model, which calculates multiple potential outcomes and establishes grant date fair value based on the most likely outcome. For the purposes of grant date fair value, the TSR component assumes a risk-free rate of 0.73% – 2.11% and volatility of 40%, see Note 4 — Fair Value Measurements, for the level 3 unobservable input used in the determination of the grant date fair value of the TSR. The weighted average grant date fair value of the TSR component of PRSU awards granted during the six months ended June 30, 2022 was $15.57.

ROCE and IPO readiness are considered to be non-market performance conditions. Thus, the likelihood of achievement must be reassessed at every reporting period, and compensation expense is adjusted accordingly. As of June 30, 2022, management estimates IPO readiness will be achieved at the maximum performance level or 100%, and ROCE performance to be greater than the target performance level at approximately 100%. Accordingly, adjustments were made to compensation expense during the six months ended June 30, 2022 to reflect the estimated levels of achievement. In addition to the level of achievement, the adjustment takes into account the per share grant date fair value of the Company’s common stock of as of the modification date, or grant date. The grant date fair value of the PSRUs presented in the activity for six months ended June 30, 2022 takes into account the grant date fair value for ROCE and IPO readiness, due to the non-market performance conditions being probable of achievement as of the modification date which establishes a grant date fair value. The weighted average grant date fair value of the ROCE and IPO readiness components of PRSU awards granted during the six months ended June 30, 2022 was $11.91.

As of June 30, 2022, there was $46.3 million of unrecognized compensation expense related to the PRSU awards which will be amortized over a weighted average period of 1.5 years.

For the three months ended June 30, 2022 and six months ended June 30, 2022, stock-based compensation related to the PRSUs was $7.7 million, and $18.0 million, respectively, which are included in general and administrative expenses in the condensed consolidated statement of operations and compressive income (loss).

Time-Based Restricted Stock Units

Under the applicable provisions of the Plan, the TRSU incentive award was anticipated to be granted in the form of four annual awards. One quarter of the annual award requires no service for vesting and vests immediately upon the grant date. The remaining three quarters of the annual award vest in equal portions upon the subsequent three anniversary dates following the grant date. The remaining annual awards are anticipated to be granted on the first, second and third anniversaries of the initial TRSU award date, subject to continued employment with the Company and board approval. Vesting for these anticipated three annual awards is expected to follow the same vesting schedule as the first annual awards based on the legal grant date. Upon an initial public offering of the Company, all unvested and legally granted and outstanding awards under the Plan will vest immediately. Awards accounted for as granted under ASC 718 Compensation-Stock Compensation, but not legally granted at such time, will not vest and will be treated accordingly. The following table summarizes the TRSU activity for the six months ended June 30, 2022:

(in thousands, except per share amounts)	Shares		Weighted- Average Grant Date Fair Value
Unvested TRSUs at January 1, 2022	​	2,328	​	$	11.06
Granted(1)	​	86	​	$	12.20
Vested	​	(316)	​	$	11.08
Forfeited	​	(23)	​	$	11.06
Unvested TRSUs as of June 30, 2022	​	2,075	​	$	11.11

(1)

Represents number of awards considered granted under ASC 718 Compensation-Stock Compensation. Of these, 64,125 are not considered legally granted.

As of June 30, 2022 there was $21.2 million of unrecognized compensation expense related to the TRSU awards which will be amortized over a weighted average period of 4.64 years.

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For the three and six months ended June 30, 2022, stock-based compensation expense related to the TRSUs was $1.2 million and $2.3 million, respectively, which are included in general and administrative expenses in the condensed consolidated statement of operations and compressive income (loss).

Subsequent Activities

From June 30, 2022 through the date the condensed consolidated financial statements were available for issuance, the Company granted an additional 81,600 RSUs, comprised of 67,200 PRSUs (assuming maximum performance) and 14,400TRSUs. Of the 14,400 TRSUs considered granted under ASC 718 Compensation-Stock Compensation, 10,800 are not considered legally granted.

Note 12 — Equity Method Investment

The Company is a 50% owner of BKV-BPP Power, LLC (the “Joint Venture”) which is accounted for as an equity method investment.

During the six months ended June 30, 2022, the Company recognized, based on its 50% ownership interest in the Joint Venture, losses of $24.0 million.

The table below sets forth the summarized financial information of the Joint Venture:

Income Statement (in thousands)	Six Months Ended June 30, 2022
​	(unaudited)
Revenues	​	$	129,003
Variable operating expenses	​	​	82,280
Gross profit	​	​	46,723
Operating expenses	​	​	25,689
Income from operations	​	​	21,034
Net loss	​	$	(47,916)

Note 13 — Credit and Other Risk

Credit risk is defined as the risk of a counterparty to a contract failing to perform or pay the amounts due.

The Company is exposed to credit risks in its operating and financing activities. The Company’s maximum exposure to credit risk is partially related to financial assets recorded on the condensed consolidated balance sheets, including commodity derivative instruments that have a positive market value. Additionally, the Company maintains its primary bank accounts with a single large, global bank.

The Company is not currently aware of any exceptional event, dispute, risks or contingent liabilities that could have a material impact on the assets and liabilities, results, financial position or operations of the Company.

The Company is subject to U.S. federal income tax as well as income in various state jurisdictions, and the Company’s operating cash flow is sensitive to the amount of income taxes the Company must pay. In the jurisdictions in which the Company operates or previously operated, income taxes are assessed on earnings after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs that are considered allowable deductions (such as intangible drilling costs) and the timing of such deductions, or the rates assessed on the Company’s taxable earnings would all impact the Company’s income taxes and resulting operating cash flow. In addition, new taxes are from time to time proposed and, if enacted, could adversely impact the Company.

Substantially all of the Company’s accounts receivable result from the sale of natural gas and joint interest billings. The Company sells natural gas, NGLs and oil to fewer than five customers and bills working interest owners for costs related to development of the Company’s natural gas properties. The

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Company does not believe that the loss of any of these customers would have a material adverse effect on the condensed consolidated financial statements because alternative customers are readily available.

Note 14 — Commitments and Contingencies

From time to time, the Company may be subject to various claims, title matters and legal proceedings arising in the ordinary course of business, including environmental contamination claims, personal injury and property damage claims, claims related to joint interest billings and other matters under natural gas operating agreements and other contractual disputes. The Company maintains general liability and other insurance to cover some of these potential liabilities. All known liabilities are fully accrued based on the Company’s best estimate of the potential loss. While the outcome and impact on the Company cannot be predicted with certainty, the Company believes that its ultimate liability with respect to any such matters will not have a significant impact or material adverse effect on its financial positions, results of operations or cash flows. Results of operations and cash flows, however, could be significantly impacted in the reporting periods in which such matters are resolved.

The Company was involved in an arbitration against an operator related to to the breach of various provisions of a certain agreement related to the construction and operation of a midstream gathering system. On February 18, 2022, the Company agreed to settle with the operator, and as a result, received payment of $35.0 million to settle all past disputes and agreed to a midstream gathering rate going forward. Of the $35.0 million, $18.1 million was considered collection of accounts receivable, the remaining $16.9 million is considered a contingent gain, and is included in the condensed consolidated statement of operations and comprehensive income (loss) for the six months ended June 30, 2022, as gain on the settlement of litigation.

The Company has volume commitments in the form of gathering, processing and transportation agreements with various third parties that require delivery of 913,291,106 Dth of natural gas. The majority of the agreements terminate by 2026, with one agreement extending through 2036. As of June 30, 2022, the aggregate undiscounted future payments required under these contracts total $252.1 million. The Company expects to fulfill the commitments from existing productive wells.

The Company has committed to spend $3.5 million on a field compression related capital project by December 31, 2022.

As a part of the consideration paid for the Devon Barnett Acquisition, additional cash consideration will be required to be paid if certain hurdle rates are reached related to future average closing Henry Hub natural gas and West Texas Intermediate crude oil prices during the period beginning January 2021 through December 31, 2024. During the six months ended June 30, 2022, the Company settled the 2021 portion of the arrangement resulting in a payment of $65.0 million and was paid on January 18, 2022. For the remaining years ending December 31, 2022 through 2024, average Henry Hub natural gas hurdle rates are $3.00/MMBTU, $3.25/MMBTU and $3.50/MMBTU, respectively; average West Texas Intermediate crude oil hurdle rates for the years ending December 31, 2022 through 2024 are $55.00/BBL, $60.00/BBL, and $65.00/​BBL, respectively. The maximum amount payable under the arrangement is $195.0 million, or $65.0 million per year, for the years ending December 31, 2022-2024. Payments are due in the month following the end of the respective measurement period for which the hurdle rates are set. As described in Note 4 — Fair Value Measurements, management uses NYMEX forward pricing estimates for both Henry Hub and West Texas Intermediate hurdle rates and Monte Carlo simulations to determine the fair value of the contingent consideration. As of June 30, 2022 and December 31, 2021, the Company’s estimate of the fair value of the unsettled contingent consideration was $174.4 million and $142.5 million, respectively. The change in the fair value of the contingent consideration for the three months ended June 30, 2022 and 2021 was $1.4 million and $31.9 million, respectively, and $31.9 million and $115.3 million for the six months ended June 30, 2022 and 2021, respectively, increasing the associated liability on the Condensed Consolidated Balance Sheets as of June 30, 2022, respectively, and recognition of loss, in the loss on contingent consideration liabilities on the condensed consolidated statements of operations and comprehensive income (loss), respectively.

In conjunction with the Exxon Barnett Acquisition (see Note 2 — Acquisition) additional cash consideration will be required to be paid by the Company if thresholds are met for future Henry Hub for the years ended December 31, 2023, and 2024. Henry Hub payouts and thresholds are as follows for the year

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ended December 31, 2023 : $4.00/MMBTU $10.0 million, $4.50/MMBTU $17.5 million, and $5.00/​MMBTU $25.0 million. Henry Hub payouts and thresholds are as follows for the year ended December 31, 2024: $3.75/MMBTU $10.0 million, $4.25/MMBTU $17.5 million, and $4.75/MMBTU $25.0 million, Payments of the additional cash consideration are due as of January 31, of the calendar year following the applicable threshold measurement periods.The fair value of the contingent consideration as of the acquisition date of June 30, 2022, was $17.2 million. Refer to Note 4 — Fair Value Measurements for the valuation methodology and associated inputs.

A summary of the Company’s commitments, excluding contingent consideration, as of June 30, 2022, is provided in the following table:

(in thousands)	2022			2023			2024			2025			2026			Thereafter			Total
Term loan payments	​	$	—	​	$	114,000	​	$	114,000	​	$	114,000	​	$	114,000	​	$	114,000	​	$	570,000
Credit facility	​	​	30,000	​	​	—	​	​	—	​	​	—	​	​	—	​	​	—	​	​	30,000
Notes payable to related party	​	​	—	​	​	—	​	​	—	​	​	—	​	​	—	​	​	191,000	​	​	191,000
Interest on related party notes	​	​	2,894	​	​	—	​	​	—	​	​	—	​	​	—	​	​	—	​	​	2,894
Lease payments	​	​	5,905	​	​	1,517	​	​	1,029	​	​	972	​	​	848	​	​	1,664	​	​	11,935
Capital commitment	​	​	3,500	​	​	—	​	​	—	​	​	—	​	​	—	​	​	—	​	​	3,500
Volume commitments	​	​	28,426	​	​	56,313	​	​	41,198	​	​	24,227	​	​	19,627	​	​	82,320	​	​	252,111
Total	​	$	70,725	​	$	171,830	​	$	156,227	​	$	139,199	​	$	134,475	​	$	388,984	​	$	1,061,440

On August 22, 2022, the Company entered into a management services agreement with a third party to provide general administrative and management services for carbon capture projects to BKVerde. Pursuant to the management services agreement, the Company is required to make quarterly payments of $2.0 million, beginning in August 2022 through February 2024. The agreement can be terminated with mutual consent from the Company and the third party. During this time period the third party will facilitate the administration and development of carbon capture projects.Under the arrangement, the Company also paid a one-time fee of $4.8 million to allow the Company access to carbon capture projects previously identified by the third party.

Pursuant to an ISDA Master Agreement for derivative contracts (the “Master Agreement”) between the Company and the counterparty thereto (the “Counterparty”), the Company was subject to a covenant that restricted the Company from creating, issuing, incurring, or assuming additional indebtedness in excess of $75.0 million. In June 2022, the Company entered into a term loan credit agreement and borrowed $570.0 million of term loans thereunder. In connection with the Company’s exceeding this $75.0 million indebtedness threshold, on August 4, 2022, the Company executed the 3rd Amendment to the Master Agreement (the “3rd Amendment”) with the Counterparty. Pursuant to the 3rd Amendment, the Company was required to novate or terminate, at the election of the Company, $100.0 million in derivative contracts by October 4, 2022. As of September 15, 2022, the Company terminated derivative contracts of $100.2 million with the Counterparty to meet this requirement. The Company is required to make cash payments for the $100.2 million of terminations of derivative contract which are due in the aggregate by November 30, 2022. The 3rd Amendment also includes a cross default provision pursuant to which a default by the Company related to the covenants under the Company’s term loan credit agreement would cause a default under the Master Agreement. In addition, the Company’s satisfaction of the previously described obligation with respect to termination of derivative contracts caused the debt incurrence covenant in the Master Agreement to no longer apply.

Note 15 — Income Taxes

The effective tax rates for the three and six months ended June 30, 2022 were 10.4% and (45.0%), respectively, and 23.0% and 23.0% for the three and six months ended June 30, 2021. The effective tax rates differ from the U.S. statutory federal income tax rate of 21.0% primarily due to state taxes. Additionally, for the three and six months ended June 30, 2022, the decrease in the tax rate was primarily due to the recording of a bargain purchase gain on the Exxon Barnett Acquisition, which was nontaxable.

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Note 16 — Earnings Per Share

Basic net income or (loss) and comprehensive income or (loss) per common share is calculated by dividing net income or (loss) available to common stockholders of the Company by the basic weighted average number of common shares outstanding for the respective period. Diluted net income (loss) and comprehensive income (loss) per common share is calculated by dividing net income (loss) available to common stockholders of the Company by the diluted weighted average number of common shares outstanding for the respective period. Diluted weighted average number of common shares outstanding and the dilutive effect of potential common shares is calculated using the treasury method for RSUs or if converted method for preferred stock. The Company includes potential shares of common stock for PRSUs in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the reporting period was also the end of the performance period. During periods in which the Company incurred a net loss, diluted weighted average common shares outstanding were equal to basic weighted average of common shares outstanding because the effects of all potential common shares was anti-dilutive.

The following is a reconciliation of the Company’s basic weighted average number of common shares outstanding to the diluted weighted average number of common shares outstanding:

​	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2022		2021		2022		2021
Basic weighted average common shares outstanding	​	117,318	​	116,996	​	117,310	​	117,052
Add: dilutive effect of TRSUs	​	735	​	—	​	577	​	—
Add: dilutive effect of PRSUs	​	6,392	​	—	​	5,334	​	—
Diluted weighted average of common shares outstanding	​	124,445	​	116,996	​	123,221	​	117,052
Weighted average number of outstanding securities excluded from the calculation of diluted loss and comprehensive loss per share	​	​	​	​	​	​	​	​
TRSUs	​	—	​	32	​	—	​	551
PRSUs	​	—	​	1,647	​	—	​	824
Preferred stock	​	—	​	33,815	​	—	​	34,344

Note 17 — Subsequent Events

The Company has evaluated its subsequent events occurring after June 30, 2022 through September 15, 2022, which represents the date the condensed consolidated financial statements were available to be issued. All such subsequent events are discussed with their relevant section within these notes to the condensed consolidated financial statements. No further subsequent events have been identified.

Events Subsequent to Original Issuance of Financial Statements

In connection with the reissuance of the condensed consolidated financial statements, the Company has evaluated subsequent events occurring after September 15, 2022, through October 25, 2022, the date the condensed consolidated financial statements were available to be reissued. All such subsequent events are outlined below.

On September 16, 2022, the Company repaid $116.0 million that was borrowed under the $116 Million Loan Agreement see Note 7 — Related Parties.

On October 14, 2022, the Company repaid the one month draw of $30.0 million on Facility III, see Note 8- Debt.

On October 18, 2022, the Company terminated $57.4 million of derivative contracts which are payable on March 31, 2023.

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Report of Independent Auditors

To the Management of XTO Energy Inc.

Opinion

We have audited the accompanying statements of revenues and direct operating expenses of the Barnett Assets of XTO Energy Inc. and Barnett Gathering, LLC (the “Company”), for the years ended December 31, 2021 and 2020, including the related notes (referred to as the “statements of revenues and direct operating expenses”).

In our opinion, the accompanying statements of revenues and direct operating expenses present fairly, in all material respects, the revenues in excess of direct operating expenses of the Company for the years ended December 31, 2021 and 2020 in accordance with accounting principles generally accepted in the United States of America.

Basis for Opinion

We conducted our audit in accordance with auditing standards generally accepted in the United States of America (US GAAS). Our responsibilities under those standards are further described in the Auditors’ Responsibilities for the Audit of the Statements of Revenues and Direct Operating Expenses section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audit. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Emphasis of Matter

The accompanying statements of revenues and direct operating expenses were prepared in connection with XTO Energy Inc. and Barnett Gathering LLC’s divesture of the Barnett Assets and, as described in Note 1, were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. The statements of revenues and direct operating expenses are not intended to be a complete presentation of the financial position, results of operations or cash flows of the Barnett Assets of XTO Energy Inc. and Barnett Gathering LLC. Our opinion is not modified with respect to this matter.

Responsibilities of Management for the Statements of Revenues and Direct Operating Expenses

Management is responsible for the preparation and fair presentation of the statements of revenues and direct operating expenses in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of the statements of revenue and direct operating expenses that are free from material misstatement, whether due to fraud or error.

In preparing the statements of revenues and direct operating expenses, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for one year after the date the statements of revenues and direct operating expenses are available to be issued.

Auditors’ Responsibilities for the Audit of the Statements of Revenues and Direct Operating Expenses

Our objectives are to obtain reasonable assurance about whether the statements of revenues and direct operating expenses as a whole is free from material misstatement, whether due to fraud or error, and to issue an auditors’ report that includes our opinion. Reasonable assurance is a high level of assurance but is not

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absolute assurance and therefore is not a guarantee that an audit conducted in accordance with US GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the statements of revenues and direct operating expenses.

In performing an audit in accordance with US GAAS, we:

•

Exercise professional judgment and maintain professional skepticism throughout the audit.

•

Identify and assess the risks of material misstatement of the statements of revenues and direct operating expenses, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the statements of revenues and direct operating expenses.

•

Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, no such opinion is expressed.

•

Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the statements of revenue and direct operating expenses.

•

Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for a reasonable period of time.

We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.

/s/ PricewaterhouseCoopers LLP

Dallas, Texas
September 12, 2022

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BARNETT ASSETS

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

​	Year Ended December 31,				Six Months Ended June 30,
(in U.S. Dollars)	2021		2020		2022		2021
​	​	​	​	​	(Unaudited)
REVENUES	​	​	​	​	​	​	​	​
Oil and condensate, gas and NGL sales	​	307,980,127	​	183,587,740	​	219,232,387	​	117,279,977
Midstream operating revenues	​	6,243,524	​	6,400,076	​	3,620,836	​	2,788,135
Other revenues	​	267,540	​	395,570	​	247,704	​	127,602
Total Revenues	​	314,491,191	​	190,383,386	​	223,100,927	​	120,195,714
DIRECT OPERATING EXPENSES	​	​	​	​	​	​	​	​
Lease operating expense	​	76,921,954	​	83,055,070	​	47,456,160	​	36,713,078
Overhead costs	​	20,826,466	​	20,523,594	​	10,720,051	​	10,442,276
Cost of goods sold	​	49,794,678	​	50,306,855	​	25,320,736	​	22,616,152
Production and property taxes	​	21,667,036	​	17,056,948	​	10,696,307	​	4,262,571
Total Direct Operating Expenses	​	169,210,134	​	170,942,467	​	94,193,254	​	74,034,077
REVENUES IN EXCESS OF DIRECT OPERATING EXPENSES	​	145,281,057	​	19,440,919	​	128,907,673	​	46,161,637

F-84

BARNETT ASSETS

NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
Years Ended December 31, 2021 and 2020 and Six Months Ended June 30, 2022 and 2021 (unaudited)

Note 1 — Basis of Presentation

XTO Energy Inc. and Barnett Gathering, LLC (together, the “Company”), wholly-owned subsidiaries of ExxonMobil Corporation owned oil and gas properties located in the Barnett Shale/Fort Worth Basin (the “Properties”), consisting of approximately 160,000 net acres, 2700 gross wells, and certain midstream gathering infrastructure. On May 18, 2022, the Company entered into a purchase and sale agreement with BKV North Texas, LLC and BKV Midstream, LLC (together, “BKV” or the “Buyer”), under which BKV agreed to acquire the Properties from the Company in a cash transaction for aggregate consideration of $750.0 million, subject to customary closing purchase price adjustments and certain additional contingent payments. The transaction closed on June 30, 2022.

The Statements of Revenues and Direct Operating Expenses (the “Statements”) have been derived from the historical financial records of the Company, which represent their interests in revenues and expenses associated with the Properties, and were not accounted for as a separate subsidiary or division during the periods presented. Accordingly, a complete set of financial statements required by Regulation S-X, including a balance sheet and cash flow statement, prepared under U.S. generally accepted accounting principles (“GAAP”) is not available or practicable to prepare for the Properties.

The Statements are not intended to be a complete presentation of the results of operations of the Properties as they do not include depreciation, depletion and amortization, accretion of asset retirement obligations, general and administrative expenses, interest expense, and income taxes. These costs are excluded because they are either not comparable to future operations, or they were not separately allocated to the Properties in the Company’s historical accounting records. In addition to these exclusions, the Statements may not be representative of future operations due to potential changes in the business of the Buyer.

The accompanying Statements for the six months ended June 30, 2022 and 2021 are unaudited. The unaudited interim Statements have been prepared on the same basis as the annual Statements. In the opinion of management, such unaudited interim statements reflect all adjustments necessary for fair statement of the revenues and direct operating expenses of the Properties.

Note 2 — Use of Estimates in Preparation of the Statements

The preparation of these Statements requires management to make estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the respective reporting periods. Actual results may differ from the estimates and assumptions used in the preparation of the Statements.

Note 3 — Revenue Recognition

The Company generally sells crude oil and natural gas under short-term agreements at prevailing market prices. In some cases (e.g., natural gas), products may be sold under long-term agreements, with periodic price adjustments to reflect market conditions. Revenue is recognized at the amount the Company expects to receive when the customer has taken control, which is typically when title transfers and the customer has assumed the risks and rewards of ownership. The prices of certain sales are based on price indices that are sometimes not available until the next period. In such cases, estimated realizations are accrued when the sale is recognized, and are finalized when the price is available. Such adjustments to revenue from performance obligations satisfied in previous periods are not significant. Payment for revenue transactions is typically due within 30 days. Future volume delivery obligations that are unsatisfied at the end of the period are expected to be fulfilled through ordinary production or purchases. These performance obligations are based on market prices at the time of the transaction and are fully constrained due to market price volatility.

Note 4 — Direct Operating Expenses

Direct operating expenses are recognized when incurred and consist of direct operating expenses of the Properties. The direct operating expenses include lease operating expenses and deductions. Lease operating

F-85

BARNETT ASSETS

NOTES TO THE STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES
Years Ended December 31, 2021 and 2020 and Six Months Ended June 30, 2022 and 2021 (unaudited) (continued)

expenses include lifting costs, well repair expenses, facility maintenance expenses, well workover costs, and other field-related expenses. Lease operating expenses also include overhead and expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and gas production activities. Other deductions include cost of goods sold such as gathering and transportation expenses, and purchases of third party gas. Deductions also include the associated production taxes and property taxes associated with the Properties.

Note 5 — Subsequent Events

The Company has evaluated subsequent events through September 12, 2022, the date the Statements of Revenues and Direct Operating Expenses were available to be issued, and has concluded that no events need to be reported.

F-86

BARNETT ASSETS

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Estimated Quantities of Proved Oil, Natural Gas, and NGL Reserve Quantities

Estimated quantities of proved natural gas, NGL and oil reserves at December 31, 2021, and December 31, 2020 and changes in the reserves during each period for the Properties, are shown below. For the years ended December 31, 2021 and 2020 all reserves are proved developed.

These estimates have been prepared in accordance with SEC regulations regarding oil and natural gas reserve reporting using the average price during the trailing 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month.

Estimates of proved natural gas, NGL and oil reserves have been completed in accordance with professional engineering standards. The estimates of proved natural gas, NGL and oil reserves were prepared by the Buyer’s petroleum engineers for the years ended December 31, 2021 and 2020. Those proved reserves estimates were calculated by adding back production (rolled back) and adjusting for pricing from a reserve report prepared by Ryder Scott Company L.P., an independent petroleum consulting firm engaged by the Buyer, as of June 30, 2022, as this method was deemed to provide the best estimates based on information available.

​	Natural Gas (MMcf)		NGL (MBbls)		Oil (MBbls)		Total (MMcfe)
January 1, 2020	​	965,033	​	18,703	​	189	​	1,078,385
Revision of previous estimates(1)	​	(217,748)	​	(4,441)	​	(45)	​	(244,664)
Production	​	(85,388)	​	(1,435)	​	(19)	​	(94,112)
December 31, 2020	​	661,897	​	12,827	​	125	​	739,609
Revision of previous estimates(2)	​	359,153	​	6,807	​	77	​	400,457
Production	​	(74,076)	​	(1,283)	​	(18)	​	(81,882)
December 31, 2021	​	946,974	​	18,351	​	184	​	1,058,184

(1)

The downward revisions of previous estimates of 244,664 MMcfe for the year ended December 31, 2020 were the result of lower product pricing.

(2)

The upward revisions of previous estimates of 400,457 MMcfe for the year ended December 31, 2021 were the result of higher commodity prices and improved well performance.

F-87

BARNETT ASSETS

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (continued)

Standardized Measure of Discounted Future Net Cash Flows

The Buyer prepared the following summary which sets forth the Buyer’s future net cash flows relating to proved natural gas, NGL and oil reserves based on the standardized measure for the years ended December 31, 2021 and 2020. As discussed in Note 1 Basis of Preparation, the effects of federal income taxes are not included in the accompanying Statements, and similarly are not included in the standardized measure presented.

Future cash flows (in thousands)	As of December 31,
	2021			2020
Future estimated revenues(1)	​	$	2,724,244	​	$	686,798
Future estimated production costs(2)	​	​	(1,190,931)	​	​	(508,748)
Future estimated development costs(2)	​	​	(121,966)	​	​	(122,467)
Future income tax expense(3)	​	​	(14,302)	​	​	(3,606)
Future net cash flows	​	​	1,397,045	​	​	51,977
10% annual discount for estimated timing of cash flows	​	​	(688,067)	​	​	(25,602)
Standardized measure of discounted future net cash flows related to proved reserves	​	$	708,978	​	$	26,375

(1)

In accordance with SEC regulations regarding oil and natural gas reserve reporting, reserves were estimated using the average price during the trailing 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month.

(2)

Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions.

(3)

As stated above, no provisions for future federal income taxes were included; however, provisions for future obligations under the Texas gross margin tax are included.

F-88

BARNETT ASSETS

SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (continued)

The following table summarizes the changes in the Standardized Measure of discount future net cash flows:

​	For the Years Ended December 31,
(in thousands)	2021			2020
Balance, beginning of period	​	$	26,375	​	$	341,528
Net change in sales and transfer prices and in production (lifting) costs related to future production	​	​	574,114	​	​	(179,269)
Changes in estimated future development costs	​	​	148	​	​	(782)
Sales and transfers of natural gas, NGLs and oil produced during the period	​	​	(188,565)	​	​	(62,952)
Net change due to revisions in quantity estimates	​	​	278,939	​	​	(104,659)
Net change in future income taxes	​	​	(4,558)	​	​	2,402
Accretion of discount	​	​	2,815	​	​	34,571
Changes in timing and other	​	​	19,710	​	​	(4,464)
Total discounted cash flow as end of period	​	$	708,978	​	$	26,375

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations involve significant estimates and judgments. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the prices and costs utilized in the computation of reported amounts above. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

F-89

PART II INFORMATION

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13.   Other Expenses of Issuance and Distribution.

The following table sets forth the various expenses, other than underwriting discounts and commissions, payable by us in connection with the offering of our common stock contemplated by this registration statement. All of the fees set forth below are estimates, except for the SEC registration fee, the Financial Industry Regulatory Authority, Inc. (“FINRA”) filing fee and the NYSE listing fee.

SEC registration fee	$	*
FINRA filing fee	​	*
NYSE listing fees	​	*
Transfer agent and registrar fees and expenses	​	*
Printing fees and expenses	​	*
Legal fees and expenses	​	*
Accounting fees and expenses	​	*
Miscellaneous	​	*
Total	$	*

*

To be provided by amendment.

Item 14.   Indemnification of Directors and Officers.

Our certificate of incorporation will provide that directors and officers will not be liable to the Company or its stockholders for monetary damages to the fullest extent permitted by the DGCL. In addition, if the DGCL is amended to authorize the further elimination or limitation of the liability of directors and officers, then the liability of a director or officer of the Company, in addition to the limitation on personal liability provided for in our certificate of incorporation, will be limited to the fullest extent permitted by the amended DGCL. Our bylaws will provide that the Company will indemnify, and advance expenses to, any officer or director to the fullest extent authorized by the DGCL.

Section 145 of the DGCL provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses, including attorneys’ fees, judgments, fines and amounts paid in settlement in connection with specified actions, suits and proceedings whether civil, criminal, administrative, or investigative, other than a derivative action by or in the right of the corporation, if they acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe their conduct was unlawful. A similar standard is applicable in the case of derivative actions, except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation. The statute provides that it is not exclusive of other indemnification that may be granted by a corporation’s certificate of incorporation, bylaws, disinterested director vote, stockholder vote, agreement or otherwise.

Our certificate of incorporation will also contain indemnification rights for our directors and our officers. Specifically, our certificate of incorporation will provide that we shall defend, indemnify and advance expenses to our officers and directors to the fullest extent authorized by the DGCL. Further, we may maintain insurance on behalf of our officers and directors against expense, liability or loss asserted incurred by them in their capacities as officers and directors.

In addition, we intend to enter into indemnification agreements, to be effective upon the completion of this offering, with our current directors and officers containing provisions that are in some respects broader than the specific indemnification provisions contained in the DGCL. The indemnification agreements will

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require us, among other things, to indemnify our directors and officers against certain liabilities that may arise by reason of their status or service as directors or officers and to advance their expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and officers.

We intend to maintain liability insurance policies that indemnify our directors and officers against various liabilities, including certain liabilities arising under the Securities Act or the Exchange Act that may be incurred by them in their capacity as such.

The proposed form of Underwriting Agreement to be filed as Exhibit 1.1 to this registration statement provides for indemnification of our directors and officers by the underwriters against certain liabilities arising under the Securities Act or otherwise in connection with this offering.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

Item 15.   Recent Sales of Unregistered Securities.

In the three years preceding the filing of this registration statement, we have issued the following unregistered securities.

Corporatization Event

The information set forth in “Business — Our History  — The Corporatization Event” of the prospectus is incorporated herein by reference. On May 1, 2020, as part of the Corporatization Event, the Company issued 92,700,000 shares of its common stock in exchange for a contribution by the partners of BKV O&G of all of the partnership interests in BKV O&G and 2,000,000 shares of its common stock in exchange for a contribution by the members of Kalnin Ventures of all of the membership interests in Kalnin Ventures. The foregoing issuances were made under an exemption from registration provided by Section 4(a)(2) of the Securities Act, and no underwriters were involved in these transactions.

Other Equity Issuances

On October 1, 2020, the Company issued 22,284,000 shares of its common stock to an existing investor, BNAC, for $222.8 million. The foregoing issuance was made under an exemption from registration provided by Section 4(a)(2) of the Securities Act, and no underwriters were involved in this transaction.

On December 15, 2020, the Company issued 100,000 shares of its common stock to a new investor, OCM BKV Holdings, LLC, an affiliate of Oaktree Capital Management L.P., for $1.0 million, net of associated costs. These shares were issued in connection with the issuance of 9,900,000 shares of Series A Redeemable Preferred Stock, par value $10.00 per share, of the Company (the “Series A preferred stock”), to the same investor in a private placement for $99.0 million. The foregoing issuances were made under an exemption from registration provided by Section 4(a)(2) of the Securities Act and Rule 506(b) of Regulation D promulgated thereunder, and no underwriters were involved in these transactions. The Company redeemed a portion of such shares of Series A preferred stock in May 2021 and the remainder in October 2021.

2021 Plan Issuances

From January 1, 2021 through December 31, 2021, performance restricted stock units (PRSUs) were legally granted under the 2021 Plan, which, assuming vesting at maximum payout, would result in the vesting of 12,256,502 shares of the Company’s common stock, and 656,595 time restricted stock units (TRSUs) were legally granted, of which 164,112 TRSUs were vested at the time of grant and 155,098 TRSUs have since vested. From December 31, 2021 and through the date of this registration statement, additional PRSUs were legally granted, which, assuming vesting at maximum payout, would result in the vesting of 466,200 shares of the Company’s common stock, and 645,760 TRSUs were legally granted, of which 161,398 TRSUs were vested as of the date of this registration statement. Such awards under the 2021 Plan were granted to employees and directors of the Company or its subsidiaries. The foregoing issuances were made under an

II-2

exemption from registration provided by either (i) Rule 701 under the Securities Act as transactions pursuant to compensatory benefit plans and contracts relating to compensation; or (ii) Section 4(a)(2) of the Securities Act as transactions by an issuer not involving any public offering. Any outstanding and unvested PRSUs and TRSUs will vest in connection with this offering.

2020 ESPP Issuances

In December 2021, the Company issued 287,209 shares of its common stock through sales under the 2020 ESPP and received proceeds of approximately $3.2 million from such sales. In April 2022, the Company issued 5,125 shares of its common stock through sales under the 2020 ESPP and received proceeds of $78,310 from such sales. Such sales under the 2020 ESPP were made to certain employees and directors of the Company. The foregoing issuances were made under an exemption from registration provided by either (i) Rule 701 under the Securities Act as transactions pursuant to compensatory benefit plans and contracts relating to compensation; or (ii) Section 4(a)(2) of the Securities Act as transactions by an issuer not involving any public offering.

Item 16.   Exhibits and Financial Statement Schedules.

(a)   Exhibits:   The list of exhibits set forth under “Exhibit Index” at the end of this registration statement is incorporated herein by reference.

Item 17.   Undertakings.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the Underwriting Agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1)   For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2)   For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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EXHIBIT INDEX

Exhibit Number	Description
1.1*	Form of Underwriting Agreement
2.1+‡**	Purchase and Sale Agreement, dated December 17, 2019, between Devon Energy Production Company, L.P. and BKV Barnett, LLC
2.2+**	First Amendment to Purchase and Sale Agreement, dated April 13, 2020, among Devon Energy Production Company, L.P., BKV Barnett, LLC and, solely with respect to the sections listed therein, BKV Oil & Gas Capital Partners, L.P.
2.3+**	Purchase and Sale Agreement, dated May 18, 2022, between XTO Energy Inc., Barnett Gathering, LLC, BKV North Texas, LLC and BKV Midstream, LLC
3.1**	Amended and Restated Certificate of Incorporation of BKV Corporation, as currently in effect
3.2**	Bylaws of BKV Corporation, as currently in effect
3.3	Form of Second Amended and Restated Certificate of Incorporation of BKV Corporation, to be in effect upon completion of this offering
3.4**	Form of Amended and Restated Bylaws of BKV Corporation, to be in effect upon completion of this offering
4.1	Form of Common Stock Certificate
5.1*	Opinion of Baker Botts L.L.P. as to the legality of the securities being registered
10.1+**	Credit Agreement, dated June 16, 2022, among BKV Corporation, the lenders party thereto and Bangkok Bank Public Company Limited, New York Branch
10.2**	Amended and Restated Loan Agreement, dated June 15, 2022, between Banpu North America Corporation and BKV Corporation, in the amount of $116,000,000
10.3**	Amended and Restated Loan Agreement, dated June 15, 2022, between Banpu North America Corporation and BKV Corporation, in the amount of $75,000,000
10.4+**	Revolving Credit Agreement, dated August 24, 2022, among BKV Corporation, the lenders party thereto and Bangkok Bank Public Company Limited, New York Branch
10.5	Form of Stockholders’ Agreement to be entered into between BKV Corporation and Banpu North America Corporation
10.6	Form of Amended and Restated Tax Sharing Agreement to be entered into between BKV Corporation and Banpu North America Corporation
10.7†‡	BKV Corporation 2021 Long Term Incentive Plan, adopted January 1, 2021 (the “2021 Plan”)
10.8†	First Amendment to the 2021 Plan, dated November 5, 2021
10.9†‡	Form of Time Restricted Stock Unit Award and Performance-Based Restricted Stock Unit Award Notice and Award Agreement under the 2021 Plan
10.10†	Form of Time Restricted Stock Unit Award Notice and Award Agreement under the 2021 Plan
10.11†	BKV Corporation 2020 Employee Stock Purchase Plan, adopted July 16, 2020
10.12†	First Amendment to the BKV Corporation 2020 Employee Stock Purchase Plan, dated November 5, 2021
10.13†	Second Amendment to the BKV Corporation 2020 Employee Stock Purchase Plan, dated April 21, 2022
10.14†	BKV Corporation 2022 Equity and Incentive Compensation Plan (the “2022 Plan”)
10.15*†	Form of RSU Award Agreement under the 2022 Plan (CEO)
10.16*†	Form of RSU Award Agreement under the 2022 Plan (Non-CEO Employee)
10.17*†	Form of RSU Award Agreement under the 2022 Plan (Director)

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Exhibit Number	Description
10.18*†	Form of Director Indemnification Agreement
10.19†	Employment Agreement, dated August 4, 2020, between BKV Corporation and Christopher P. Kalnin
10.20†	Employment Agreement, dated January 11, 2021, between BKV Corporation and John T. Jimenez
10.21†	Employment Agreement, dated February 18, 2020, between Kalnin Ventures LLC and Eric Jacobsen
10.22†	Employment Agreement, dated January 15, 2021, between BKV Corporation and Brid Kealey
10.23†	Employment Agreement, dated October 15, 2018, between Kalnin Ventures LLC and Lindsay B. Larrick
10.24†	Employment Agreement, dated April 1, 2018, between Kalnin Ventures LLC and An Sao (Ethan) Ngo
10.25+	Limited Liability Company Agreement of BKV-BPP Power, LLC, dated October 29, 2021
10.26†	BKV Corporation Non-Employee Director Compensation Program
10.27+	Credit Facility, dated December 22, 2021, among BKV Corporation, Oversea-Chinese Banking Corporation Limited and the guarantors party thereto
10.28+	Credit Facility, dated February 7, 2022, among BKV Corporation, Standard Chartered Bank, BKV Chaffee Corners, LLC, BKV Chelsea, LLC, BKV Operating, LLC and BKV Barnett, LLC
21.1*	List of Subsidiaries of BKV Corporation
23.1*	Consent of PricewaterhouseCoopers LLP (BKV Corporation)
23.2*	Consent of PricewaterhouseCoopers LLP (ExxonMobil Barnett Assets)
23.3*	Consent of Ryder Scott Company, L.P.
23.4*	Consent of Baker Botts L.L.P. (included as part of Exhibit 5.1 hereto)
24.1*	Power of Attorney (included on the signature page of the initial filing of the registration statement)
99.1	Ryder Scott Company, L.P., Summary of Reserves at December 31, 2020 (SEC Pricing) (BKV Barnett, LLC)
99.2	Ryder Scott Company, L.P., Summary of Reserves at December 31, 2020 (SEC Pricing) (BKV Chaffee Corners, LLC)
99.3	Ryder Scott Company, L.P., Summary of Reserves at December 31, 2020 (SEC Pricing) (BKV Chelsea, LLC)
99.4	Ryder Scott Company, L.P., Summary of Reserves at December 31, 2020 (SEC Pricing) (BKV Operating, LLC)
99.5	Ryder Scott Company, L.P., Summary of Reserves at December 31, 2021 (SEC Pricing) (BKV Barnett, LLC)
99.6	Ryder Scott Company, L.P., Summary of Reserves at December 31, 2021 (SEC Pricing) (BKV Chaffee Corners, LLC)
99.7	Ryder Scott Company, L.P., Summary of Reserves at December 31, 2021 (SEC Pricing) (BKV Chelsea, LLC)
99.8	Ryder Scott Company, L.P., Summary of Reserves at December 31, 2021 (SEC Pricing) (BKV Operating, LLC)
99.9	Ryder Scott Company, L.P., Summary of Reserves at September 30, 2022 (SEC Pricing) (BKV Barnett, LLC)

II-5

Exhibit Number	Description
99.10	Ryder Scott Company, L.P., Summary of Reserves at September 30, 2022 (SEC Pricing) (BKV Chaffee Corners, LLC)
99.11	Ryder Scott Company, L.P., Summary of Reserves at September 30, 2022 (SEC Pricing) (BKV Chelsea, LLC)
99.12	Ryder Scott Company, L.P., Summary of Reserves at September 30, 2022 (SEC Pricing) (BKV Operating, LLC)
99.13	Ryder Scott Company, L.P., Summary of Reserves at September 30, 2022 (SEC Pricing) (Exxon Barnett Acquisition)
107*	Calculation of Filing Fee Table

*

To be filed by amendment.

**

Previously filed.

†

Compensatory plan or arrangement.

+

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

‡

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

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on this       day of       , 2022.

BKV CORPORATION

By:

 

Christopher P. Kalnin
Chief Executive Officer

POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Christopher P. Kalnin and Lindsay B. Larrick, and each of them, his or her true and lawful attorneys-in-fact and agents, each with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments, including post-effective amendments, to this registration statement, and any registration statement relating to the offering covered by this registration statement and filed pursuant to Rule 462(b) under the Securities Act of 1933, and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that each of said attorney-in-fact and agents or their substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933 this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Name	Title	Date
Christopher P. Kalnin	Chief Executive Officer and Director (Principal Executive Officer)	, 2022
John T. Jimenez	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	, 2022
Chanin Vongkusolkit	Chairman of the Board	, 2022
Somruedee Chaimongkol	Director	, 2022
Joseph R. Davis	Director	, 2022
Akaraphong Dayananda	Director	, 2022
Carla S. Mashinski	Director	, 2022

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Name	Title	Date
Thiti Mekavichai	Director	, 2022
Charles C. Miller III	Director	, 2022
Sunit S. Patel	Director	, 2022
Anon Sirisaengtaksin	Director	, 2022
Sinon Vongkusolkit	Director	, 2022

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EX-3.3

Exhibit 3.3

FORM OF

SECOND AMENDED AND RESTATED CERTIFICATE OF INCORPORATION

OF

BKV CORPORATION

BKV Corporation, a corporation organized and existing under the laws of the State of Delaware, pursuant to Sections 242 and 245 of the General Corporation Law of the State of Delaware, hereby certifies as follows:

1.             The present name of the corporation is BKV Corporation. The corporation was incorporated under the name “BKV Corporation” by the filing of its original Certificate of Incorporation, effective as of May 1, 2020, with the Secretary of State of the State of Delaware on April 28, 2020. The original Certificate of Incorporation was amended and restated on December 15, 2020 (as amended and restated, the “Original Certificate of Incorporation”).

2.             This Second Amended and Restated Certificate of Incorporation (this “Amended and Restated Certificate of Incorporation”), which amends, restates and integrates the provisions of the Original Certificate of Incorporation, was duly adopted in accordance with the provisions of Sections 242 and 245 of the General Corporation Law of the State of Delaware by the directors and stockholders of the corporation.

3.             The Original Certificate of Incorporation is hereby amended and restated to read in its entirety as follows:

Article I

Section 1.1         Name. The name of the Corporation is BKV Corporation (the “Corporation”).

Article II

Section 2.1         Address. The registered office of the Corporation in the State of Delaware is 251 Little Falls Drive, Wilmington, New Castle County, Delaware 19808; and the name of the Corporation’s registered agent at such address is Corporation Service Company.

Article III

Section 3.1         Purpose. The purpose of the Corporation is to engage in any lawful act or activity for which corporations may now or hereafter be organized under the General Corporation Law of the State of Delaware (the “DGCL”).

Article IV

Section 4.1         Capitalization. The total number of shares of all classes of stock that the Corporation is authorized to issue is 580,000,000 shares, consisting of (i) 80,000,000 shares of Preferred Stock, par value $0.01 per share (“Preferred Stock”), and (ii) 500,000,000 shares of Common Stock, par value $0.01 per share (“Common Stock”). The number of authorized shares of Common Stock or Preferred Stock may be increased or decreased (but not below the number of shares thereof then outstanding) by the affirmative vote of the holders of a majority in voting power of the stock of the Corporation entitled to vote thereon irrespective of the provisions of Section 242(b)(2) of the DGCL (or any successor provision thereto), and no vote of the holders of Common Stock or Preferred Stock voting separately as a class shall be required therefor, unless a vote of any such holder is required pursuant to this Amended and Restated Certificate of Incorporation (including any certificate of designation relating to any series of Preferred Stock).

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Section 4.2         Preferred Stock.

(A)          The Board of Directors of the Corporation (the “Board”) is hereby expressly authorized, by resolution or resolutions, at any time and from time to time, to provide, out of the unissued shares of Preferred Stock, for one or more series of Preferred Stock and, with respect to each such series, to fix the number of shares constituting such series and the designation of such series, the voting powers (if any) of the shares of such series, and the powers, preferences and relative, participating, optional or other special rights, if any, and any qualifications, limitations or restrictions thereof, of the shares of such series and to cause to be filed with the Secretary of State of the State of Delaware a certificate of designation with respect thereto. The powers, preferences and relative, participating, optional and other special rights of each series of Preferred Stock, and the qualifications, limitations or restrictions thereof, if any, may differ from those of any and all other series at any time outstanding.

(B)           Except as otherwise required by law, holders of a series of Preferred Stock, as such, shall be entitled only to such voting rights, if any, as shall expressly be granted thereto by this Amended and Restated Certificate of Incorporation (including any certificate of designation relating to such series of Preferred Stock).

Section 4.3         Common Stock.

(A)          Voting Rights.

(i)         Each holder of Common Stock, as such, shall be entitled to one vote for each share of Common Stock held of record by such holder on all matters on which stockholders of the Corporation generally are entitled to vote.

(ii)        Notwithstanding the foregoing, to the fullest extent permitted by law, holders of Common Stock, as such, shall have no voting power with respect to, and shall not be entitled to vote on, any amendment to this Amended and Restated Certificate of Incorporation (including any certificate of designation relating to any series of Preferred Stock) that relates solely to the terms of one or more outstanding series of Preferred Stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to this Amended and Restated Certificate of Incorporation (including any certificate of designation relating to any series of Preferred Stock) or pursuant to the DGCL.

(B)           Dividends and Distributions. Subject to applicable law and the rights, if any, of the holders of any outstanding series of Preferred Stock or any class or series of stock having a preference over or the right to participate with the Common Stock with respect to the payment of dividends and other distributions in cash, property of the Corporation or shares of the Corporation’s capital stock, such dividends and other distributions may be declared and paid ratably on the Common Stock out of the assets of the Corporation that are by law available therefor at such times and in such amounts as the Board in its discretion shall determine.

(C)           Liquidation, Dissolution or Winding Up. In the event of any voluntary or involuntary liquidation, dissolution or winding up of the affairs of the Corporation, after payment or provision for payment of the debts and other liabilities of the Corporation and subject to the rights, if any, of the holders of Preferred Stock or any class or series of stock having a preference over or the right to participate with the Common Stock as to distributions upon dissolution or liquidation or winding up, the holders of all outstanding shares of Common Stock shall be entitled to receive the remaining assets of the Corporation available for distribution ratably in proportion to the number of shares held by each such stockholder.

(D)           No Preemptive Rights. No holder of Common Stock shall have any preemptive, conversion or other rights to subscribe for additional shares with respect to the Common Stock or any other securities of the Corporation, or to any obligations convertible (directly or indirectly) into securities of the Corporation, whether now or hereafter authorized.

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Article V

Section 5.1         Amendment of Certificate of Incorporation. Notwithstanding anything to the contrary contained in this Amended and Restated Certificate of Incorporation, in addition to any vote required by this Amended and Restated Certificate of Incorporation, the bylaws of the Corporation (as in effect from time to time, the “Bylaws”) or applicable law or securities exchange rule or regulation, the following provisions in this Amended and Restated Certificate of Incorporation may be amended, altered, repealed or rescinded, in whole or in part, or any provision inconsistent therewith or herewith may be adopted, only by the affirmative vote of the holders of at least sixty-six and two-thirds percent (66 2/3%) in voting power of all the then-outstanding shares of stock of the Corporation entitled to vote thereon, voting together as a single class: this Article V, Article VI, Article VII, Article VIII, Article IX and Article X (the “Specified Provisions”); provided, however, that, in the case of any proposed amendment, alteration, repeal or rescission of, or adoption of any provision inconsistent with, a Specified Provision, (A) as to which the DGCL does not require the consent or vote of the stockholders or (B) that is approved by at least sixty percent (60%) of the Board, then only the affirmative vote of the holders of a majority in voting power of all the then-outstanding shares of stock of the Corporation entitled to vote thereon, voting together as a single class (in addition to any vote required by this Amended and Restated Certificate of Incorporation, the Bylaws or applicable law or securities exchange rule or regulation), shall be required to amend, alter, repeal or rescind, or adopt any provision inconsistent with, a Specified Provision.

Section 5.2         Amendment of Bylaws. The Board is expressly authorized to make, repeal, alter, amend and rescind, in whole or in part, the Bylaws by the affirmative vote of a majority of the total number of directors then in office, without the assent or vote of the stockholders in any manner not inconsistent with the laws of the State of Delaware or this Amended and Restated Certificate of Incorporation. Notwithstanding anything to the contrary contained in this Amended and Restated Certificate of Incorporation or the Bylaws or any provision of law that might otherwise permit a lesser vote of the stockholders, in addition to any vote of the holders of any class or series of capital stock of the Corporation required by this Amended and Restated Certificate of Incorporation (including any certificate of designation relating to any series of Preferred Stock), the Bylaws or applicable law or securities exchange rule or regulation, the affirmative vote of the holders of at least sixty-six and two-thirds percent (66 2/3%) in voting power of all the then-outstanding shares of stock of the Corporation entitled to vote thereon, voting together as a single class, shall be required in order for the stockholders of the Corporation to alter, amend, repeal or rescind, in whole or in part, any provision of the Bylaws or to adopt any provision inconsistent therewith.

Article VI

Section 6.1         Board of Directors.

(A)          Except as provided in this Amended and Restated Certificate of Incorporation and the DGCL, the business and affairs of the Corporation shall be managed by or under the direction of the Board. Except as otherwise provided for or fixed pursuant to the provisions of Article IV (including any certificate of designation with respect to any series of Preferred Stock) and this Article VI relating to the rights of the holders of any series of Preferred Stock to elect additional directors, the total number of directors shall be determined from time to time by the affirmative vote of a majority of the total number of directors then in office. The directors (other than those directors elected by the holders of any series of Preferred Stock, voting separately as a series or together with one or more other such series, as the case may be) shall be divided into three classes designated Class I, Class II and Class III. Each class shall consist, as nearly as possible, of one-third of the total number of such directors. Class I directors shall initially serve for a term expiring at the first annual meeting of stockholders following the initial closing of the registered initial underwritten public offering of the Common Stock (the “IPO Date”), Class II directors shall initially serve for a term expiring at the second annual meeting of stockholders following the IPO Date and Class III directors shall initially serve for a term expiring at the third annual meeting of stockholders following the IPO Date. Commencing with the first annual meeting of stockholders following the IPO Date, the directors of the class to be elected at each annual meeting shall be elected for a three-year term. If the number of such directors is changed, any increase or decrease shall be apportioned among the classes so as to maintain the number of directors in each class as nearly equal as possible, and any such additional director of any class elected to fill a newly created directorship resulting from an increase in such class shall hold office for a term that shall coincide with the remaining term of that class, but in no case shall a decrease in the number of directors remove or shorten the term of any incumbent director. Any such director shall hold office until the annual meeting at which his or her term expires and until his or her successor shall be elected and qualified, or his or her death, resignation, retirement, disqualification or removal from office. The Board is authorized to assign members of the Board already in office to their respective class.

(B)           Subject to the rights granted to the holders of any one or more series of Preferred Stock then outstanding or the rights granted pursuant to the Stockholders’ Agreement, expected to be dated on or about the IPO Date (the “Stockholders’ Agreement”), by and between the Corporation and Banpu North America Corporation (together with its affiliates, subsidiaries, successors and assigns, but excluding the Corporation and its subsidiaries, collectively, “Banpu”), any newly created directorship on the Board that results from an increase in the number of directors and any vacancy occurring in the Board (whether by death, resignation, retirement, disqualification, removal or other cause) shall be filled by a majority of the total number of directors then in office, although less than a quorum, or by a sole remaining director, and not by the stockholders. Any director elected to fill a vacancy or newly created directorship shall hold office until the next election of the class for which such director shall have been chosen and until his or her successor shall be elected and qualified, or until his or her earlier death, resignation, retirement, disqualification or removal.

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(C)           Any or all of the directors (other than the directors elected by the holders of any series of Preferred Stock, voting separately as a series or together with one or more other such series, as the case may be) may be removed only for cause and only by the affirmative vote of the holders of at least sixty percent (60%) in voting power of all the then-outstanding shares of stock of the Corporation entitled to vote thereon, voting together as a single class.

(D)           During any period when the holders of any series of Preferred Stock, voting separately as a series or together with one or more series, have the right to elect additional directors, then upon commencement and for the duration of the period during which such right continues: (i) the then otherwise total authorized number of directors of the Corporation shall automatically be increased by such specified number of directors, and the holders of such Preferred Stock shall be entitled to elect the additional directors so provided for or fixed pursuant to said provisions, and (ii) each such additional director shall serve until such director’s successor shall have been duly elected and qualified, or until such director’s right to hold such office terminates pursuant to said provisions, whichever occurs earlier, subject to his or her earlier death, resignation, retirement, disqualification or removal. Except as otherwise provided by the Board in the resolution or resolutions establishing such series, whenever the holders of any series of Preferred Stock having such right to elect additional directors are divested of such right pursuant to the provisions of such stock, the terms of office of all such additional directors elected by the holders of such stock, or elected to fill any vacancies resulting from the death, resignation, disqualification or removal of such additional directors, shall forthwith terminate and the total authorized number of directors of the Corporation shall be reduced accordingly.

(E)           Elections of directors need not be by written ballot unless the Bylaws shall so provide.

Article VII

Section 7.1         Limitation on Liability of Directors and Officers. To the fullest extent permitted by the DGCL as it now exists or may hereafter be amended and except as otherwise provided in the Bylaws, a director or officer of the Corporation shall not be personally liable to the Corporation or its stockholders for monetary damages for breach of fiduciary duty owed to the Corporation or its stockholders.

Section 7.2         Indemnification and Advancement of Expenses.

(A)          Each person who was or is made a party or is threatened to be made a party to or is otherwise involved in any action, suit or proceeding, whether civil, criminal, administrative or investigative (a “Proceeding”), by reason of the fact that he or she is or was a director or an officer of the Corporation or, while a director or officer of the Corporation, is or was serving at the request of the Corporation as a director, officer, employee, agent or trustee of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to an employee benefit plan (such person solely in any such capacity, an “Indemnitee”), shall be indemnified and held harmless by the Corporation to the fullest extent permitted by the DGCL as it now exists or may hereafter be amended, subject to the terms and conditions set forth in the Bylaws.

(B)           In addition to the right to indemnification conferred in Section 7.2(A), an Indemnitee shall also have the right to be paid by the Corporation the expenses incurred in connection with any such Proceeding in advance of its final disposition to the fullest extent permitted by the DGCL as it now exists or may hereafter be amended, subject to the terms and conditions set forth in the Bylaws.

Section 7.3         Applicability. Neither the amendment nor repeal of this Article VII, nor the adoption of any provision of this Amended and Restated Certificate of Incorporation, nor, to the fullest extent permitted by the DGCL, any modification of law shall eliminate, reduce or otherwise adversely affect any right or protection of a current or former director or officer of the Corporation existing at the time of such amendment, repeal, adoption or modification. If the DGCL is subsequently amended to authorize corporate action further eliminating or limiting the personal liability of directors or officers, then the liability of a director or officer, as applicable, to the Corporation shall be eliminated or limited to the fullest extent permitted by the DGCL as so amended.

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Article VIII

Section 8.1         Consent of Stockholders in Lieu of Meeting. At any time when Banpu beneficially owns, in the aggregate, at least thirty-five percent (35%) in voting power of the stock of the Corporation entitled to vote generally in the election of directors, any action required or permitted to be taken at any annual or special meeting of stockholders of the Corporation may be taken without a meeting, without prior notice and without a vote, if a consent or consents in writing, setting forth the action so taken, shall be signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted and shall be delivered to the Corporation by delivery to its registered office in the State of Delaware, its principal place of business, or an officer or agent of the Corporation having custody of the books in which proceedings of meetings of stockholders are recorded. Delivery made to the Corporation’s registered office shall be made by hand or by certified or registered mail, return receipt requested. At any time when Banpu beneficially owns, in the aggregate, less than thirty-five percent (35%) in voting power of the stock of the Corporation entitled to vote generally in the election of directors, any action required or permitted to be taken by the stockholders of the Corporation must be effected at a duly called annual or special meeting of such holders and may not be effected by any consent in writing by such holders; provided, however, that any action required or permitted to be taken by the holders of Preferred Stock, voting separately as a series or separately as a class with one or more other such series, may be taken without a meeting, without prior notice and without a vote, to the extent expressly so provided by the applicable certificate of designation relating to such series of Preferred Stock. For the purposes of this Amended and Restated Certificate of Incorporation, beneficial ownership of shares shall be determined in accordance with Rule 13d-3 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

Section 8.2         Special Meetings of the Stockholders. Except as otherwise required by law and subject to the rights of the holders of any series of Preferred Stock, special meetings of the stockholders of the Corporation for any purpose or purposes may be called at any time only by or at the direction of the Board by the affirmative vote of a majority of the total number of directors then in office, the Chairman of the Board or the Chief Executive Officer of the Corporation, and may not be called by any other person or persons.

Section 8.3         Annual Meetings of the Stockholders. An annual meeting of stockholders for the election of directors to succeed those whose terms expire and for the transaction of such other business as may properly come before the meeting, shall be held at such place, if any, on such date, and at such time as shall be fixed exclusively by resolution of the Board or a duly authorized committee thereof.

Article IX

Section 9.1         Competition and Corporate Opportunities.

(A)           In recognition and anticipation that (i) certain directors, principals, officers, employees and/or other representatives of Banpu and its Affiliates (as defined below) may serve as directors, officers or agents of the Corporation, (ii) Banpu and its Affiliates may now engage and may continue to engage in the same or similar activities or related lines of business as those in which the Corporation, directly or indirectly, may engage and/or other business activities that overlap with or compete with those in which the Corporation, directly or indirectly, may engage, and (iii) members of the Board who are not employees of the Corporation (the “Non-Employee Directors”) and their respective Affiliates may now engage and may continue to engage in the same or similar activities or related lines of business as those in which the Corporation, directly or indirectly, may engage and/or other business activities that overlap with or compete with those in which the Corporation, directly or indirectly, may engage, the provisions of this Article IX are set forth to regulate and define the conduct of certain affairs of the Corporation with respect to certain classes or categories of business opportunities as they may involve Banpu, the Non-Employee Directors or their respective Affiliates and the powers, rights, duties and liabilities of the Corporation and its directors, officers and stockholders in connection therewith.

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(B)           None of (i) Banpu or any of its Affiliates or (ii) any Non-Employee Director (including any Non-Employee Director who serves as an officer of the Corporation in both his or her director and officer capacities) or his or her Affiliates (the Persons (as defined below) identified in (i) and (ii) above being referred to, collectively, as “Identified Persons” and, individually, as an “Identified Person”) shall, to the fullest extent permitted by law, have any duty to refrain from directly or indirectly (1) engaging in the same or similar business activities or lines of business in which the Corporation or any of its Affiliates now engages or proposes to engage or (2) otherwise competing with the Corporation or any of its Affiliates, and, to the fullest extent permitted by law, no Identified Person shall be liable to the Corporation or its stockholders or to any Affiliate of the Corporation for breach of any fiduciary duty solely by reason of the fact that such Identified Person engages in any such activities. To the fullest extent permitted by law, the Corporation hereby renounces any interest or expectancy in, or right to be offered an opportunity to participate in, any business opportunity that may be a corporate opportunity for an Identified Person and the Corporation or any of its Affiliates, except as provided in Section 9.1(C). Subject to Section 9.1(C), in the event that any Identified Person acquires knowledge of a potential transaction or other business opportunity that may be a corporate opportunity for itself, herself or himself and the Corporation or any of its Affiliates, such Identified Person shall, to the fullest extent permitted by law, have no duty to communicate or offer such transaction or other business opportunity to the Corporation or any of its Affiliates and, to the fullest extent permitted by law, shall not be liable to the Corporation or its stockholders or to any Affiliate of the Corporation for breach of any fiduciary duty as a stockholder, director or officer of the Corporation solely by reason of the fact that such Identified Person pursues or acquires such corporate opportunity for itself, herself or himself, or offers or directs such corporate opportunity to another Person.

(C)           The Corporation does not renounce its interest in any corporate opportunity offered to any Non-Employee Director (including any Non-Employee Director who serves as an officer of this Corporation) if such opportunity is expressly offered to such person solely in his or her capacity as a director or officer of the Corporation, and the provisions of Section 9.1(B) shall not apply to any such corporate opportunity.

(D)           In addition to and notwithstanding the foregoing provisions of this Article IX, a corporate opportunity shall not be deemed to be a potential corporate opportunity for the Corporation if it is a business opportunity that (i) the Corporation is neither financially or legally able, nor contractually permitted to undertake, (ii) from its nature, is not in the line of the Corporation’s business or is of no practical advantage to the Corporation or (iii) is one in which the Corporation has no interest or reasonable expectancy.

(E)            For purposes of this Article IX, (i) “Affiliate” shall mean (a) in respect of Banpu, any Person that, directly or indirectly, is controlled by Banpu, controls Banpu or is under common control with Banpu and shall include any principal, member, director, partner, stockholder, officer, employee or other representative of any of the foregoing (other than the Corporation and any entity that is controlled by the Corporation), (b) in respect of a Non-Employee Director, any Person that, directly or indirectly, is controlled by such Non-Employee Director (other than the Corporation and any entity that is controlled by the Corporation) and (c) in respect of the Corporation, any Person that, directly or indirectly, is controlled by the Corporation; and (ii) “Person” shall mean any individual, corporation, general or limited partnership, limited liability company, joint venture, trust, association or any other entity.

(F)           To the fullest extent permitted by law, any Person purchasing or otherwise acquiring any interest in any shares of capital stock of the Corporation shall be deemed to have notice of and to have consented to the provisions of this Article IX.

Article X

Section 10.1       Severability. If any provision or provisions of this Amended and Restated Certificate of Incorporation shall be held to be invalid, illegal or unenforceable as applied to any circumstance for any reason whatsoever: (i) the validity, legality and enforceability of such provisions in any other circumstance and of the remaining provisions of this Amended and Restated Certificate of Incorporation (including, without limitation, each portion of any paragraph of this Amended and Restated Certificate of Incorporation containing any such provision held to be invalid, illegal or unenforceable that is not itself held to be invalid, illegal or unenforceable) shall not, to the fullest extent permitted by applicable law, in any way be affected or impaired thereby and (ii) to the fullest extent permitted by applicable law, the provisions of this Amended and Restated Certificate of Incorporation (including, without limitation, each such portion of any paragraph of this Amended and Restated Certificate of Incorporation containing any such provision held to be invalid, illegal or unenforceable) shall be construed so as to permit the Corporation to protect its directors, officers, employees and agents from personal liability in respect of their good faith service to or for the benefit of the Corporation to the fullest extent permitted by law.

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Section 10.2       Forum.

(A)           Unless the Corporation consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware shall, to the fullest extent permitted by law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of the Corporation, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer or employee of the Corporation to the Corporation or the Corporation’s stockholders, (iii) any action asserting a claim against the Corporation or any director or officer of the Corporation arising pursuant to any provision of the DGCL or this Amended and Restated Certificate of Incorporation or the Bylaws (as either may be amended and/or restated from time to time), or (iv) any action asserting a claim against the Corporation or any director, officer or employee of the Corporation, which claim is governed by the internal affairs doctrine.

(B)           Unless the Corporation consents in writing to the selection of an alternative forum, the federal district courts of the United States of America shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act of 1933, as amended, or the Exchange Act.

(C)           To the fullest extent permitted by law, any person purchasing or otherwise acquiring any interest in shares of capital stock of the Corporation shall be deemed to have notice of and consented to the provisions of this Section 10.2.

* * * * *

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IN WITNESS WHEREOF, the Corporation has caused this Amended and Restated Certificate of Incorporation to be signed by a duly authorized officer of the Corporation on this [ ] day of [         ], 2022.

BKV CORPORATION

By:

Name:

Title:

[Signature Page to Second Amended and Restated Certificate of Incorporation of BKV Corporation]

EX-4.1

Exhibit 4.1

NUMBER SHARES COUNTERSIGNED: BROADRIDGE CORPORATE ISSUER SOLUTIONS, INC. TRANSFER AGENT BY: AUTHORIZED SIGNATURE DATED: INCORPORATED UNDER THE LAWS OF THE STATE OF DELAWARE SEE REVERSE FOR CERTAIN DEFINITIONS This CerTifies ThaT: is The owner of CoMMon sToCK FULLY PAID AND NON-ASSESSABLE SHARES OF COMMON STOCK OF $0.01 PAR VALUE EACH OF BKV Corporation transferable on the books of the Corporation by the holder thereof in person or by duly authorized attorney upon surrender of this certificate duly endorsed or assigned. This certificate and the shares represented hereby are subject to the laws of the State of Delaware, and to the Certificate of Incorporation and Bylaws of the Corporation, as now or hereafter amended. This certificate is not valid until countersigned by the Transfer Agent. WITNESS the facsimile seal of the Corporation and the facsimile signatures of its duly authorized officers. CHRISTOPHER P. KALNIN CHIEF EXECUTIVE OFFICER JOHN T. JIMENEZ CHIEF FINANCIAL OFFICER SPECIMEN SPECIMEN SPECIMEN - NOT NEGOTIABLE SPECIMEN not negotiable

COLUMBIA PRINTING SERVICES, LLC - www.stockinformation.com The following abbreviations, when used in the inscription on the face of this certificate, shall be construed as though they were written out in full according to applicable laws or regulations: TEN COM - as tenants in common UNIF GIFT MIN ACT - ....................Custodian.................... TEN ENT - as tenants by the entireties (Cust) (Minor) JT TEN - as joint tenants with right of under Uniform Gifts to Minors survivorship and not as tenants Act ................................................... in common (State) Additional abbreviations may also be used though not in the above list. For Value Received, hereby sell, assign and transfer unto PLEASE INSERT SOCIAL SECURITY OR OTHER IDENTIFYING NUMBER OF ASSIGNEE ( PLEASE PRINT OR TYPE NAME AND ADDRESS, INCLUDING ZIP CODE, OF ASSIGNEE) Shares of the stock represented by the within Certificate, and do hereby irrevocably constitute and appoint Attorney to transfer the said stock on the books of the within named Corporation with full power of substitution in the premises. Dated NOTICE: THE SIGNATURE TO THIS ASSIGNMENT MUST CORRESPOND WITH THE NAME AS WRITTEN UPON THE FACE OF THE CERTIFICATE IN EVERY PARTICULAR, WITHOUT ALTERATION OR ENLARGEMENT OR ANY CHANGE WHATSOEVER. Signature(s) Guaranteed By The Signature(s) must be guaranteed by an eligible guarantor institution (Banks, Stockbrokers, Savings and Loan Associations and Credit Unions with membership in an approved Signature Guarantee Medallion Program), pursuant to SEC Rule 17Ad-15. THE CORPORATION WILL FURNISH TO ANY STOCKHOLDER, UPON REQUEST AND WITHOUT CHARGE, A FULL STATEMENT OF THE DESIGNATIONS, RELATIVE RIGHTS, PREFERENCES AND LIMITATIONS OF THE SHARES OF EACH CLASS AND SERIES AUTHORIZED TO BE ISSUED, SO FAR AS THE SAME HAVE BEEN DETERMINED, AND OF THE AUTHORITY, IF ANY, OF THE BOARD TO DIVIDE THE SHARES INTO CLASSES OR SERIES AND TO DETERMINE AND CHANGE THE RELATIVE RIGHTS, PREFERENCES AND LIMITATIONS OF ANY CLASS OR SERIES. SUCH REQUEST MAY BE MADE TO THE SECRETARY OF THE CORPORATION OR TO THE TRANSFER AGENT NAMED ON THIS CERTIFICATE.

EX-10.5

Exhibit 10.5

FORM OF

STOCKHOLDERS’ AGREEMENT

DATED AS OF [               ], 2022

BETWEEN

BKV CORPORATION

AND

BANPU NORTH AMERICA CORPORATION

TABLE OF CONTENTS

		Page
Article I INTRODUCTORY MATTERS		1
1.1	Defined Terms	1
1.2	Construction	4
Article II CORPORATE GOVERNANCE MATTERS		5
2.1	Election of Directors	5
2.2	Chairman of the Board	5
2.3	Amendment of Certificate of Incorporation and Bylaws	6
2.4	Reimbursement of Expenses	6
2.5	Indemnification	6
Article III INFORMATION		6
3.1	Information	6
3.2	Certain Reports	7
3.3	Disclosure of Information	7
Article IV REGISTRATION RIGHTS		9
4.1	Demand and Piggyback Rights	9
4.2	Notices, Cutbacks and Other Matters	11
4.3	Facilitating Registrations and Offerings	12
4.4	Reporting Obligations	15
4.5	Indemnification	15
Article V GENERAL PROVISIONS		16
5.1	Termination	16
5.2	Notices	17
5.3	Amendment; Waiver	18
5.4	Further Assurances	18
5.5	Assignment	18
5.6	Third Parties	18
5.7	Governing Law	18
5.8	Jurisdiction; Waiver of Jury Trial	18
5.9	Specific Performance	18
5.10	Entire Agreement	18
5.11	Severability	18
5.12	Table of Contents, Headings and Captions	18
5.13	Counterparts	19
5.14	Effectiveness	19
5.15	No Recourse	19

FORM OF STOCKHOLDERS’ AGREEMENT

This Stockholders’ Agreement is entered into as of [               ], 2022, by and between BKV Corporation, a Delaware corporation (the “Company”), and Banpu North America Corporation, a Delaware corporation (“BNAC“), to be effective as of the Effective Date (as defined herein). Unless otherwise defined herein, capitalized terms used herein shall have the respective meanings set forth in Article I hereof. The Company and BNAC are collectively referred to herein as the “Parties” and individually as a “Party.”

RECITALS:

WHEREAS, the Parties entered into that certain Stockholders’ Agreement, dated as of May 1, 2020, among the Parties and certain other Persons named therein (as amended, the “Original Stockholders’ Agreement”);

WHEREAS, in connection with the initial public offering (the “IPO”) of shares of the Company’s Common Stock, the Company intends to consummate the transactions described in the Registration Statement on Form S-1 (Registration No. 333-[               ]); and

WHEREAS, effective as of the closing of the IPO, (i) the Original Stockholders’ Agreement shall terminate in its entirety in accordance with its terms and shall be of no further force nor effect and (ii) the Parties are entering into this Agreement to set forth certain understandings between such Parties, including with respect to certain governance matters.

NOW, THEREFORE, in consideration of the mutual promises, covenants and agreements set forth herein and for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows:

Article IINTRODUCTORY MATTERS

1.1          Defined Terms. In addition to the terms defined elsewhere herein, the following terms have the following meanings when used herein with initial capital letters:

(a)           “Affiliate” means, with respect to any Person, any Person that, directly or indirectly through one or more intermediaries, Controls, is Controlled by or is under common Control with such Person; provided, however, that for the purposes of this Agreement, the Affiliates of Banpu shall not include the Company and its Subsidiaries.

(b)           “Agreement” means this Stockholders’ Agreement, as the same may be amended, supplemented, restated or otherwise modified from time to time in accordance with the terms hereof.

(c)          “Applicable Percentage” means, at any time, the then-applicable percentage of the voting power of shares of the Company’s capital stock entitled to vote generally in the election of directors that is beneficially owned, directly or indirectly, by Banpu.

(d)           “Auditor” means the independent registered public accounting firm appointed by the Board or the Audit Committee of the Board as auditor of the Company from time to time.

(e)           “Banpu” means BNAC, together with its successors and permitted assigns, but excluding the Company and its Subsidiaries.

(f)            “Banpu Designee” has the meaning set forth in Section 2.1(a) hereof.

(g)           “beneficially own” (including its correlative meanings, “beneficially owned” and “beneficial ownership”) has the meaning set forth in Rule 13d-3 promulgated under the Exchange Act.

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(h)           “BNAC” has the meaning set forth in the Preamble.

(i)            “Board” means the board of directors of the Company.

(j)            “Budget” means the annual budget for the Company and its Subsidiaries as approved and/or amended from time to time by the Board.

(k)           “Business Day” means each Monday, Tuesday, Wednesday, Thursday and Friday that is not a day on which banking institutions in New York, NY are authorized or obligated by law or executive order to close.

(l)            “Business Plan” means the rolling business plan for the Company and its Subsidiaries updated annually in respect of the forthcoming five (5) year period setting out details of their strategic planning in respect of market growth, capital expenditure, financing, tax and contingency planning, and compared against the applicable Budget, as approved and/or amended from time to time by the Board.

(m)          “Bylaws” means the Company’s Amended and Restated Bylaws as in effect on the Effective Date, as the same may be amended or restated from time to time.

(n)           “Certificate of Incorporation” means the Company’s Second Amended and Restated Certificate of Incorporation as in effect on the Effective Date, as the same may be amended or restated from time to time.

(o)           “Common Stock” means the shares of common stock, par value $0.01 per share, of the Company, and any other capital stock of the Company into which such common stock is reclassified or reconstituted.

(p)           “Company” has the meaning set forth in the Preamble.

(q)           “Confidential Information” has the meaning set forth in Section 3.3(a)(i) hereof.

(r)            “Control” (including its correlative meanings, “Controlled by” and “under common Control with”) means the possession, directly or indirectly, of the power to direct or cause the direction of management or policies (whether through ownership of ownership interests, by contract or otherwise) of a Person.

(s)           “Demand Notice” has the meaning set forth in Section 4.1(a)(i) hereof.

(t)            “Director” means any director of the Company.

(u)           “Effective Date” means the date on which the closing of the IPO occurs.

(v)           “Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder, as the same may be amended from time to time.

(w)          “FINRA” means the Financial Industry Regulatory Authority, Inc.

(x)            “GAAP” means generally accepted accounting principles in the United States.

(y)           “Governmental Authority” means any nation or government, any state or other political subdivision thereof, and any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to government.

(z)            “IFRS” means the International Financial Report Standards issued by the IFRS Foundation and the International Accounting Standards in effect at the time to which the related reference to such principles pertains.

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(aa)         “IPO” has the meaning set forth in the Recitals.

(bb)         “Law” means any statute, law, regulation, ordinance, rule, injunction, order, decree, governmental approval, directive, requirement, or other governmental restriction or any similar form of decision of, or determination by, or any interpretation or administration of any of the foregoing by, any Governmental Authority and any rules and regulations of a Recognized Exchange.

(cc)         “Maximum Designee Number” means (i) from the Effective Date until (but not including) the one-year anniversary of the Effective Date: the number equal to (x) the Total Number of Directors less (y) three (3); (ii) from and after the one-year anniversary of the Effective Date until (but not including) the first date on which Banpu beneficially owns, directly or indirectly, 50% or less of the voting power of all shares of the Company’s capital stock entitled to vote generally in the election of directors: the number equal to (x) the Total Number of Directors less (y) four (4); and (iii) from and after the first date on which Banpu beneficially owns, directly or indirectly, 50% or less of the voting power of all shares of the Company’s capital stock entitled to vote generally in the election of directors: the number equal to (x) the Total Number of Directors less (y) the minimum number of Directors that would constitute a majority of the Total Number of Directors.

(dd)         “Original Stockholders’ Agreement” has the meaning set forth in the Recitals.

(ee)         “Party” or “Parties” has the meaning set forth in the Preamble.

(ff)           “Person” means an individual, a partnership, a corporation, a limited liability company, an association, a joint stock company, a trust, a joint venture, a cooperative, an unincorporated organization, or other form of business organization, whether or not regarded as a legal entity under applicable Law, or any Governmental Authority or any department, agency or political subdivision thereof.

(gg)         “Recognized Exchange” means The New York Stock Exchange or the Nasdaq Capital Market.

(hh)         “Registrable Securities” means shares of Common Stock held by Securityholder from time to time. For purposes of this Agreement, Registrable Securities shall cease to be Registrable Securities when (i) a registration statement covering resales of such Registrable Securities has been declared effective under the Securities Act by the SEC and such Registrable Securities have been disposed of pursuant to such effective registration statement, (ii) such Registrable Securities are eligible to be sold by Securityholder owning such Registrable Securities (including Registrable Securities deliverable to Securityholder under an effective Exchange Registration) pursuant to Rule 144 or 145 (or any similar provision then in effect) under the Securities Act, without any restriction or limitation thereunder on volume or manner of sale, or (iii) such Registrable Securities cease to be outstanding shares of Common Stock of the Company.

(ii)           “Registration Expenses” means any and all expenses incurred in connection with the performance of or compliance with Article IV hereof, including:

(i)            all SEC, stock exchange, or FINRA registration and filing fees (including, if applicable, the fees and expenses of any “qualified independent underwriter,” as such term is defined in Rule 5121 of FINRA, and of its counsel);

(ii)           all fees and expenses of complying with securities or blue sky laws (including fees and disbursements of counsel for the underwriters in connection with blue sky qualifications of the Registrable Securities);

(iii)          all printing, messenger and delivery expenses;

(iv)          all fees and expenses incurred in connection with the listing of the Registrable Securities on any securities exchange or FINRA and all rating agency fees;

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(v)           the reasonable fees and disbursements of counsel for the Company and of its independent public accountants, including the expenses of any special audits and/or comfort letters required by or incident to such performance and compliance;

(vi)          any fees and disbursements of underwriters customarily paid by the issuers or sellers of Securities, including liability insurance if the Company so desires or if the underwriters so require, and the reasonable fees and expenses of any special experts retained in connection with the requested registration, but excluding underwriting discounts and commissions and transfer taxes, if any;

(vii)         the reasonable fees and out-of-pocket expenses of not more than one (1) law firm incurred by Securityholder in connection with the registration;

(viii         the costs and expenses of the Company relating to analyst and investor presentations or any “road show” undertaken in connection with the registration and/or marketing of the Registrable Securities (including the reasonable out-of-pocket expenses of Securityholder); and

(ix)           any other fees and disbursements customarily paid by the issuers of Securities.

(jj)           “SEC” means the Securities and Exchange Commission.

(kk)         “Securities” means capital stock, limited partnership interests, limited liability company interests, beneficial interests, warrants, options, notes, bonds, debentures, and other securities, equity interests, ownership interests and similar obligations of every kind and nature of any Person.

(ll)           “Securities Act” means the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder, as the same may be amended from time to time.

(mm)        “Securityholder” means Banpu.

(nn)         “Subsidiary” means, with respect to any Person, any corporation, limited liability company, partnership, association or other business entity of which: (i) if a corporation, a majority of the total voting power of shares of stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, representatives or trustees thereof is at the time owned or Controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person or a combination thereof; or (ii) if a limited liability company, partnership, association or other business entity, a majority of the total voting power of stock (or equivalent ownership interest) of the limited liability company, partnership, association or other business entity is at the time owned or Controlled, directly or indirectly, by that Person or one or more Subsidiaries of that Person or a combination thereof. For purposes hereof, a Person or Persons shall be deemed to have a majority ownership interest in a limited liability company, partnership, association or other business entity if such Person or Persons shall be allocated a majority of limited liability company, partnership, association or other business entity gains or losses or shall be or Control the managing member, managing director or other governing body or general partner of such limited liability company, partnership, association or other business entity.

(oo)         “Total Number of Directors” means the total number of directors comprising the Board, including any vacancies.

(pp)         “WKSI” means a well-known seasoned issuer, as defined in Rule 405 under the Securities Act.

1.2          Construction. The language used in this Agreement will be deemed to be the language chosen by the Parties to express their mutual intent, and no rule of strict construction will be applied against any Party. Unless the context otherwise requires: (a) “or” is disjunctive but not exclusive, (b) words in the singular include the plural, and in the plural include the singular, and (c) the words “hereof,” “herein,” and “hereunder” and words of similar import when used in this Agreement refer to this Agreement as a whole and not to any particular provision of this Agreement, and section references are to this Agreement unless otherwise specified.

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Article IICORPORATE GOVERNANCE MATTERS

2.1          Election of Directors.

(a)            Following the Effective Date, and for so long as Banpu beneficially owns, directly or indirectly, 10% or more of the voting power of all shares of the Company’s capital stock entitled to vote generally in the election of directors, BNAC shall have the right (but not the obligation) pursuant to this Agreement to designate for nomination to the Board a number of individuals (each, a “Banpu Designee”) equal to the number of Directors (all decimal numbers to be rounded up to the nearest whole number) determined by multiplying the Applicable Percentage to the Total Number of Directors; provided, however, that such number of individuals shall not exceed the Maximum Designee Number.

As of the Effective Date, the initial Banpu Designees shall be [               ]. BNAC shall give written notice to the Corporate Governance and Nominating Committee of the Board of each Banpu Designee no later than the date that is sixty (60) days prior to the first anniversary of the date that the Company’s annual proxy for the prior year was first mailed to the Company’s stockholders. For the avoidance of doubt, BNAC shall not have any rights to designate a Director pursuant to this Agreement from and after the first date on which Banpu beneficially owns, directly or indirectly, less than 10% of the voting power of all shares of the Company’s capital stock entitled to vote generally in the election of directors.

(b)            In the event that a vacancy is created or exists at any time by the death, disability, retirement or resignation of any Banpu Designee or as a result of BNAC not yet designating a person to fill such vacancy or Board seat, any individual nominated by or at the direction of the Board or any duly authorized committee thereof to fill such vacancy shall be, and the Company shall use its best efforts to cause such vacancy to be filled, as soon as possible, by a new designee of BNAC, and the Company shall take, to the fullest extent permitted by law, at any time and from time to time, all actions necessary to accomplish the same, including by taking Board action to appoint such Banpu Designee to the Board to fill such vacancy.

(c)            The Company and Banpu shall, to the fullest extent permitted by law, take all actions to cause the Board to include the Chief Executive Officer of the Company.

(d)            The Company shall, to the fullest extent permitted by law, include in the slate of nominees recommended by the Board at any meeting of stockholders called for the purpose of electing directors, the persons designated pursuant to this Section 2.1 and use its best efforts to cause the election of each such designee to the Board, including nominating each such individual to be elected as a Director as provided herein, recommending such individual’s election and soliciting proxies or consents in favor thereof.

(e)            If at any time Banpu’s beneficial ownership is reduced such that it would no longer be entitled pursuant to Section 2.1(a) hereof to designate for nomination to the Board the full number of individuals that constitute the Banpu Designees at such time, then it shall promptly (and in any event within two (2) Business Days) cause such number of Banpu Designees then serving as Directors on the Board to resign from the Board (such resigning Directors to be selected at BNAC’s discretion, and to be replaced by nominees chosen by the remaining Directors in office) as is necessary so that the remaining number of Banpu Designees then serving on the Board is less than or equal to the number of Banpu Designees that BNAC is then entitled to designate for nomination pursuant to Section 2.1(a) hereof.

2.2          Chairman of the Board.

(a)            For so long as Banpu beneficially owns at least 25% of the voting power of shares of the Company’s capital stock entitled to vote generally in the election of directors, BNAC shall have the right (but not the obligation) pursuant to this Agreement to designate the Chairman of the Board from among the Banpu Designees.

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(b)            The individual designated as Chairman of the Board shall serve as such for a three-year term, or until such earlier time as such individual retires or is otherwise replaced by BNAC as Chairman.

(c)            In the event that the Chairman of the Board ceases to hold office as a Director during his or her term as Chairman at a time when BNAC has the right pursuant to Section 2.2(a) hereof to designate the Chairman, BNAC shall have the right (but not the obligation) pursuant to this Agreement to designate a new Chairman of the Board from among the other Banpu Designees. Such new Chairman of the Board shall serve for the remainder of the term of the Chairman who ceased to hold office.

2.3          Amendment of Certificate of Incorporation and Bylaws. Neither the Certificate of Incorporation nor the Bylaws shall be amended in a manner inconsistent with the terms of this Agreement without the consent of BNAC.

2.4          Reimbursement of Expenses. The Company shall cause each Director to be promptly reimbursed for all reasonable and documented out-of-pocket costs and expenses incurred by him or her in connection with (a) attending meetings of the Board or any committee thereof and other meetings and events attended on behalf of the Company and (b) serving as a member of the Board.

2.5          Indemnification. Each Person who was or is made a party or is threatened to be made a party to or is otherwise involved in any action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he or she is or was a Director or an officer of the Company or is or was serving at the request of the Company as a director, officer, or trustee of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to an employee benefit plan, shall be indemnified and held harmless by the Company to the fullest extent permitted by the General Corporation Law of the State of Delaware as it now exists or may hereafter be amended, subject to the terms and conditions set forth in the Bylaws.

Article IIIINFORMATION

3.1          Information.

(a)            For so long as BNAC shall have the right pursuant to this Agreement to nominate to the Board at least one (1) Director, the Company shall prepare, or procure the preparation of, and shall submit to BNAC:

(i)            the financial information set forth in Section 3.2 hereof; and

(ii)           such information as BNAC may reasonably require relating to the business or financial condition of the Company or any of its Subsidiaries within a reasonable period.

(b)            The Company shall not be required to disclose any privileged information of the Company so long as the Company has used commercially reasonable efforts to enter into an arrangement pursuant to which it may provide such information to BNAC without the loss of any such privilege. Further, BNAC may request that the Company not provide any of the information required pursuant to this Section 3.1 or Section 3.2 hereof if such information is reasonably expected to contain any material non-public information (within the meaning of U.S. federal securities laws).

(c)            On or before September 15 of each fiscal year, the Company shall prepare and deliver to the Board a detailed draft of the Budget and Business Plan for the Company and its Subsidiaries (including the financial projection and estimated major items of revenue and capital expenditure) for the following fiscal year, broken down on a monthly basis, and an accompanying cash flow forecast, together with a balance sheet showing the projected position of the Company and its Subsidiaries as at the end of the following fiscal year. The Company shall use reasonable efforts to finalize such Budget and Business Plan for the following fiscal year on before November 15.

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3.2          Certain Reports. For so long as Banpu beneficially owns at least 25% of the voting power of shares of the Company’s capital stock entitled to vote generally in the election of directors, the Company shall deliver or cause to be delivered to BNAC:

(a)            as soon as available, but in any event not later than twenty (20) days after the end of each of month, (i) the unaudited monthly consolidated financial statements of the Company for the month then ended, in each case, prepared in accordance with IFRS, (ii) a report of the Company’s production by basin for such month then ended and (iii) the Company’s safety report for the month then ended;

(b)            as soon as available, but in any event not later than forty-five (45) days after the end of each of the first three (3) quarters of each fiscal year, the unaudited quarterly consolidated financial statements of the Company for the fiscal quarter then ended, in each case, prepared in accordance with GAAP (except that such financial statements may (i) be subject to normal year-end audit adjustments and (ii) not contain all notes thereto that may be required in accordance with GAAP);

(c)            as soon as available, but in any event not later than ninety (90) days after the end of each fiscal year, the audited consolidated financial statements of the Company for the fiscal year then ended, in each case, prepared in accordance with GAAP;

(d)            as soon as available, but in any event not later than (i) forty-five (45) days after the end of each of the first three (3) quarters of each fiscal year and (ii) ninety (90) days after the end of each fiscal year, the consolidated financial statements of the Company, in each case, prepared in accordance with IFRS, together with such other information as BNAC may request that is reasonably required by Banpu in order to prepare and present its consolidated financial statements in accordance with applicable Law and stock exchange requirements.

3.3          Disclosure of Information.

(a)            Subject to Section 3.3(b) hereof, BNAC shall, and shall use all reasonable efforts to ensure that Banpu, its Affiliates and its and their respective representatives shall:

(i)            hold in strict confidence and keep confidential the following (the “Confidential Information”):

(1)            all communications between them and the Company or any of its Subsidiaries;

(2)            all information and other materials that pertain to the Company’s or any of its Subsidiaries’ businesses which is not available to the public, whether written, oral, electronic, visual form or any other media, including, without limitation, such information that is proprietary or confidential or concerning the Company’s or any of its Subsidiaries’ ownership, operations or proposed operations, projects, strategies, business plans, actual or projected financial or operating data, contracts, books and records; and

(3)            any information relating to this Agreement, the customers, business, assets or affairs of the Company and its Subsidiaries and all information concerning the business transactions and/or financial arrangements of the Company and its Subsidiaries that Banpu may have or acquire as a stockholder of the Company or through making appointments to the Board; and

(ii)            (1) not use any Confidential Information for any purpose other than to evaluate and analyze the Company’s and its Subsidiaries’ assets and operations and its interest therein and (2) not disclose any Confidential Information to any Person (other than a Director or officer of the Company) without the consent of the Company.

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(b)            Section 3.3(a) hereof shall not prohibit disclosure or use of any information if and to the extent:

(i)            the information is or becomes publicly available, other than by breach of this Agreement;

(ii)           the Company has given prior written approval to the disclosure or use;

(iii)          the Board has confirmed in writing that such information is not confidential;

(iv)          Banpu is able to demonstrate to the Company that such information was independently developed, sourced or acquired by it or any of its Affiliates after the date of this Agreement without the use of any Confidential Information;

(v)           the disclosure or use is required by Law, any governmental or regulatory body or any securities exchange on which the shares of Banpu or its Affiliates are listed; provided, that Banpu has provided the Company with prior notice and a reasonable opportunity to comment on such disclosure;

(vi)          the disclosure or use is required for the purpose of any judicial or arbitral proceedings arising out of this Agreement or any documents to be entered pursuant to it;

(vii)          the disclosure is reasonably made to a tax authority if and to the extent such disclosure is reasonably required for the purposes of the tax affairs of Banpu or its Affiliates; or

(viii)        the disclosure of information by BNAC to Banpu or its or their respective representatives on a need to know basis and on terms that such Persons undertake to comply with the provisions of this Section 3.3 as if they were a party to this Agreement.

(c)            Upon Banpu ceasing to be a stockholder of the Company, BNAC shall, and shall use all reasonable efforts to ensure that Banpu, its Affiliates and its and their respective representatives shall, promptly:

(i)            return all written Confidential Information provided to it or its Affiliates or its or their respective representatives which is in such Person’s possession or under its custody and control without keeping any copies thereof;

(ii)           destroy all analyses, compilations, notes, studies, memoranda or other documents prepared by it or its Affiliates or its or their respective representatives to the extent that the same contain, reflect or derive from any Confidential Information relating to the Company or any of its Subsidiaries or their business; and

(iii)          so far as it is practicable to do so (but, in any event, subject to continuing compliance with the duties of confidentiality contained in this Agreement), expunge any Confidential Information relating to the Company or any of its Subsidiaries or their business in its possession or under its custody and control from any computer, word processor or other device;

provided that (1) Banpu may retain (A) any Confidential Information relating to the Company or any of its Subsidiaries or their business as may be required by Law or contained or referred to in board minutes or in documents referred to therein and (B) any Confidential Information residing in its automatic data backup systems; and (2) Banpu’s advisers may keep one (1) copy of any documents in their possession for record purposes, in each case subject to continuing compliance with the duties of confidentiality contained in this Agreement, notwithstanding any termination thereof.

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(d)           Subject to the foregoing provisions of this Section 3.3, no public disclosure or announcement of any kind regarding the Company shall be made by Banpu unless Banpu has notified the Company prior to any such disclosure or announcement, in which case Banpu shall take all reasonable steps to obtain the consent of the Company to the contents of such disclosure or announcement (such consent not to be unreasonably withheld or delayed).

(e)            The obligations contained in this Section 3.3 shall last three (3) years after the termination of this Agreement pursuant to Section 5.1 hereof.

Article IVREGISTRATION RIGHTS

4.1          Demand and Piggyback Rights.

(a)            Right to Demand a Non-Shelf Registered Offering.

(i)            Upon the written demand of Securityholder (a “Demand Notice”) made at any time and from time to time following the date that is six (6) months after the consummation of the IPO, the Company will facilitate in the manner described in this Agreement a non-shelf registered offering of the Registrable Securities requested by Securityholder to be included in such offering; provided that the Company shall not be obligated to effect more than two (2) such offerings in any twelve (12) month period.

(ii)            Any demanded non-shelf registered offering may, at the Company’s option, include shares of Common Stock to be sold by the Company for its own account and will also include any other Registrable Securities to be sold by the holders of registration rights granted other than pursuant to this Agreement exercising such rights, to the extent exercising such rights on a timely basis. In order to be valid, the Demand Notice must provide the information described in Section 4.2(a) hereof (if applicable) and Section 4.3(e) hereof or be followed by such information, when requested as contemplated by Section 4.3(e) hereof.

(iii)          Without limiting any other obligations of the Company hereunder, as soon as reasonably practicable, but in no event later than forty-five (45) days after receiving a valid Demand Notice satisfying the criteria set forth in Section 4.1(a) hereof, the Company shall file (or confidentially submit, at the Company’s discretion) with the SEC a registration statement covering all of the Registrable Securities covered by such Demand Notice and any other registrable securities properly requested in accordance with other registration rights agreements with the Company, but subject in each case to any cutbacks imposed in accordance with Section 4.2(f) hereof and the limitations set forth in Section 4.1(e) hereof.

(b)            Right to Piggyback on a Non-Shelf Registered Offering. In connection with any registered offering of shares of Common Stock covered by a non-shelf registration statement (including at the initiative of the Company), Securityholder may exercise piggyback rights to have included in such offering Registrable Securities held by it, subject to any cutbacks imposed in accordance with Section 4.2(f) hereof and the limitations set forth in Section 4.1(e) hereof. The Company will facilitate in the manner described in this Agreement any such non-shelf registered offering.

(c)            Right to Demand and be Included in a Shelf Registration.

(i)            Upon the delivery of a Demand Notice by Securityholder, provided at any time and from time to time when the Company is eligible to utilize Form S-3 or a successor form to sell shares of Common Stock in a secondary offering on a delayed or continuous basis in accordance with Rule 415 under the Securities Act, the Company will facilitate in the manner described in this Agreement a shelf registration of the Registrable Securities held by Securityholder requested by it to be included in such shelf. If, at the time of such request, the Company is eligible for WKSI status, such shelf registration shall, upon the approval of the Board, cover an unspecified number of Registrable Securities to be sold by the Company and Securityholder.

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(ii)            Without limiting any other obligations of the Company hereunder, as soon as reasonably practicable, but in no event later than forty-five (45) days after receiving a valid Demand Notice as set forth in Section 4.1(c)(i) hereof, the Company shall file (or confidentially submit, at the Company’s discretion) with the SEC a shelf registration statement covering all of the Registrable Securities covered by such Demand Notice and any other registrable securities properly requested in accordance with other registration rights agreements with the Company, but subject in each case to any cutbacks imposed in accordance with Section 4.2(f) hereof and the limitations set forth in Section 4.1(e) hereof.

(d)            Demand and Piggyback Rights for Shelf Takedowns.

(i)            Upon the delivery of a Demand Notice by Securityholder, provided at any time and from time to time after a shelf registration statement has been declared effective by the SEC, the Company will facilitate in the manner described in this Agreement a “takedown” of Registrable Securities off of an effective shelf registration statement; provided that the Company shall not be obligated to effect (1) an underwritten shelf takedown unless such offering shall include securities with a total offering price (including piggyback securities and before deduction of underwriting discounts) reasonably expected to exceed, in the aggregate, $5,000,000 and (2) more than two (2) underwritten offerings demanded pursuant to this Section 4.1(d) or Section 4.1(a) hereof in any twelve (12) month period.

(ii)            In connection with any underwritten shelf takedown (including at the initiative of the Company), Securityholder may exercise piggyback rights to have included in such takedown Registrable Securities held by it that are registered on such shelf.

(e)            Limitations on Demand and Piggyback Rights.

(i)            Any demand for the filing of a registration statement or for a registered offering or takedown, and the exercise of any piggyback registration rights, will be subject to the constraints of any applicable contractual lockup arrangements, and any such demand must be deferred until such lockup arrangements no longer apply. If a demand has been made for a non-shelf registered offering or for an underwritten takedown, no further demands may be made so long as the related offering is still being pursued. Notwithstanding anything in this Agreement to the contrary, Securityholder will not have piggyback or other registration rights with respect to the following registered primary offerings by the Company: (1) a registration relating solely to employee benefit plans; (2) a registration on Form S-4 or S-8 (or other similar successor forms then in effect under the Securities Act); (3) a registration pursuant to which the Company is offering to exchange its own Securities for other Securities; (4) a registration statement relating solely to dividend reinvestment or similar plans; (5) a shelf registration statement relating to debt securities of the Company or any Subsidiary that are convertible for common equity of the Company; or (6) a registration where the Registrable Securities are not being sold for cash.

(ii)           The Company may postpone the filing of a demanded registration statement or suspend the effectiveness of any shelf registration statement for a reasonable “blackout period” not in excess of ninety (90) days if (1) the Company has initiated a registered offering of its securities and continues to actively employ, in good faith, all reasonable efforts to cause the applicable registration statement to become effective; (2) Securityholder has requested an underwritten offering and the Company and Securityholder are unable to obtain the commitment of underwriters to firmly underwrite the offer; or (3) the Board determines in good faith that such registration or offering could materially interfere with a bona fide business, acquisition or divestiture or financing transaction of the Company or is reasonably likely to require premature disclosure of information that the Company has a bona fide business purpose for not disclosing publicly; provided that the Company shall not delay the filing of any demanded registration statement more than one (1) time in any twelve (12) month period.

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4.2          Notices, Cutbacks and Other Matters.

(a)            Notifications Regarding Registration Statements. In order for Securityholder to exercise its right to demand that a registration statement be filed, it must include in its Demand Notice the number of Registrable Securities sought to be registered, the complete name of the selling Securityholder and the proposed plan of distribution.

(b)            Notifications Regarding Registration Piggyback Rights.

(i)            In the event that the Company files (or confidentially submits) a registration statement with respect to a non-shelf registered offering, the Company will promptly give to Securityholder a written notice thereof as soon as practicable, but in no event less than seven (7) Business Days before the anticipated filing (or confidential submission) date of such registration statement. If Securityholder wishes to exercise its piggyback rights with respect to any such non-shelf registration statement, it must notify the Company of the number of Registrable Securities it seeks to have included in such registration statement in a written notice given within five (5) Business Days after the date of the Company’s notice.

(ii)            In the event that the Company proposes to conduct an underwritten shelf takedown, the Company will promptly give to Securityholder a written notice thereof as soon as practicable, but in no event less than five (5) Business Days before the expected date of commencement of marketing efforts for such underwritten shelf takedown. If Securityholder wishes to exercise its piggyback rights with respect to any such underwritten shelf takedown, it must notify the Company of the number of Registrable Securities it seeks to have included in such takedown in a written notice given within two (2) Business Days after the date of the Company’s notice.

(iii)          Pending any required public disclosure and subject to applicable legal requirements, the Parties will maintain appropriate confidentiality of their discussions regarding a prospective registration and/or offering.

(c)            Notifications Regarding Demanded Underwritten Takedowns.

(i)            At any time and from time to time after a shelf registration statement has been declared effective by the SEC, if Securityholder wishes to exercise its demand with respect to any “takedown” of Registrable Securities off of such effective shelf registration statement, it must notify the Company of the number of Registrable Securities it seeks to have included in such registration statement in a written notice and the expected price range of such offering no later than 5:00 p.m., New York City time, on the second (2nd) Business Day prior to any public announcement of such anticipated takedown.

(ii)            Pending any required public disclosure and subject to applicable legal requirements, the Parties will maintain appropriate confidentiality of their discussions regarding a prospective takedown.

(d)           Requirements for Participation in Underwritten Offerings.

(i)            If Securityholder proposes to distribute its Registrable Securities through an underwritten offering, it shall enter into an underwriting agreement in customary form with the underwriters selected for such underwritten offering and the Company.

(ii)           Subject to Section 4.2(e) hereof, Securityholder may not participate in any underwritten offering for equity securities of the Company pursuant to a registration initiated by the Company hereunder unless it (1) agrees to sell its securities on the basis provided in any underwriting arrangements approved by the Company and (2) completes and executes all customary questionnaires, powers of attorney, indemnities, lock-up agreements, underwriting agreements and other customary documents as may be reasonably required under the terms of such underwriting arrangements.

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(e)            Plan of Distribution, Underwriters, Advisors and Counsel. If a majority of the Registrable Securities proposed to be sold in an underwritten offering through a non-shelf registration statement or through a shelf takedown is being sold by the Company for its own account, the Company will be entitled to determine the plan of distribution and select the managing underwriters and any provider of advisory services for such offering. Otherwise, if Securityholder holds a majority of the shares of Common Stock requested to be included, it will be entitled to determine the plan of distribution and select the managing underwriters, provided that such investment banker or bankers and managers shall be reasonably satisfactory to the Company.

(f)            Cutbacks. If the managing underwriters advise the Company and the selling Securityholder that, in their opinion, the number of Registrable Securities requested to be included in an underwritten offering exceeds the amount that can be sold in such offering without adversely affecting the distribution of the Registrable Securities being offered, the price that will be paid in such offering or the marketability thereof, such offering will include only the number of Registrable Securities that the underwriters advise can be sold in such offering. If the Company is selling Registrable Securities for its own account in such offering and the offering is not being made on account of a demand made by Securityholder pursuant to Section 4.1(a) hereof, the securities to be offered by the Company will have first priority. To the extent of any remaining capacity, and in all other cases, the selling Securityholder (and any other Persons having registration rights pari passu with Securityholder and participating in such offering) and the Company will be subject to cutback pro rata based on the number of Registrable Securities initially requested by them to be included in such offering, without distinguishing between Securityholder or other Persons exercising pari passu registration rights based on who made the demand for such offering or otherwise.

(g)           Withdrawals. Even if Registrable Securities held by Securityholder have been part of a registered underwritten offering, Securityholder may, no later than the time at which the public offering price and underwriters’ discount are determined with the managing underwriter, decline to sell all or any portion of the Registrable Securities being offered for its account. For the avoidance of doubt, a commenced offering under which a withdrawal has been made in accordance with this Section 4.2(g) shall not count against the maximum number of demanded offerings that Securityholder may make in any twelve (12) month period.

4.3          Facilitating Registrations and Offerings.

(a)            General. If the Company becomes obligated under this Agreement to facilitate a registration and offering of Registrable Securities on behalf of Securityholder, the Company will do so with the same degree of care and dispatch as would reasonably be expected in the case of a registration and offering by the Company of Registrable Securities for its own account. Without limiting this general obligation, the Company will fulfill its specific obligations as described in this Section 4.3.

(b)            Registration Statements. In connection with each registration statement that is demanded by Securityholder in accordance with this Agreement or as to which piggyback rights otherwise apply, the Company will:

(i)            (1) prepare and file with the SEC a registration statement on an appropriate form covering the applicable Registrable Securities, (2) file amendments thereto as warranted, (3) seek the effectiveness thereof as promptly as reasonably practicable and (4) file with the SEC prospectuses, prospectus supplements and free writing prospectuses as may be required, all in consultation with Securityholder and as reasonably necessary in order to permit the offer and sale of such Registrable Securities in accordance with the applicable plan of distribution;

(ii)            within a reasonable time prior to the filing of any registration statement, any prospectus, any amendment to a registration statement, amendment or supplement to a prospectus or any free writing prospectus (in each case including all exhibits filed therewith), provide copies of such documents to the selling Securityholder and to the underwriter or underwriters of an underwritten offering, if applicable, and to their respective counsel; fairly consider such reasonable changes in any such documents prior to or after the filing thereof as the counsel to Securityholder or the underwriter or the underwriters may request; and make such of the representatives of the Company as shall be reasonably requested by the selling Securityholder or any underwriter available for discussion of such documents;

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(iii)          use all reasonable efforts to cause each registration statement and the related prospectus and any amendment or supplement thereto, as of the effective date of such registration statement, amendment or supplement and during the distribution of the registered Registrable Securities (1) to comply in all material respects with the requirements of the Securities Act (including the rules and regulations promulgated thereunder) and (2) not to contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading; and

(iv)          notify Securityholder promptly (1) when a registration statement has become effective and when any post-effective amendments and supplements thereto become effective if such registration statement or post-effective amendment is not automatically effective upon filing pursuant to Rule 462 under the Securities Act, (2) of the issuance by the SEC or any state securities authority of any stop order, injunction or other order or requirement suspending the effectiveness of a registration statement or the initiation of any proceedings for that purpose, (3) if, between the effective date of a registration statement and the closing of any sale of securities covered thereby pursuant to any agreement to which the Company is a party, the representations and warranties of the Company contained in such agreement cease to be true and correct in all material respects or if the Company receives any notification with respect to the suspension of the qualification of the Registrable Securities for sale in any jurisdiction or the initiation of any proceeding for such purpose, and (4) of the happening of any event during the period a registration statement is effective as a result of which such registration statement or the related prospectus contains any untrue statement of a material fact or omits to state any material fact required to be stated therein or necessary to make the statements therein not misleading.

(c)            Non-Shelf Registered Offerings and Shelf Takedowns. In connection with any non-shelf registered offering or shelf takedown that is demanded by Securityholder or as to which piggyback rights otherwise apply, the Company will:

(i)            cooperate with the selling Securityholder and the sole underwriter or managing underwriter of an underwritten offering, if any, to facilitate the timely preparation and delivery of certificates representing the Registrable Securities to be sold and not bearing any restrictive legends; and enable such Registrable Securities to be in such denominations (consistent with the provisions of the governing documents thereof) and registered in such names as the selling Securityholder or the sole underwriter or managing underwriter of an underwritten offering of Registrable Securities, if any, may reasonably request at least five (5) days prior to any sale of such Registrable Securities;

(ii)           furnish to Securityholder and to each underwriter, if any, participating in the relevant offering, without charge, as many copies of the applicable prospectus, including each preliminary prospectus, and any amendment or supplement thereto and such other documents as Securityholder or such underwriter may reasonably request in order to facilitate the public sale or other disposition of the Registrable Securities; and the Company hereby consents to the use of the prospectus, including each preliminary prospectus, by Securityholder and such underwriter in connection with the offering and sale of the Registrable Securities covered by the prospectus or the preliminary prospectus;

(iii)          (1) use all reasonable efforts to register or qualify the Registrable Securities being offered and sold, no later than the time the applicable registration statement becomes effective, under all applicable state securities or blue sky laws of such jurisdictions as each underwriter, if any, or Securityholder holding Registrable Securities covered by a registration statement, shall reasonably request; (2) use all reasonable efforts to keep each such registration or qualification effective during the period such registration statement is required to be kept effective; and (3) do any and all other acts and things which may be reasonably necessary or advisable to enable each such underwriter, if any, and Securityholder to consummate the disposition in each such jurisdiction of such Registrable Securities owned by Securityholder; provided, however, that the Company shall not be obligated to qualify as a foreign corporation or as a dealer in securities in any jurisdiction in which it is not so qualified or to consent to be subject to general service of process (other than service of process in connection with such registration or qualification or any sale of Registrable Securities in connection therewith) in any such jurisdiction;

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(iv)          cause all Registrable Securities being sold to be qualified for inclusion in or listed on any Recognized Exchange on which Registrable Securities issued by the Company are then so qualified or listed if so requested by Securityholder, or if so requested by the underwriter or underwriters of an underwritten offering of Registrable Securities, if any;

(v)           cooperate and assist in any filings required to be made with FINRA and in the performance of any due diligence investigation by any underwriter in an underwritten offering;

(vi)          use all reasonable efforts to facilitate the distribution and sale of any Registrable Securities to be offered pursuant to this Agreement, including without limitation by making “road show” presentations, holding meetings with and making calls to potential investors and taking such other actions as shall be requested by Securityholder or the lead managing underwriter of an underwritten offering; and

(vii)         enter into customary agreements (including, in the case of an underwritten offering, underwriting agreements in customary form, and including provisions with respect to indemnification and contribution in customary form and consistent with the provisions relating to indemnification and contribution contained herein) and take all other customary and appropriate actions in order to expedite or facilitate the disposition of such Registrable Securities and in connection therewith:

(1)            make such representations and warranties to the selling Securityholder and the underwriters, if any, in form, substance and scope as are customarily made by issuers to underwriters in similar underwritten offerings;

(2)            obtain opinions of counsel to the Company and updates thereof (which counsel and opinions (in form, scope and substance) shall be reasonably satisfactory to the lead managing underwriter, if any) addressed to the selling Securityholder and the underwriters, if any, covering the matters customarily covered in opinions requested in sales of securities or underwritten offerings and such other matters as may be reasonably requested by Securityholder and such underwriters;

(3)            obtain “comfort” letters and updates thereof from the Company’s independent certified public accountants and independent petroleum reserve engineers addressed to the selling Securityholder, if permissible, and the underwriters, if any, which letters shall be customary in form and shall cover matters of the type customarily covered in “comfort” letters to underwriters in connection with primary underwritten offerings; and

(4)            to the extent requested and customary for the relevant transaction, enter into a Securities sales agreement with Securityholder providing for, among other things, the appointment of such representative as agent for the selling Securityholder for the purpose of soliciting purchases of Registrable Securities, which agreement shall be customary in form, substance and scope and shall contain customary representations, warranties and covenants.

The above shall be done at such times as customarily occur in similar registered offerings or shelf takedowns.

(d)            Due Diligence. In connection with each registration and offering of Registrable Securities to be sold by Securityholder, the Company will, in accordance with customary practice, make available for inspection by underwriters and any counsel or accountant retained by such underwriters all relevant financial and other records, pertinent corporate documents and properties of the Company and cause appropriate officers, managers, employees, outside counsel and accountants of the Company to supply all information reasonably requested by any such underwriter, counsel or accountant in connection with their due diligence exercise, including through in-person meetings, but subject to customary privilege constraints.

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(e)            Information from Securityholder. In connection with any registration or offering of Registrable Securities in which Securityholder is participating, Securityholder will furnish to the Company in writing such information regarding itself as is required to be included in, or is otherwise required by FINRA or the SEC in connection with, any registration statement, any prospectus or any amendment or supplement thereto, the ownership of Registrable Securities by Securityholder and the proposed distribution by Securityholder of such Registrable Securities, as well as any such additional information as the Company may from time to time reasonably request in writing in connection therewith.

(f)            Expenses. All Registration Expenses incurred in connection with any registration statement or registered offering covering Registrable Securities held by Securityholder will be borne by the Company. However, (i) underwriters’, brokers’ and dealers’ discounts and commissions applicable to Registrable Securities sold for the account of Securityholder and (ii) other than as set forth in the definition of “Registration Expenses,” all reasonable fees and expenses of any legal counsel representing Securityholder will be borne by Securityholder.

4.4          Reporting Obligations. As long as Securityholder shall own Registrable Securities, the Company, at all times while it shall be a reporting company under the Exchange Act, covenants to file timely (or obtain extensions in respect thereof and file within the applicable grace period) all reports required to be filed by the Company after the Effective Date pursuant to Sections 13(a) or 15(d) of the Exchange Act. The Company further covenants that it shall take such further action as Securityholder may reasonably request, all to the extent required from time to time to enable Securityholder to sell shares of Common Stock held by it without registration under the Securities Act within the limitation of the exemptions provided by Rule 144 promulgated under the Securities Act (or any successor rule promulgated thereafter by the SEC), including providing any legal opinions that may be required by the Company’s transfer agent or otherwise related to the transfer of Registrable Securities.

4.5          Indemnification.

(a)            Indemnification by the Company. In the event of any registration under the Securities Act by any registration statement pursuant to rights granted in this Agreement of Registrable Securities held by Securityholder, the Company will indemnify and hold harmless Securityholder, its officers, directors, and each underwriter of such securities and each other Person, if any, who Controls Securityholder or such underwriter, against any losses, claims, damages or liabilities (including legal fees and costs of court), joint or several, to which such Person may become subject under the Securities Act or otherwise, to the extent arising out of or are based upon any untrue statement or alleged untrue statement of any material fact contained, on its effective date, in any registration statement under which such securities were registered under the Securities Act, any preliminary prospectus, if used prior to the effective date of such registration statement, or in the final prospectus or in any amendment or supplement to any of the foregoing, or in any document incorporated by reference therein, or any issuer free writing prospectus (including any “road show,” whether or not required to be filed with the SEC), or which arise out of or are based upon the omission or alleged omission to state a material fact required to be stated therein or necessary to make the statements therein not misleading; provided, however, that the Company shall not be liable to Securityholder or its underwriters or controlling Persons in any such case to the extent that any such loss, claim, damage or liability arises out of or is based upon an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Company by Securityholder or such underwriter specifically for use in the preparation thereof.

(b)            Indemnification by Securityholder. Securityholder, as a condition to including Registrable Securities in such registration statement, will indemnify and hold harmless (in the same manner and to the same extent as set forth in Section 4.5(a) hereof) the Company, each director and officer of the Company and each underwriter of such securities and each other Person, if any, who Controls the Company or such underwriter (i) with respect to any statement or omission from such registration statement, or any amendment or supplement to it, if such statement or omission was made in reliance upon and in conformity with information furnished to the Company through a written instrument duly executed by Securityholder specifically regarding Securityholder for use in the preparation of such registration statement or amendment or supplement, or (ii) with respect to compliance by Securityholder with applicable Laws in effecting the sale or other disposition of the securities covered by such registration statement; provided, that the liability of Securityholder pursuant to this Section 4.5(b) shall not exceed the total price at which the securities were offered to the public by Securityholder.

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(c)            Indemnification Procedures. Promptly after receipt by an indemnified party of notice of the commencement of any action involving a claim referred to in Section 4.5(a) and Section 4.5(b) hereof, the indemnified party will, if a claim in respect thereof is to be made or may be made against an indemnifying party, give written notice to such indemnifying party of the commencement of the action. The failure of any indemnified party to give notice shall not relieve the indemnifying party of its obligations in this Section 4.5, except to the extent that the indemnifying party is actually prejudiced by the failure to give notice. If any such action is brought against an indemnified party, the indemnifying party will be entitled to participate in and to assume the defense of the action with counsel reasonably satisfactory to the indemnified party, and after notice from the indemnifying party to such indemnified party of its election to assume defense of the action, the indemnifying party will not be liable to such indemnified party for any legal or other expenses incurred by the latter in connection with the action’s defense other than reasonable costs of investigation. The indemnifying party shall, in connection with any one such action or separate but substantially similar or related actions arising out of the same general allegations or circumstances, pay for the reasonable fees and expenses of one (but not more than one) separate firm of attorneys for the indemnified party (in addition to all local counsel which is necessary, in the good faith opinion of both counsel for the indemnifying party and counsel for the indemnified party in order to adequately represent the indemnified parties), in addition to counsel for the indemnifying party. Whether or not a defense is assumed by the indemnifying party, the indemnifying party will not be subject to any liability for any settlement made without its consent (not to be unreasonably withheld). No indemnifying party will consent to entry of any judgment or enter into any settlement which (1) does not include as an unconditional term the giving by the claimant or plaintiff, to the indemnified party, of a release from all liability in respect of such claim or litigation or (2) involves the imposition of equitable remedies or the imposition of any non-financial obligations on the indemnified party.

(d)            Contribution. If the indemnification required by this Section 4.5 from the indemnifying party is unavailable to or insufficient to hold harmless an indemnified party in respect of any indemnifiable losses, claims, damages, liabilities, or expenses, then the indemnifying party shall contribute to the amount paid or payable by the indemnified party as a result of such losses, claims, damages, liabilities, or expenses in such proportion as is appropriate to reflect (i) the relative benefit of the indemnifying and indemnified parties and (ii) if the allocation in clause (i) is not permitted by applicable Law, in such proportion as is appropriate to reflect the relative benefit referred to in clause (i) and also the relative fault of the indemnified and indemnifying parties, in connection with the actions which resulted in such losses, claims, damages, liabilities, or expenses, as well as any other relevant equitable considerations. The relative benefits received by a party shall be deemed to be in the same proportion as the total net proceeds from the offering (before deducting expenses) received by it bear to the total amounts (including, in the case of any underwriter, any underwriting commissions and discounts) received by each other party. The relative fault of the indemnifying party and the indemnified party shall be determined by reference to, among other things, whether any action in question, including any untrue or alleged untrue statement of a material fact or any omission or alleged omission to state a material fact, has been made by, or relates to information supplied by, such indemnifying party or parties, and the parties’ relative intent, knowledge, access to information, and opportunity to correct or prevent such action. The amount paid or payable by a party as a result of the losses, claims, damage, liabilities, and expenses referred to above shall be deemed to include any legal or other fees or expenses reasonably incurred by such party in connection with any investigation or proceeding. The Company and Securityholder agree that it would not be just and equitable if contribution pursuant to this Section 4.5(d) were determined by pro rata allocation or by any other method of allocation which does not take account of the equitable considerations referred to in the prior provisions of this Section 4.5(d).

Notwithstanding the provisions of this Section 4.5(d), no indemnifying party shall be required to contribute any amount in excess of the amount by which the total price at which the securities were offered to the public by such indemnifying party exceeds the amount of any damages which such indemnifying party has otherwise been required to pay by reason of an untrue statement or omission. No Person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution from any Person who was not guilty of such a fraudulent misrepresentation.

Article VGENERAL PROVISIONS

5.1          Termination. This Agreement shall terminate on the earlier to occur of (a) such time as BNAC is no longer entitled to designate a Director pursuant to Section 2.1(a) hereof (provided, however, that the provisions of Article IV hereof shall survive and continue in full force and effect until Securityholder no longer holds any Registrable Securities and in any case Section 4.5 shall survive and continue in full force and effect until the expiration of the applicable statute of limitations in respect of such matter); and (b) the delivery of a written notice by BNAC to the Company requesting that this Agreement terminate.

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5.2          Notices. Any notice, designation, request, consent, demand and other communications required or permitted under this Agreement shall be in writing and shall be personally delivered, sent by facsimile or electronic transmission, or sent by reputable overnight courier service (charges prepaid) to the Parties at the respective addresses set forth below and to any other recipient at the address indicated on the Company’s records, or at such address or to the attention of such other Person as the recipient Party has specified by prior written notice to the sending Party. Any such notice, designation, request, consent, demand, other communication and other documents shall be deemed to have been given or made hereunder on the date of delivery, if delivered personally or by facsimile or electronic transmission, and one (1) Business Day after the date of deposit with a reputable overnight courier service, if delivered by reputable overnight courier service.

(a)            If to the Company, to:

BKV Corporation

1200 17th Street, Suite 2100

Denver, Colorado 80202

Attention: Lindsay Larrick, Vice President and General Counsel

Facsimile: [***]

E-mail: [***]

with a copy (not constituting notice) to:

Baker Botts L.L.P.

2001 Ross Avenue, Suite 900

Dallas, Texas 75201

Attention: Samantha Crispin

Facsimile: [***]

E-mail: [***]

(b)            If to BNAC or Banpu, to:

Banpu North America Corporation

[               ]

[               ]

Attention: [               ]

Facsimile: [***]

E-mail: [***]

with a copy (not constituting notice) to:

[               ]

[               ]

[               ]

Attention: [               ]

E-mail: [***]

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5.3          Amendment; Waiver. This Agreement may be amended, supplemented or otherwise modified only by a written instrument executed by the Parties. Neither the failure nor delay on the part of any Party to exercise any right, remedy, power or privilege under this Agreement shall operate as a waiver thereof, nor shall any single or partial exercise of any right, remedy, power or privilege preclude any other or further exercise of the same or of any other right, remedy, power or privilege, nor shall any waiver of any right, remedy, power or privilege with respect to any occurrence be construed as a waiver of such right, remedy, power or privilege with respect to any other occurrence. No waiver shall be effective unless it is in writing and is signed by the Party asserted to have granted such waiver.

5.4          Further Assurances. The Parties will sign such further documents, cause such meetings to be held, resolutions passed, exercise their votes and do and perform and cause to be done such further acts and things necessary, proper or advisable in order to give full effect to this Agreement and every provision hereof. To the fullest extent permitted by law, the Company shall not directly or indirectly take any action that is intended to, or would reasonably be expected to result in, Banpu being deprived of the rights contemplated by this Agreement.

5.5          Assignment. This Agreement will inure to the benefit of and be binding on the Parties and their respective successors and permitted assigns. This Agreement may not be assigned by a Party without the express prior written consent of the other Party, and any attempted assignment, without such consent, will be null and void; provided, however, that BNAC may assign this Agreement to Banpu Public Company Limited or any wholly owned subsidiary of Banpu Public Company Limited by giving prior written notice to, but without the express prior written consent of, the other Party.

5.6          Third Parties. This Agreement does not create any rights, claims or benefits inuring to any person that is not a Party nor create or establish any third-party beneficiary hereto.

5.7          Governing Law. This Agreement and all claims or disputes arising out of this Agreement shall be governed by and construed in accordance with the laws of the State of Delaware, without regard to principles of conflicts of laws thereof.

5.8          Jurisdiction; Waiver of Jury Trial. In any judicial proceeding involving any dispute, controversy or claim arising out of or relating to this Agreement, each of the Parties unconditionally accepts the jurisdiction and venue of the courts of the State of Delaware or if jurisdiction over the matter is vested exclusively in federal courts, the United States District Court for the District of Delaware, and the appellate courts to which orders and judgments thereof may be appealed. In any such judicial proceeding, the Parties agree that in addition to any method for the service of process permitted or required by such courts, to the fullest extent permitted by law, service of process may be made by delivery provided pursuant to the directions in Section 5.2 hereof. EACH OF THE PARTIES HEREBY WAIVES TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW TRIAL BY JURY IN ANY JUDICIAL PROCEEDING INVOLVING ANY DISPUTE, CONTROVERSY OR CLAIM ARISING OUT OF OR RELATING TO THIS AGREEMENT.

5.9          Specific Performance. Each Party acknowledges and agrees that in the event of any breach of this Agreement by any of them, the other Party would be irreparably harmed and could not be made whole by monetary damages. Each Party accordingly agrees to waive the defense in any action for specific performance that a remedy at law would be adequate and agrees that the Parties, in addition to any other remedy to which they may be entitled at law or in equity, shall be entitled to specific performance of this Agreement without the posting of bond.

5.10       Entire Agreement. This Agreement sets forth the entire understanding of the Parties with respect to the subject matter hereof. There are no agreements, representations, warranties, covenants or understandings with respect to the subject matter hereof or thereof other than those expressly set forth herein and therein. This Agreement supersedes all other prior agreements and understandings between the Parties with respect to such subject matter.

5.11       Severability. If any provision of this Agreement, or the application of such provision to any Person or circumstance or in any jurisdiction, shall be held to be invalid or unenforceable to any extent, (a) the remainder of this Agreement shall not be affected thereby, and each other provision hereof shall be valid and enforceable to the fullest extent permitted by law, (b) as to such Person or circumstance or in such jurisdiction such provision shall be reformed to be valid and enforceable to the fullest extent permitted by law, and (c) the application of such provision to other Persons or circumstances or in other jurisdictions shall not be affected thereby.

5.12        Table of Contents, Headings and Captions. The table of contents, headings, subheadings and captions contained in this Agreement are included for convenience of reference only, and in no way define, limit or describe the scope of this Agreement or the intent of any provision hereof.

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5.13       Counterparts. This Agreement and any amendment hereto may be signed in any number of separate counterparts, each of which shall be deemed an original, but all of which taken together shall constitute one Agreement (or amendment, as applicable).

5.14        Effectiveness. This Agreement shall become effective upon the Effective Date.

5.15        No Recourse. This Agreement may only be enforced against, and any claims or cause of action that may be based upon, arise out of or relate to this Agreement, or the negotiation, execution or performance of this Agreement may only be made against the entities that are expressly identified as Parties and no past, present or future Affiliate, director, officer, employee, incorporator, member, manager, partner, stockholder, agent, attorney or representative of any Party shall have any liability for any obligations or liabilities of the Parties or for any claim based on, in respect of, or by reason of, the transactions contemplated hereby.

[Remainder of Page Intentionally Left Blank]

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IN WITNESS WHEREOF, the Parties have executed this Agreement on the day and year first above written.

COMPANY:

BKV CORPORATION

By:

Name:

Title:

Signature Page to Stockholders’ Agreement

BANPU NORTH AMERICA CORPORATION

By:

Name:

Title:

Signature Page to Stockholders’ Agreement

EX-10.6

Exhibit 10.6

 

FORM OF AMENDED AND RESTATED TAX SHARING AGREEMENT

 

AMENDED AND RESTATED TAX SHARING AGREEMENT (this “Agreement”), made as of [               ], 2022, by and between (i) Banpu North America Corporation, a Delaware corporation (“BNAC”), and (ii) BKV Corporation, a Delaware corporation (“Banpu Sub”).

 

WHEREAS, BNAC is the common parent of an affiliated group (within the meaning of Section 1504 of the Internal Revenue Code of 1986, as amended (the “Code”)) of corporations (collectively, the “Banpu Group”) of which Banpu Sub is a member, and files a consolidated U.S. federal income tax return on the basis of a taxable year ending on December 31 on behalf of itself and members of the Banpu Group (“Consolidated Return”).

 

WHEREAS, BNAC and Banpu Sub entered into that certain Tax Sharing Agreement, dated May 1, 2020 (the “Initial Tax Sharing Agreement”), to provide for payment by Banpu Sub to BNAC of the amounts payable by Banpu Sub in respect of U.S. federal income taxes and of certain state and local taxes, and for certain payments by BNAC to Banpu Sub, all as provided therein.

 

WHEREAS, BNAC and Banpu Sub desire to amend and restate the Initial Tax Sharing Agreement in its entirety, in accordance with the terms and conditions of this Agreement.

 

Accordingly, BNAC and Banpu Sub agree as follows:

 

1.             Agreement to Join in and Preparation and Filing of Consolidated and Combined Returns.

 

1.1.          Banpu Sub agrees to join with BNAC in any Consolidated Return for any taxable year for which BNAC properly elects to file a Consolidated Return that includes Banpu Sub. Banpu Sub also agrees, at the request of BNAC, to join BNAC or any direct or indirect subsidiary of BNAC in any state or local income or franchise tax return filed on a consolidated, combined, or unitary basis (a “Combined Return”) for any taxable year for which BNAC properly elects to file a Combined Return that includes Banpu Sub.

 

1.2.          Banpu Sub hereby irrevocably designates BNAC as its agent for the purpose of taking any and all actions necessary or incidental to the filing of each Consolidated Return and each Combined Return.

 

1.3.          BNAC shall be responsible for the preparation and filing of the Consolidated Returns and Combined Returns required to be filed by the Banpu Group, subject to the following:

 

1.3.1. Subject to Section 1.3.2 and 1.3.3 below, decisions regarding (1) the manner in which such Consolidated Returns and Combined Returns are prepared and filed, including the methods, conventions, practices, principles, positions, and elections to be used and the manner in which any items of income, gain, loss, deduction, or credit (“Tax Items”) shall be reported, (2) whether any extensions may be requested, (3) whether amended Consolidated Returns or Combined Returns shall be filed, (4) whether any claims for refund shall be made, (5) whether any tax overpayments shall be paid by way of refund or credited against any liability for the related tax and (6) the retention of outside firms to prepare or review such Consolidated Returns or Combined Returns, in each case, shall be made at BNAC’s reasonable discretion and in a manner consistent with past practice.

 

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1.3.2. The Tax Items included with respect to Banpu Sub and its subsidiaries (including any entity that is disregarded as separate from Banpu Sub or its corporate subsidiaries for U.S. federal income tax purposes or for purposes of any state or local tax law) (the “Company Group”) in the Consolidated Returns and Combined Returns shall be consistent in all respects with the tax reporting information provided by Banpu Sub to BNAC pursuant to Section 2.1.

 

1.3.3. BNAC shall consult with Banpu Sub prior to changing any method of accounting or making any material election if such action would solely impact the Company Group.

 

1.3.4. BNAC shall provide Banpu Sub a copy of any Consolidated Return or Combined Return described under this Section 1.3 within ten (10) business days after filing such return.

 

1.4.          Banpu Sub shall be responsible for the preparation and filing of any (i) U.S. state or local income or franchise tax return, other than a Combined Return, which is required to be filed by or with respect to Banpu Sub or any other member of the Company Group and (ii) U.S. federal income tax return of Banpu Sub or any other member of the Company Group for any tax period beginning on or after the date that Banpu Sub ceases to be a member of the Banpu Group (each, a “Banpu Sub-Filed Return”), subject to the following provisions:

 

1.4.1. Banpu Sub shall have the exclusive right, in its sole discretion, with respect to any Banpu Sub-Filed Return to determine (1) the manner in which such Banpu Sub-Filed Return shall be prepared and filed, including the methods, conventions, practices, principles, positions, and elections to be used and the manner in which any Tax Item shall be reported, (2) whether any extensions may be requested, (3) whether an amended Banpu Sub-Filed Return shall be filed, (4) whether any claims for refund shall be made, (5) whether any tax overpayments shall be paid by way of refund or credited against any liability for the related tax and (6) the retention of outside firms to prepare or review such Banpu Sub-Filed Returns.

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1.4.2. With respect to any Banpu Sub-Filed Return, Banpu Sub may not take (and shall cause the other members of the Company Group not to take) any positions that it knows, or reasonably should know, are inconsistent with the methods, conventions, practices, principles, positions, or elections used by BNAC in preparing any Consolidated Return or Combined Return, except to the extent that (A) the failure to take such position would be contrary to applicable tax law or (B) taking such position would not reasonably be expected to materially adversely affect any member of the Banpu Group.

 

1.4.3. Banpu Sub shall provide BNAC a copy of any Banpu Sub-Filed Return within ten (10) business days after filing such return; provided however, that this Section 1.4.3 shall cease to apply on and after the time that BNAC ceases to own at least 25% of the voting power of shares of Banpu Sub’s capital stock entitled to vote generally in the election of directors.

 

2.             Determination and Payment of Tax Liability of the Company Group.

 

2.1.          Preparation and Provision of Tax Reporting Information and Separate Return Tax Liability Calculations. Not less than twenty (20) business days prior to the due date (including extensions) for the filing of any Consolidated Return or Combined Return that includes Banpu Sub or any other members of the Company Group, Banpu Sub shall provide to BNAC (1) a pro forma draft of the portion of such Consolidated Return or Combined Return that reflects the Tax Items of the Company Group for the entire taxable year, (2) a spreadsheet or statement that sets forth in reasonable detail the computation of the Separate Return Tax Liability (as defined below) of the Company Group in respect of such Consolidated Return or Combined Return for the entire taxable year, (3) the amount payable by Banpu Sub or BNAC pursuant to Section 2.3 or Section 4, as determined in accordance with this Agreement and (4) such other reasonable information as is requested by BNAC. Not less than ten (10) business days prior to each estimated tax installment due date prescribed in Section 6655(c) of the Code (an “Estimated Tax Installment Date”), Banpu Sub shall provide to BNAC a tax reporting package which includes the items described above for the period covered by such estimated tax installment (the “Estimated Tax Installment Period”). If BNAC disagrees with any Tax Item of the Company Group reflected on the pro forma draft of any Combined Return or Consolidated Return described in clause (1) above or the computations in clauses (2) or (3) above, then BNAC shall promptly notify Banpu Sub and the parties shall use their reasonable best efforts to resolve the dispute and, to the extent the parties are unable to resolve such dispute, the provisions of Section 7 shall apply.

 

2.2.          Separate Return Tax Liability. For purposes of this Agreement, the “Separate Return Tax Liability” for a taxable year shall mean an amount equal to the U.S. federal income tax liability or state or local income or franchise tax liability, as the case may be, that would have been payable by the Company Group for such taxable year if the Company Group had filed a separate U.S. federal income tax return or state or local income or franchise tax return, as the case may be, for such taxable year and all prior taxable years (i.e., on a cumulative basis) for which this Agreement is or was in effect, subject to and except as set forth in the following provisions:

 

2.2.1. The Separate Return Tax Liability of the Company Group shall be computed by Banpu Sub using such methods, conventions, practices, principles, positions, and elections as are consistent with the methods, conventions, practices, principles, positions and elections that are used by BNAC in preparing the applicable Consolidated Return or Combined Return.

 

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2.2.2. Any item of income or loss of a member of the Banpu Group that is treated as deferred on the Consolidated Return filed by BNAC (e.g., gain or loss on an intercompany transaction between members of the Banpu Group that is deferred pursuant to Section 1.1502-13 or 1.1502-13T of the Treasury regulations) shall be taken into account in computing taxable income of the Banpu Group for purposes of this Agreement, but only at such time and in such amount as such item is actually taken into account and recognized on the Consolidated Return filed by BNAC.

 

2.2.3. The Separate Return Tax Liability with respect to a Combined Return filed in a state or locality shall be computed by taking into account such Tax Items, and such receipts or other data used to compute apportionment factors, of each Company Group member as are taken into account with respect to such Company Group member in preparing such Combined Return. Notwithstanding the foregoing, if no Company Group member has nexus to a particular state or locality for which a Combined Return is filed, then the Separate Return Tax Liability of the Company Group for such state or locality shall be deemed to be zero.

 

2.2.4. The computation of the Separate Return Tax Liability of the Company Group shall be determined without regard to whether the Banpu Group is obligated to pay a tax liability for the applicable taxable period.

 

2.2.5. Tax Items of the Company Group that are not utilized during the particular taxable period in which such items have accrued, and that could reduce a tax in another taxable period, including a net operating loss, net capital loss, disallowed business interest, foreign tax credit, charitable deduction, credit related to alternative minimum tax or any other tax credit (a “Tax Asset”) generated by any member of the Company Group, generally shall be taken into account in determining the Separate Return Tax Liability in the taxable period(s) during which such Tax Assets of the Company Group are included in and used in the applicable Consolidated Return or Combined Return. Notwithstanding the foregoing, that portion of any such Tax Asset that has been taken into account in determining Tax Benefits (as defined below) for which Banpu Sub has received a payment under Section 4 shall not again be taken into account for purposes of reducing the Separate Return Tax Liability of the Company Group under this Section 2.2.5.

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2.2.6. If the Separate Return Tax Liability of the Company Group for a taxable period is less than zero, then the Separate Return Tax Liability of the Company Group shall be deemed to be zero for such period for purposes of Section 2.3.

 

2.3.          Payments of Separate Return Tax Liabilities.

 

2.3.1. No later than five (5) business days before the due date for the payment of the Banpu Group consolidated or combined tax liability with respect to a Consolidated Return or Combined Return for the entire taxable year, Banpu Sub shall pay to BNAC the excess (if any) of (i) the Separate Return Tax Liability of the Company Group for such taxable year determined with respect to such Consolidated Return or Combined Return, as the case may be, over (ii) such amounts (if any) previously paid by Banpu Sub to BNAC for such taxable year determined with respect to such Consolidated Return or Combined Return, as the case may be.

 

2.3.2. Payments made by Banpu Sub in accordance with this Section 2.3 and Section 3 shall be in lieu of any other payment by Banpu Sub on account of its share, if any, of the consolidated U.S. federal income tax liability of the Banpu Group due in respect of any Consolidated Return and the state or local income or franchise tax liability of the Banpu Group due in respect of any Combined Return for the relevant taxable year.

 

3.             Adjustments. Any adjustment of income, deduction, or credit that results after the taxable year in question by reason of any carryback, amended return, claim for refund, audit, or resolution of any dispute between the parties by the Expert (as defined below) or otherwise, shall be given effect by redetermining amounts payable and reimbursable hereunder for such taxable year (and other taxable years, where appropriate) for which this Agreement is in effect as if such adjustment had been part of the original determination hereunder, with interest payable (by Banpu Sub or BNAC, as the case may be) in the amounts provided in Section 6621 of the Code and penalties thereon payable only to the extent that penalties are actually paid by BNAC to any taxing authority with respect to such adjustment. Within ten (10) business days following any such adjustment, (i) Banpu Sub will provide BNAC a statement setting forth in reasonable detail the redetermined amounts payable and reimbursable hereunder; and (ii) the party responsible for such payment or reimbursement shall make such payment or reimbursement to the other party. If BNAC disagrees with the statement prepared by Banpu Sub under this Section 3, then BNAC shall promptly notify Banpu Sub and the parties shall use their reasonable best efforts to resolve the dispute and, to the extent the parties are unable to resolve such dispute, the provisions of Section 7 shall apply.

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4.             Payments for Tax Benefits of Banpu Sub. Within ten (10) business days of the filing of a Consolidated Return or Combined Return, (i) Banpu Sub shall provide to BNAC a statement setting forth in reasonable detail the amount equal to the reduction in the tax liability (or increase in tax refund) (the “Tax Benefit”) (if any) that the Banpu Group recognized on such Consolidated Return or Combined Return as a result of the Separate Return Tax Liability of the Company Group being less than zero for such taxable period or otherwise as a result of the use by the Banpu Group of Tax Assets or other Tax Items of loss, deduction or credit of the Company Group; and (ii) BNAC shall pay such amount to Banpu Sub. For the avoidance of doubt, no Tax Asset or other Tax Item that has been taken into account in any taxable period for the Company Group’s benefit in reducing the Separate Return Tax Liability otherwise determined and payable by Banpu Sub under Sections 2.2 and 2.3 shall again be taken into account for purposes of determining any amount payable under this Section 4.

 

5.             Tax Audits, Examinations and Other Tax Proceedings.

 

5.1.          Proceedings Relating to Consolidated or Combined Returns. Banpu Sub shall cooperate fully with BNAC in any audits, contests, or other administrative or judicial proceedings (“Tax Proceedings”) relating to any Consolidated Return or Combined Return. Except as provided in the following sentence, BNAC generally shall have sole control (but acting reasonably and in good faith) over and discretion as to the undertaking, conduct, defense, settlement or other disposition of any such Tax Proceeding with respect to a Consolidated Return or Combined Return. With respect to any Tax Proceedings arising out of any Consolidated Return or Combined Return in which any Tax Item of the Company Group is a subject of such Tax Proceeding (a “Contested Company Group Item”), Banpu Sub shall be entitled to participate in such Tax Proceeding, and BNAC shall consult with Banpu Sub with respect to any Contested Company Group Item, shall act in good faith with a view to the merits in connection with such Tax Proceeding, shall keep Banpu Sub updated and informed with respect to such Contested Company Group Item and shall not settle or compromise any Contested Company Group Item without Banpu Sub’s prior written consent, such consent not be unreasonably withheld or delayed.

 

5.2.          Proceedings Relating to Banpu Sub-Filed Returns. BNAC shall cooperate fully with Banpu Sub in Tax Proceedings relating to any Banpu Sub-Filed Return. Banpu Sub shall have, in good faith, sole control over and discretion as to the undertaking, conduct, defense, settlement or other disposition of any such Tax Proceeding. With respect to any Tax Proceedings arising out of any Banpu Sub-Filed Returns in which any Tax Item of the Banpu Group is a subject of such Tax Proceeding (a “Contested Banpu Group Item”), BNAC shall be entitled to participate in such Tax Proceeding, and Banpu Sub shall consult with BNAC with respect to any Contested Banpu Group Item, shall act in good faith with a view to the merits in connection with such Tax Proceeding, shall keep BNAC updated and informed with respect to such Contested Banpu Group Item and shall not settle or compromise any Contested Banpu Group Item without BNAC’s prior written consent, such consent not be unreasonably withheld or delayed.

 

5.3.          Notice. If a party becomes aware of the existence of a tax issue that may give rise to a Tax Proceeding, such party shall give prompt notice to the other party of such issue (and such notice shall contain factual information, to the extent known, describing any asserted tax liability in reasonable detail), and shall promptly forward to the other party copies of all notices and material communications with any tax authority relating to such issue. Failure to give timely notice shall not affect the indemnities given hereunder except, and only to the extent that, the indemnifying party shall have been actually materially prejudiced as a result of such failure.

 

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6.            Tax Liability of Banpu Sub in the Event of Disaffiliation. This Section 6 sets forth how certain tax matters are to be handled in cases where a transaction or event occurs that causes Banpu Sub to no longer be eligible to join with BNAC in the filing of a Consolidated Return or Combined Return (a “Deconsolidation Event”).

 

6.1.          In General. In the case of a Deconsolidation Event, (i) Banpu Sub and the other members of the Company Group shall remain liable under this Agreement for the Separate Return Tax Liability of the Company Group for the taxable period during which such Deconsolidation Event occurs and for prior taxable periods in which Banpu Sub was a member of the Banpu Group, and Banpu Sub shall be required to pay BNAC all amounts for such taxable periods that are determined pursuant to this Agreement and (ii) Banpu Sub shall remain entitled to receive, and BNAC shall remain liable to pay, any Tax Benefit, tax refund, or other amounts payable to Banpu Sub under this Agreement that relate to any taxable period beginning on or before the date of a Deconsolidation Event (a “Pre-Deconsolidation Period”). Moreover, should a Tax Proceeding ultimately result in assessment of a tax deficiency (or payment of a tax refund) against any Banpu Group member for years in which Banpu Sub or the other members of the Company Group were part of the Banpu Group, Banpu Sub shall remain liable for the Company Group’s portion of such tax deficiency (or remain entitled to receive the Company Group’s portion of such tax refund) determined pursuant to Section 2.2, Section 3, and Section 4 of this Agreement, plus related interest and penalties, if any.

 

6.2.          Allocation of Tax Items. In the case of a Deconsolidation Event, all tax computations for (i) any Pre-Deconsolidation Periods ending on the date of the Deconsolidation Event and (ii) the immediately following taxable period of Banpu Sub or any disaffiliated members of the Company Group, shall be made pursuant to the principles of Section 1.1502-76(b) of the Treasury Regulations or any similar provision of federal, state or local tax law, as agreed to by BNAC and Banpu Sub.

 

6.3.          Allocation of Tax Assets. In the case of a Deconsolidation Event, Banpu Sub and BNAC shall cooperate in determining the allocation of any Tax Assets among BNAC and Banpu Sub. The parties hereby agree that in the absence of controlling legal authority or unless otherwise provided under this Agreement, Tax Assets shall be allocated to (i) the party that generated such Tax Asset or (ii) in cases where it is unclear which party generated the Tax Asset, to the party required to bear the liability for the tax associated with such Tax Asset.

 

6.4.          Carrybacks. In the case of a Deconsolidation Event, BNAC agrees to pay to Banpu Sub the Tax Benefit from the recognition by BNAC on a Consolidated Return or Combined Return for any Pre-Deconsolidation Period of a carryback of any Tax Asset of the Company Group from taxable period beginning after the date of a Deconsolidation Event (except to the extent that such carryback of any Tax Asset increases any Taxes, or reduces any Tax Benefit, attributable to the Banpu Group for any reason); provided, however, that no payment shall be required to be made with respect to any Tax Benefit recognized by BNAC with respect to any Tax Asset that has previously been taken into account in any taxable period for the Company Group’s benefit to reduce the Separate Return Tax Liability determined and payable under Sections 2.2 and 2.3 or to determine any amount payable to Banpu Sub under Section 4. If subsequent to the payment by BNAC to Banpu Sub for any such Tax Benefit, there shall be a redetermination which results in a decrease (1) to the amount of the Tax Asset so carried back or (2) to the amount of such Tax Benefit, Banpu Sub shall repay to BNAC any amount paid to Banpu Sub pursuant to this Section 6.4 which would not have been payable to Banpu Sub pursuant to this Section 6.4 had the amount of the Tax Benefit been determined in light of these events, plus any related interest and penalties. Nothing in this Section 6.4 shall require BNAC to file an amended tax return or claim for refund of taxes.

 

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6.5.          Continuing Covenants. Each of BNAC and Banpu Sub (for itself and each member of the Company Group) agrees (i) not to take any action reasonably expected to result in an increased tax liability to the other, a reduction in a Tax Asset of the other or an increased liability to the other under this Agreement, and (ii) to take any action reasonably requested by the other that would reasonably be expected to result in a Tax Benefit; provided, in either such case, that the taking or refraining to take such action does not result in any additional cost not fully compensated for by the other party or any other adverse effect to such party. The parties hereby acknowledge that the preceding sentence is not intended to limit, and therefore shall not apply to, the rights of the parties with respect to matters otherwise covered by this Agreement.

 

7.             Disputes. In the event of a disagreement that BNAC and Banpu Sub are unable to resolve with respect to any determination required to be made pursuant to this Agreement (a “Reconciliation Dispute”), the Reconciliation Dispute shall be submitted for determination to a nationally recognized expert (the “Expert”) in the particular area of disagreement mutually acceptable to both parties. The Expert shall be a partner or principal in a nationally recognized accounting firm, and unless BNAC and Banpu Sub agree otherwise, the Expert shall not have any material relationship with BNAC or Banpu Sub, or other actual or potential conflict of interest. The costs and expenses relating to the engagement of such Expert shall be borne equally by BNAC and Banpu Sub, except that if the Expert determines that the proposed position submitted by a party to the Expert for its determination is frivolous, has not been asserted in good faith, or is not supported by substantial authority, then 100% of such costs, fees, and expenses shall be borne by such party. The Expert shall finally determine any Reconciliation Dispute and the determinations of the Expert pursuant to this Section 7 shall be final and binding on BNAC and Banpu Sub and may be entered and enforced in any court having competent jurisdiction.

 

8.             Treatment of Payments. The parties agree that any payments made by one party to another party pursuant to this Agreement shall be treated in accordance with the principles of Section 1.1502-32(b)(3)(iv)(D) of the Treasury Regulations or any similar provision of federal, state or local tax law, as reasonably determined by Banpu Sub, and accordingly are generally not includible in the taxable income of the recipient or as deductible by the payor.

 

9.             Indemnification. BNAC agrees to indemnify and hold harmless Banpu Sub and each other member of the Company Group against and from any claims of liability for (a) all U.S. federal income tax with respect to any Consolidated Returns, interest thereon, and penalties with respect thereto asserted by the Service, (b) all state or local income or franchise tax with respect to any Combined Returns, interest thereon, and penalties with respect thereto asserted by any state taxing authority, (c) any taxes imposed on any member of the Company Group pursuant to Treasury Regulation Section 1.1502-6 or any analogous provision of state or local tax law and (d) any other income taxes which a member of the Banpu Group (other than Banpu Sub or other members of the Company Group) is required to pay to any taxing authority, provided in each case that Banpu Sub has made the payments required to be made by Banpu Sub in respect of the applicable liability to BNAC pursuant to the applicable provisions of this Agreement. Each party agrees to indemnify the other party for taxes and losses arising out of or based upon (i) any breach or nonperformance of any covenant or agreement made or to be performed by such party contained in this Agreement; or (ii) supplying the other party with inaccurate or incomplete information, in connection with the preparation of any tax return.

 

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10.           Cooperation. The parties shall cooperate with one another in all matters relating to taxes (and each shall cause its respective affiliates to so cooperate). Banpu Sub shall provide BNAC, and BNAC shall provide Banpu Sub, with such cooperation and information as is necessary in order to enable BNAC and Banpu Sub to satisfy their respective tax and accounting obligations. Unless otherwise provided under this Agreement, such cooperation and information shall include (i) making the parties’ respective knowledgeable employees available during normal business hours, (ii) providing the information required by reasonable tax and accounting questionnaires from the other party (at the times and in the format as reasonably required by such other party), (iii) maintaining such books and records and providing such information as may be necessary or reasonably useful in the filing of Consolidated Returns, Combined Returns and Banpu Sub-Filed Returns, (iv) executing such documents as may be necessary or reasonably useful in connection with any Tax Proceeding, the filing of Consolidated Returns, Combined Returns and Banpu Sub-Filed Returns, or the filing of refund claims by a member of the Banpu Group or Company Group (including certification, to the best of a party’s knowledge, of the accuracy and completeness of the information it has supplied), (v) Banpu Sub providing BNAC with such documentation as may be requested by BNAC or its parent company in order to enable BNAC, BNAC’s parent company and its subsidiaries to satisfy the requirements for tax declarations or available tax exemptions under the applicable Revenue Laws (whether currently in effect or issued and implemented in the future) and (vi) taking any actions which the other party may reasonably request in connection with the foregoing matters.

 

11.           Legal and Accounting Fees. Unless otherwise specified herein, any fees or expenses (including internal expenses) for legal, accounting or other professional services rendered in connection with tax research relating to the Company Group, the preparation of a Consolidated Return or a Combined Return or any statement relating to any Separate Return Tax Liability or other calculations under this Agreement or the conduct of any Tax Proceeding shall be allocated between BNAC and Banpu Sub in a manner resulting in BNAC and Banpu Sub, respectively, bearing a reasonable approximation of the actual amount of such fees or expenses hereunder reasonably related to, and for the benefit of, each party. Banpu Sub shall pay BNAC for any fees and expenses allocated to Banpu Sub pursuant to this Section 11 within five (5) business days after the date Banpu Sub receives notice from BNAC requesting such payment.

 

12.           Effective Date and Termination.

 

12.1.        This Agreement shall be effective as of the date first written above.

 

12.2.        This Agreement shall terminate at such time as all obligations and liabilities of the parties hereto have been satisfied. The obligations and liabilities of the parties arising under this Agreement shall continue in full force and effect until all such obligations have been met and such liabilities have been paid in full, whether by expiration of time, operation of law, or otherwise. The obligations and liabilities of each party are made for the benefit of, and shall be enforceable by, the other parties and their successors and permitted assigns.

 

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13.           Captions. All Section captions contained in this Agreement are for convenience only and shall not be deemed a part of the Agreement.

 

14.           Counterparts. This Agreement may be executed in counterparts, each of which shall constitute an original and all of which, when taken together, shall constitute one Agreement.

 

15.           Amendment: Waiver. This Agreement may be amended, modified, superseded, cancelled or extended, and the provisions hereof may be waived, only by a written instrument signed by BNAC and Banpu Sub or, in the case of a waiver, either of them who is the party waiving compliance.

 

16.           Governing Law. This Agreement shall be governed by the laws of the State of Delaware, without regard to the conflict of laws rules thereof.

 

17.           Successors and Assigns. Neither BNAC nor Banpu Sub may assign, novate or otherwise transfer its rights, obligations or rights and obligations under this Agreement without the prior written consent of the other party. This Agreement shall be binding upon, and shall inure to all the benefits of, the parties hereto and their respective successors and permitted assigns.

 

18.           No Third-Party Beneficiaries. Nothing in this Agreement is intended to or shall confer any rights or benefits upon any person other than the parties hereto.

 

19.           Notices. Any notice or other communication required or permitted hereunder shall be in English and in writing and shall be delivered personally, telegraphed, telexed, sent by facsimile transmission or sent by certified, registered or overnight express mail, postage prepaid. Any such notice shall be deemed given when so delivered personally, telegraphed, telexed or sent by facsimile transmission or, if mailed by overnight mail, the day after the date of deposit with a reputable courier service, or if mailed by non-overnight certified or registered mail, five days after the date of deposit in the United States mails, as follows:

 

19.1.        if to BNAC:

 

Banpu North America Corporation
1200 17th Street, Suite 2100
Denver, CO 80202
E-mail: [***]
Attention: Mr. Thiti Mekavichai, Director

 

19.2.        if to Banpu Sub:

 

BKV Corporation
1200 17th Street, Suite 2100
Denver, CO 80202
E-mail: [***]
Attention: Lindsay Larrick, Vice President and General Counsel

 

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Any party may by notice given in accordance with this Section 19 to the other parties designate another address or person for receipt of notices hereunder.

 

[Remainder of Page Intentionally Left Blank]

 

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IN WITNESS WHEREOF, the parties have caused this Agreement to be executed by their respective officers as of the date set forth above.

 

BANPU NORTH AMERICA CORPORATION

By:

Name:

Title:

BKV CORPORATION

By:

Name:

Title:

Signature Page to Amended and Restated Tax Sharing Agreement

 

EX-10.7

Exhibit 10.7

Portions of this document have been redacted pursuant to Item 601(b)(10)(iv) of Regulation S-K because it is both not material and is the type that the registrant treats as private or confidential. Redacted portions are indicated with the notation “[***]”.

BKV Corporation

2021 LONG TERM INCENTIVE PLAN

ADOPTED JANUARY 1, 2021

1. Purpose of Plan.

The purpose of the BKV Corporation 2021 Long Term Incentive Plan (the “Plan”) is to advance the interests of BKV Corporation, a Delaware corporation (the “Company”), and its stockholders by enabling the Company and its Subsidiaries to attract and retain persons of ability to perform services for the Company and its Subsidiaries by providing an incentive to such individuals through opportunities for equity participation in the Company and by rewarding such individuals who contribute to the achievement by the Company of its economic objectives. This Plan and the terms set forth herein shall be subject to the criteria set forth on Appendix 3 attached hereto, which sets forth the parameters to which this Plan and each Incentive Award hereunder remain subject in accordance with the approval of the Plan by the Board.

2. Definitions.

The following terms will have the meanings set forth below, unless the context clearly otherwise requires. Terms defined elsewhere in the Plan will have the same meaning throughout the Plan.

2.1            “Adverse Action” means any Participant, during or within one year after the termination of Service, (a) being employed or retained by or rendering services to any organization that, directly or indirectly, competes with or becomes competitive with the Company or any Subsidiary, or rendering such services that are prejudicial or in conflict with the interests of the Company or any Subsidiary, or otherwise violating any non-compete or non-solicitation agreement with the Company or any Subsidiary, (b) violating any confidentiality agreement or agreement governing the ownership or assignment of intellectual property rights of the Company or any Subsidiary, or (c) engaging in any other conduct or act determined to be injurious, detrimental or prejudicial to any interest of the Company or any Subsidiary.

2.2            “Base Price” means the initial price per share of the Company’s Common Stock and is set at a constant $10.00 per share.

2.3            “BNAC” means BANPU North America Corporation, a Delaware corporation.

2.4            “Board” means the Board of Directors of the Company.

2.5            “Broad Parameters” mean a broad parameter for compensation for the Employees (excluding the CEO and the Senior Management) who have been approved by the Board from time to time and reflected in the Budget which broad parameters are set forth on Appendix 2 attached hereto.

2.6            “Budget” means the annual budget of the Company and its subsidiaries as approved and/or amended from time to time by the Board.

2.7            “Cause” means “cause” as defined in any employment or other agreement or policy applicable to the Participant’s Service, or if no such agreement or policy exists, and will mean (a) dishonesty, fraud, misrepresentation, embezzlement, breach of fiduciary duty or deliberate injury or attempted injury, in each case relating to the Company or any Subsidiaries, (b) any unlawful or criminal activity of a serious nature or act of moral turpitude, in each case relating to the Company or any Subsidiaries, or (c) persistent failure to perform his or her duties in accordance with his or her employment agreement or service contract with the Company or any Subsidiaries or to comply with the established work rules or internal policies of the Company or any Subsidiaries that has an adverse effect on the Company or any Subsidiaries following notice and an opportunity to cure; provided, however, that if there is a separate written agreement between the Participant and the Company or any Subsidiary that defines “cause”, such agreement shall control in the event of an inconsistency with the definition in this Section 2.7.

2.8            “CEO” means the chief executive officer of the Company from time to time.

2.9            “Change in Control” means an event described in Section 9.1(c).

2.10          “Code” means the Internal Revenue Code of 1986, as amended. Any reference to a section of the Code in the Plan will be deemed to include a reference to any applicable rules and regulations thereunder and any successor or amended section of the Code.

2.11          “Committee” means the group of individuals administering the Plan, as provided in Section 3.1.

2.12          “Common Stock” means the common stock of the Company, par value $0.01 per share, or the number and kind of shares of stock or other securities in accordance with Section 4.1.

2.13          “Director” means a member of the Board.

2.14          “Disability” means the disability of the Participant such as would entitle the Participant to receive disability income benefits pursuant to a long-term disability plan of the Company or Subsidiary then covering the Participant or, if no such plan exists or is applicable to the Participant, the permanent and total disability of the Participant within the meaning of Section 22(e)(3) of the Code.

2.15          “Effective Date” has the meaning given it in Section 14.

2.16          “Eligible Recipients” means (a) an Employee and (b) Director of the Company or any Subsidiary.

2.17          “Employee” means any person treated as an employee in the records of the Company or any Subsidiary. The Committee will determine in good faith and in the exercise of its sole discretion whether an individual has become or has ceased to be an Employee and the effective date of such individual’s employment or termination of employment, as the case may be. For purposes of an individual’s rights, if any, under the terms of the Plan as of the time of the Committee’s determination of whether or not the individual is an Employee, all such determinations by the Committee will be final, binding and conclusive as to such rights, if any, notwithstanding that the Company or any court of law or governmental agency subsequently makes a contrary determination as to such individual’s status as an Employee.

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2.18          “Exchange Act” means the Securities Exchange Act of 1934, as amended. Any reference to a section of the Exchange Act in the Plan will be deemed to include a reference to any applicable rules and regulations thereunder.

2.19          “Fair Market Value” means, with respect to the Common Stock, as of any date: (a) the closing sale price of the Common Stock as of such date at the end of the regular trading session, as reported on any national securities exchange on which the Common Stock is then listed (or, if no shares were traded on such date, as of the next preceding date on which there was such a trade); or (b) if the Common Stock is not so listed as described in above, the price, on a per share of the Common Stock basis, at which a willing seller would sell, and a willing buyer would buy, the Common Stock having full knowledge of all relevant facts, in an arm’s length transaction without taking into account the minority ownership interest of any shares of the Common Stock and the rights associated with any minority ownership interest hereunder. For all purposes under this Plan (including as to taxation), the fair market value of the Common Stock as described in (b) above shall be determined each Financial Year by the Committee using the independent and impartial valuation of the Common Stock performed by Guggenheim Securities, LLC, provided its fees are at competitive market rates and, if not at competitive market rates (as determined by the Board based upon evidence of fees charged by other United States investment banking firms for the same services) by another independent and impartial appraiser approved by the Board. Such determination will apply such Financial Year or until a new determination of the Fair Market Value is made. For the avoidance of doubt, during the period as from the adopted date hereof that the Company does not have a Fair Market Value determination as described in subpart (b) above, the Fair Market Value shall be $10.00 per share of Common Stock and will apply until the valuation is performed for the Committee’s first determination of the Fair Market Value.

2.20          “Financial Year” means a financial or fiscal year of the Company.

2.21          “Founding Stockholder” means an Eligible Recipient who is a party to the Stockholders’ Agreement.

2.22          “Incentive Award” or “Award” means an annual award of TRSUs and PRSUs granted to an Eligible Recipient pursuant to the Plan.

2.23          “Incentive Award Agreement” means a written or electronic agreement between the Company and a Participant setting forth the individual grant of the Incentive Award of TRSUs and/or PRSUs granted to such Participant and the terms, conditions and restrictions applicable to such Award.

2.24          “Initial Public Offering” or “IPO” means the admission of all or any part of the Common Stock or depository receipts (or the equivalent) representing the Common Stock of the Company to a United States securities exchange.

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2.25          “IPO Average Trading Price” means the arithmetic average closing price in dollars per share of the Company’s Common Stock over a period of 30 trading days, immediately subsequent to an IPO.

2.26          “IPO Issuance Price” means the stated price in dollars per share, at which the Company issues its shares of Common Stock to new investors in advance of and during an IPO.

2.27          “Minimum Target IPO Price” means the minimum price at which the Company targets an IPO Issuance Price, and shall be initially set at $12.00 per share; provided, the Board will have the ultimate decision as to approval of the IPO Issuance Price.

2.28          “Participant” means an Eligible Recipient who receives any Incentive Awards under the Plan.

2.29          “Performance-based Restricted Stock Units” or “PRSUs” means Restricted Stock Units granted to an Eligible Recipient pursuant to Section 6.2 and subject to a PRSU Vesting Schedule.

2.30          “Previously Acquired Shares” means shares of Common Stock that are already owned by the Participant or, with respect to any Incentive Award, that are to be issued to the Participant upon the grant, exercise, vesting or settlement of such Incentive Award.

2.31          “PRSU KPIs” means key performance goals and indicators of the Company for a performance period as set forth in Appendix 1 attached to this Plan, or any subsequent Appendix approved and adopted by the Board.

2.32          “PRSU Vesting Schedule” means the vesting of PRSUs based on the level of achievement of PRSU KPIs for the Plan’s performance period, as approved by the Board and set forth in Appendix 1 attached to this Plan, or any subsequent Appendix approved and adopted by the Board, and included in the Incentive Award Agreement. The performance period will begin on the Effective Date and end on the earlier of December 31, 2023, the date of an IPO, or the date of a Change in Control (each a “PRSU Vesting Date”).

2.33          “Restricted Stock Unit” means an Incentive Award denominated in shares of Common Stock and granted to an Eligible Recipient pursuant to Section 6.

2.34          “Securities Act” means the Securities Act of 1933, as amended. Any reference to a section of the Securities Act in the Plan will be deemed to include a reference to any applicable rules and regulations thereunder.

2.35          “Senior Management” means, in addition to the CEO, the four (4) employees of the Company reasonably likely to receive the highest compensation during the next Financial Year (excluding the compensation of the CEO) and/or any employee recommended by the CEO and approved by the Board in accordance with Section 15.3.2 of the Stockholders’ Agreement.

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2.36          “Service” means a Participant’s employment with the Company or any Subsidiary, whether in the capacity of an Employee or a Director. A change in the capacity in which the Participant renders service to the Company or a Subsidiary as an Employee, Director, or Third Party Service Provider, shall be treated as a termination of the Participant’s Service, unless the Committee otherwise determines in its sole discretion. A Participant’s Service will be deemed to have terminated either upon an actual termination of Service or upon the Subsidiary for which the Participant performs Service ceasing to be a Subsidiary of the Company (unless the Participant continues in the Service of the Company or another Subsidiary). Subject to the foregoing, the Committee, in its sole discretion, will have the authority to determine whether the Participant’s Service has terminated and the effective date of and reason for such termination.

2.37          “Stockholders’ Agreement” means that certain Stockholders’ Agreement dated May 1, 2020, entered into by and among BNAC, the Company and Founding Stockholders as listed therein as parties thereto.

2.38          “Subsidiary” means any entity that is directly or indirectly controlled by the Company or any entity in which the Company has a significant equity interest, as determined by the Committee, provided the Company has a “controlling interest” in the Subsidiary as defined in Treas. Reg. Sec. 1.409A-1(b)(5)(iii)(E)(1).

2.39          “Tax Date” means the date any withholding tax obligation arises under the Code or other applicable tax statute for a Participant with respect to an Incentive Award.

2.40            Third-Party Service Provider” means any consultant, agent, advisor or independent contractor who renders services to the Company or a Subsidiary that: (a) are not in connection with the offer and sale of the Company’s securities in a capital raising transaction, and (b) do not directly or indirectly promote or maintain a market for the Company’s securities.

2.41          “Time Restricted Stock Units” or “TRSUs” means the Restricted Stock Units granted to an Eligible Recipient under Section 6.3 and subject to a TRSU Vesting Schedule.

2.42          “TRSU Vesting Schedule” means the vesting period for TRSUs issued under Section 5.1 and Section 6.3, which, unless provided otherwise in an Incentive Award Agreement, is as follows: one-fourth (25%) of the TRSUs will vest immediately upon the issuance of the TRSUs and the remaining TRSUs will vest in equal percentages over the next three consecutive years (i.e., 25% of the total TRSUs vesting in whole units on each annual anniversary of the issuance of the TRSU) (each a “TRSU Vesting Date”).

3. Plan Administration.

3.1            The Committee. The Plan will be administered by the Compensation Committee of the Board and subject to the Board’s approval, or the Board if such Compensation Committee is dissolved. Such a committee will act by simple majority approval of the members (but may also take action by the written consent of a majority of the members of such committee), and any simple majority of the members of such a committee will constitute a quorum. As used in the Plan, “Committee” will refer to the Compensation Committee of the Board, or the Board if such Compensation Committee is dissolved. To the extent consistent with the applicable corporate law of the Company’s jurisdiction of incorporation, the Committee may delegate to any officers of the Company the duties, power and authority of the Committee under the Plan pursuant to such conditions or limitations as the Committee may establish. The Committee may exercise its duties, power and authority under the Plan in its sole and absolute discretion without the consent of any the Participant, the Eligible Recipients, or other party, unless the Plan specifically provides otherwise. The Committee will not be obligated to treat Participants or Eligible Recipients uniformly, and determinations made under the Plan may be made by the Committee selectively among Participants or Eligible Recipients, whether or not such Participants and Eligible Recipients are similarly situated. Each determination, interpretation or other action made or taken by the Committee pursuant to the provisions of the Plan will be final, conclusive and binding for all purposes and on all persons, including the Company, the stockholders of the Company, the Participants, the Eligible Recipients and their respective heirs and other successors-in-interest. No member of the Board or the Committee shall be liable for any action or determination made in good faith with respect to the Plan or any Incentive Award granted under the Plan, including any determination regarding current values of the Common Stock that is made in good faith.

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3.2            Authority of the Committee.

(a)            In accordance with and subject to the provisions of the Plan and the Broad Parameters, the Committee will have the authority to determine all provisions of Incentive Awards as the Committee may deem necessary or desirable and as consistent with the terms of the Plan, including the following: (i) the Eligible Recipients to be selected as Participants; (ii) the nature and extent of the Incentive Awards to be made to each Participant (including the number of shares of Common Stock to be subject to each Incentive Award, the manner in which Incentive Awards will vest and whether Incentive Awards will be granted in tandem with other Incentive Awards) and the form of Incentive Award Agreement evidencing such Incentive Award; (iii) the time or times when Incentive Awards will be granted; (iv) the duration of each Incentive Award; and (v) the restrictions and other conditions to which the payment or vesting of Incentive Awards may be subject. In addition, the Committee will have the authority under the Plan in its sole discretion to pay the economic value of any Incentive Award in the form of Common Stock.

(b)            Subject to the Broad Parameters, the Committee will have the authority under the Plan to amend or modify for any reason the terms of any outstanding Incentive Award that has already been granted to a Participant in any manner, including but not limited to, the authority to modify the number of shares or other terms and conditions of an Incentive Award, accelerate the vesting or otherwise terminate any restrictions relating to an Incentive Award, accept the surrender of any outstanding Incentive Award or, to the extent not previously exercised or vested, authorize the grant of new Incentive Awards in substitution for surrendered Incentive Awards; provided, however that the amended or modified terms are permitted by the Plan as then in effect, such amendment does not cause the Incentive Award to become taxable under Section 409A of the Code, and any Participant adversely affected by such amended or modified terms has consented to such amendment or modification, except for an amendment or modification pursuant to this Section 3.2(b), Section 3.2(c), Section 3.2(d), Section 6.2(f) or Section 6.3(e). No amendment or modification to an Incentive Award, however, whether pursuant to this Section 3.2 or any other provisions of the Plan, will be deemed to be a re-grant of such Incentive Award for purposes of the Plan.

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(c)            Subject to the Broad Parameters, in the event of (i) any reorganization, merger, consolidation, recapitalization, liquidation, reclassification, stock dividend, stock split, combination of shares, rights offering, extraordinary dividend or divestiture (including a spin-off) or any other similar change in corporate structure or shares; (ii) any purchase, acquisition, sale, disposition or write-down of a significant amount of assets or a significant business; (iii) any change in accounting principles or practices, tax laws or other such laws or provisions affecting reported results; (iv) any uninsured catastrophic losses or extraordinary non-recurring items as described in Accounting Standards Codification 225-20; (v) IPO or (vi) any other similar change, in each case with respect to the Company or any other entity whose performance is relevant to the vesting of PRSUs, the Committee (or, if the Company is not the surviving entity in any such transaction, the board of directors or other managing body of the surviving entity) may, without the consent of any affected Participant, amend or modify the vesting criteria (including any performance objectives) of any outstanding PRSUs that is based in whole or in part on the financial performance of the Company (or any Subsidiary or division or other sub-unit thereof) or such other entity so as equitably to reflect such event, with the desired result that the criteria for evaluating such financial performance of the Company or such other entity will be substantially the same (in the sole discretion of the Committee or the board of directors or other managing body of the surviving entity) following such event as prior to such event.

(d)            In addition to the authority of the Committee under Section 3.2(b) and notwithstanding any other provision of the Plan, the Committee may, in its sole discretion, amend the terms of the Plan or Incentive Awards with respect to Participants resident outside of the United States or employed by a non-U.S. Subsidiary in order to comply with local legal requirements, to otherwise protect the Company’s or Subsidiary’s interests, or to meet objectives of the Plan, and may, where appropriate, establish one or more sub-plans (including the adoption of any required rules and regulations) for the purposes of qualifying for preferred tax treatment under foreign tax laws. The Committee will have no authority, however, to take any action pursuant to this Section 3.2(d) to reserve shares of Common Stock or grant Incentive Awards in excess of the limitations provided in Section 4.1 and subject to the Broad Parameters.

4. Shares Available for Issuance.

4.1            Maximum Number of Shares Available. Unless otherwise approved by the Board, the maximum number of shares of the Common Stock that are reserved and available for issuance of the Incentive Awards under conditions of the Plan shall be 14,941,176 shares (the “Available Shares”). The shares of Common Stock available for issuance under the Plan may, at the election of the Committee, be either treasury shares or shares authorized but unissued, and, if treasury shares are used, all references in the Plan to the issuance of shares will, for corporate law purposes, be deemed to mean the transfer of shares from treasury. The CEO is prohibited from granting or issuing Incentive Awards in excess of sixty percent (60%) of the Available Shares on or before the end of calendar year 2022, with such sixty percent (60%) threshold determined based upon an assumption of achievement of all PRSU KPIs at Target Threshold (100%) for all PRSUs granted to Participants. Thereafter, the CEO may not issue Incentive Awards in excess of eighty percent (80%) of the Available Shares unless the CEO receives prior written approval of the Board to exceed such amount, with such eighty percent (80%) threshold determined based upon an assumption of achievement of all PRSU KPIs at Target Threshold (100%) for all PRSUs granted to Participants.

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4.2            Accounting for Incentive Awards. The grant of any Incentive Award under the Plan will reduce the maximum number of available shares of Common Stock remaining available for issuance of the Incentive Awards under the Plan by the number of shares subject to such Incentive Award. All granted shares so subtracted from the amount available under the Plan with respect to an Incentive Award that lapses, expires, is forfeited or for any reason is terminated or unvested will not automatically become available for issuance under the Plan.

5. Participation; Grant of Awards.

5.1            Incentive Awards. Subject to the limits of Section 4.1, commencing with the Financial Year that includes the Effective Date, each Eligible Recipient who is either (i) classified by the Company at the Senior Management level or (ii) is classified by the Company below the Senior Management level and is recommended for an Incentive Award by the CEO, shall be granted Incentive Awards that are generally (a) seventy percent (70%) Performance-based Restricted Stock Units under Section 6.2 and (b) thirty percent (30%) Time Restricted Stock Units under Section 6.3, with such ratio based on the anticipated grant of TRSUs for 2021 and the three (3) Financial Years following 2021. Incentive Awards granted to such Eligible Recipients (i) who are classified by the Company at the Senior Management level will be in the amounts as determined and approved by the Board based upon recommendations from the Committee, and (ii) who are classified below the Senior Management level will be in the amounts as determined and approved by the CEO in accordance with and subject to the Broad Parameters. For illustrative purposes only, attached hereto as Appendix 4 is an example evidencing the scenarios of grant and vesting of the PRSUs and TRSUs subject to the Incentive Awards contemplated herein.

6. Restricted Stock Unit Awards.

6.1            Grant. In accordance with Section 5.1 and Section 6, Eligible Recipients shall be granted one or more Incentive Awards of Performance-based Restricted Stock Units and/or Time Restricted Stock Units under the Plan.

6.2            Performance-Based Restricted Stock Units.

(a)            PRSU Grants. PRSUs will be granted to Eligible Recipients as a one-time grant, in a single tranche on the Effective Date of the Plan or upon an Eligible Recipient first becoming a Participant under the Plan.

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(b)            PRSU Vesting; Payout Amount. Notwithstanding any other provisions of the Plan to the contrary, the PRSUs granted under the Plan shall vest and be earned based on the level of vesting under the PRSU Vesting Schedule, provided in each case the Participant remains in the continuous Service of the Company or a Subsidiary from the date of grant to such PRSU Vesting Date. Except as otherwise provided in this Section 6.2, Section 7.2 and Section 7.3, the Performance-based Restricted Stock Units will vest and be earned and the number of shares of Common Stock payable in settlement of such vested PRSUs under Section 6.2(c) will be based on the level of achievement of the PRSU KPIs as of the end of the performance period and may range from zero percent (0%) to two hundred percent (200%). The PRSU KPIs shall be expressed at the following performance levels: “Minimum Threshold,” “Target Threshold,” and “Maximum Threshold.” The PRSU KPIs and their respective weightings are outlined in Appendix 1. Vesting and payouts (i) for a Minimum Threshold level of achievement of a PRSU KPI will be at zero percent (0%) of the Target Threshold level of vesting and payout, (ii) for a Target Threshold level of achievement of a PRSU KPI will be at one hundred percent (100%) of the Target Threshold level of vesting and payout, (iii) for a Maximum Threshold or greater level of achievement of a PRSU KPI will be at two hundred percent (200%) of the Target Threshold level of vesting and payout, and (iv) for a level of achievement of a PRSU KPI between Minimum Threshold and Target Threshold, or between Target Threshold and Maximum Threshold, the vesting and payout percentage will be at a percentage level determined by straight line interpolation between the threshold levels, as applicable.

(c)            Settlement. Upon vesting of an Incentive Award of Performance-based Restricted Stock Units, such vested units shall be settled by the delivery of shares of Common Stock as soon as practicable following the PRSU Vesting Date (but not later than the March 15 of the calendar year following the calendar year that includes the PRSU Vesting Date), subject to the Company’s retention of that number of shares of Common Stock necessary to satisfy any applicable tax withholding requirements.

(d)            Additional Restrictions. At the time of the grant of Performance-based Restricted Stock Units, the Board, as it deems appropriate, may impose such restrictions or conditions that delay the delivery of the shares of Common Stock subject to such Incentive Award to a time after the vesting of such Performance-based Restricted Stock Units, but not to a date that is more than three (3) years from the date of grant.

(e)            Dividend Equivalents. Dividend equivalents may not be credited in respect of shares of Common Stock covered by Performance-based Restricted Stock Units until such Performance-based Restricted Stock Units have vested.

(f)            Adjustment by Board. Notwithstanding anything herein to the contrary, the Board has reserved the right to reduce the amount of the settlement of a PRSU as reflected in Appendix 3.

6.3            Time Restricted Stock Units.

(a)            TRSU Grants. TRSUs shall be granted to Eligible Recipients annually beginning on the Effective Date of the Plan and in each of the three (3) Financial Years thereafter or commencing upon an Eligible Recipient first becoming a Participant under the Plan.

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(b)            Vesting Requirements. Notwithstanding any other provisions of the Plan to the contrary, the Incentive Awards of Time Restricted Stock Units granted to Eligible Recipients in accordance with Section 5.1 and Section 6.3, shall vest in accordance with the TRSU Vesting Schedule; provided in each case the Participant remains in the continuous Service of the Company or a Subsidiary from the date of grant to such TRSU Vesting Date. In addition, each Incentive Award of Time Restricted Stock Units shall provide that all non-vested units under the Incentive Award shall vest upon an Initial Public Offering or a Change in Control. The vesting requirements will be set forth in an Incentive Award Agreement evidencing such Time Restricted Stock Units. Except as otherwise provided in this Section 6.3, Section 7.2 and Section 7.3, the Time Restricted Stock Units will vest and be earned and the number of shares of Common Stock payable in settlement of such vested TRSUs under Section 6.3(c) will be based on the level of vesting on the TRSU Vesting Date. If any vesting requirements of any Time Restricted Stock Units are not satisfied, such Time Restricted Stock Units will be forfeited.

(c)            Settlement. Upon the vesting of an Award of Time Restricted Stock Units, such vested units shall be settled by the delivery of shares of Common Stock as soon as practicable following the TRSU Vesting Date (but not later than the March 15 of the calendar year following the calendar year that includes the TRSU Vesting Date), subject to the Company’s retention of that number of shares of Common Stock necessary to satisfy any applicable tax withholding requirements.

(d)            Dividend Equivalents. Dividend equivalents may not be credited in respect of shares of Common Stock covered by a Time Restricted Stock Units until such Time Restricted Stock Units have vested.

(e)            Adjustment by Board. Notwithstanding anything herein to the contrary, the Board has reserved the right to reduce the amount of the settlement of a PRSU as reflected in Appendix 3.

6.4            Compliance with Section 409A of the Code. Notwithstanding anything to the contrary set forth herein, any Incentive Award granted under the Plan that is not exempt from the requirements of Section 409A of the Code shall contain such provisions so that such Incentive Award will comply with the requirements of Section 409A of the Code. Such restrictions, if any, shall be determined by the Committee and contained in the Incentive Award Agreement evidencing such Incentive Award.

7. Termination of Service; Stock Purchase and Sale Rights.

7.1            Participants. Subject to Section 7.3, except to the extent that the Committee provides otherwise in an Incentive Award Agreement at the time of grant or determines otherwise pursuant to Section 7.2 or Section 7.3 (and such provisions and determinations need not be uniform among all Incentive Awards granted pursuant to the Plan), if a Participant’s Service is terminated by any reason including resignation, termination, Disability or death, all Incentive Awards held by the Participant that have not vested as of the effective date of the termination shall be terminated and forfeited without payment of any compensation.

7.2            Modification of Rights Upon Termination. Notwithstanding the other provisions of this Section 7, upon a Participant’s termination of Service, the Committee may, in its sole discretion (which may be exercised at any time on or after the date of grant, including following such termination) cause unvested Restricted Stock Units then held by such Participant to terminate, vest or become free of restrictions and conditions to payment, following such termination of Service, in each case in the manner determined by the Committee. The Committee may not take any such action adversely affecting any vested Restricted Stock Units and underlying shares of Common Stock acquired by a Participant without the consent of the affected Participant (subject to the right of the Committee to take whatever action it deems appropriate under Section 3.2(c), Section 7.3 and Section 9).

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7.3            Additional Forfeiture Events. Notwithstanding anything in the Plan, if a Participant is determined by the Committee, acting in its sole discretion, to have taken any action that would constitute Cause or an Adverse Action, irrespective of whether such action or the Committee’s determination occurs before or after termination of such Participant’s Service and irrespective of whether or not the Participant was terminated for Cause: (a) all rights of the Participant under the Plan and any Incentive Award Agreements evidencing an Incentive Award then held by the Participant will terminate and be forfeited without notice of any kind, and (b) the Committee in its sole discretion may require the Participant to surrender and return to the Company all or any shares of Common Stock received in settlement of any vested Award, or to disgorge all or any profits or any other economic value (however defined by the Committee) made or realized by the Participant, during the period beginning one year prior to the Participant’s termination of Service in connection with any shares of Common Stock issued upon the vesting of any Incentive Awards. The Company may defer the issuance of share certificates upon the vesting or settlement of any Incentive Award for a period of up to six (6) months after the date of such vesting or settlement in order for the Committee to make any determination as to the existence of Cause or an Adverse Action.

7.4            Repurchase Right. If a Participant either (i) commits any material breach of such Participant’s employment agreement or service contract with the Company and either (1) that breach is not capable of being remedied or (2) if capable of remedy, the Participant does not remedy that breach as soon as possible and in any event within thirty (30) days of receiving a notice from the Company requiring the Participant to remedy that breach, or (ii) the Participant’s employment with the Company is terminated for any reason, including due to resignation, termination, death or Disability, the Company shall have the right, as determined by the Board, to repurchase all (and not less than all) of the vested shares of Common Stock acquired by the Participant under this Plan, in accordance with the terms of this Section 7.4:

(a)            The purchase price of the vested shares of Common Stock purchased by the Company pursuant to this Section 7.4 shall be equal to the Fair Market Value of such shares applicable at the time of the repurchase.

(b)            The Company may exercise its election to acquire the Participant’s vested shares of Common Stock by delivery to the Participant (or the Participant’s beneficiary in the event of the Participant’s death), within ninety (90) after the effective date of the termination, of a written notice of the Company’s exercise of its repurchase rights under this Section 7.4.

(c)            The closing of the purchase of the vested shares of Common Stock pursuant to this Section 7.4 shall take place at the principal office of the Company not later than thirty (30) days following receipt of such notice by the Participant (or the Participant’s beneficiary in the event of the Participant’s death).

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(d)            The Participant (or the Participant’s beneficiary in the event of the Participant’s death) shall make such customary representations and warranties as may be reasonably requested by the Company regarding such seller’s capacity and authority, good title to, and the absence of liens on, such vested shares of Common Stock.

(e)            The Company will pay the purchase price for the vested shares of Common Stock purchased by the Company under this Section 7.4 in cash, payable by wire transfer of immediately available funds to the bank account provided to the Company by the Participant (or the Participant’s beneficiary in the event of the Participant’s death).

7.5            Put Right. In the event (a) a Participant’s employment with the Company is terminated for any reason, including due to the Participant’s death or Disability (but excluding by voluntary resignation by the Participant), or (b) a Participant’s employment with the Company is terminated by virtue of the Participant’s voluntary resignation and more than thirty-six (36) months have passed from the date of the first grant of an Incentive Award to that individual Participant, and, in each case, the Company has not exercised its right within the period under Section 7.4 to repurchase the Participant’s vested shares of Common Stock, the Participant (or the Participant’s beneficiary in the event of death) shall have the right to elect to sell to the Company by giving the Company, within ninety (90) days after the effective date of termination, a written notice specifying that he or she wishes to sell all (and not less than all) of his or her vested shares of Common Stock acquired by the Participant under the Plan, and the Company shall be required to purchase from the Participant, all (and not less than all) of the vested shares of Common Stock acquired by the Participant under the Plan, in accordance with the terms of this Section 7.5:

(a)            The selling price of the vested shares of Common Stock purchased by the Company pursuant to this Section 7.5 shall be equal to the Fair Market Value of such shares applicable at the time the election to sell is made.

(b)            The Participant (or the Participant’s beneficiary in the event of the Participant’s death) may exercise an election to sell vested shares of Common Stock by delivery of thirty (30) days’ written notice specifying the number of shares to be sold.

(c)            The closing of the purchase of the vested shares of Common Stock pursuant to this Section 7.5 shall take place at the principal office of the Company not later than thirty (30) days following receipt of such notice by the Company.

(d)            The Participant (or the Participant’s beneficiary in the event of the Participant’s death) shall make such customary representations and warranties as may be reasonably requested by the Company regarding such seller’s capacity and authority, good title to, and the absence of liens on, such vested shares of Common Stock.

(e)            The Company will pay the selling price for the vested shares of Common Stock purchased by the Company under this Section 7.5 in cash, payable by wire transfer of immediately available funds to the bank account provided to the Company by the Participant (or the Participant’s beneficiary in the event of the Participant’s death).

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7.6            Drag-Along Rights. If at any time BNAC (alone or together with any of the other stockholders of the Company) proposes to effect the sale of shares of Common Stock representing more than eighty percent (80%) of the total issued and outstanding shares of Common Stock, BNAC (and BNAC alone) may require the participation of all (and not less than all) of the vested shares of the Common Stock owned by the Participants in such sale in the manner set forth in this Section 7.6:.

(a)            BNAC shall exercise its rights pursuant to this Section 7.6 by delivering to the Company and each of the other stockholders of the Company a written notice (the “Drag-along Notice”) of such proposed sale no later than fifteen (15) days prior to the proposed closing thereof. Any Drag-along Notice shall make reference to the Participants’ obligations under this Section 7.6 and shall describe in reasonable detail:

(i)            the number of shares of Common Stock to be sold by BNAC;

(ii)           the person to whom such shares of Common Stock are proposed to be sold;

(iii)          the material terms and conditions of the sale, including the consideration to be paid; and

(iv)          the proposed date, time and location of the closing of the sale.

(b)            In any sale is subject to this Section 7.6, each of the Participants shall agree to sell all (and not less than all) of the shares of Common Stock owned by the Participant, free and clear of any liens and on the same terms and conditions as BNAC in such sale, and shall make such customary representations and warranties as may be reasonably requested by the Company regarding such seller’s capacity and authority, good title to, and the absence of liens on, such vested shares of Common Stock.

(c)            If BNAC (alone or together with any of the other stockholders of the Company) proposes to effect the sale of shares of Common Stock representing more than eighty percent (80%) of the total issued and outstanding shares of the Common Stock pursuant to this Section 7.6, the Participants shall consent to and not object to or exercise any appraisal or dissenters’ rights in connection with such transaction. Without limiting the foregoing, each of the Participants shall, if requested by BNAC, execute and deliver a power of attorney and custody agreement, in form and substance satisfactory to BNAC, with respect to the shares of Common Stock that are to be included by them in any sale pursuant to this Section 7.6. The power of attorney and custody agreement will provide, among other things, that each such Participant will:

(i)            deliver to and deposit into custody with BNAC, named as the custodian therein, a certificate or certificates representing such shares of Common Stock (duly endorsed in blank by the owner or owners thereof or accompanied by duly endorsed stock powers in blank); and

(ii)           irrevocably appoint BNAC as such stockholder’s agent and attorney-in-fact with full power to act thereunder on behalf of such stockholder with respect to the matters specified therein.

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(d)            Each Participant shall fully cooperate with BNAC and shall take all necessary actions to effectuate the sale of shares of Common Stock pursuant to this Section 7.6, including entering into such agreements and delivering such certificates and instruments, as may be reasonably requested from time to time by BNAC, provided that no Participant shall be:

(i)            liable for any indemnification obligations to any potential purchaser in respect of such representations and warranties on a joint, rather than several, basis, and in no event with respect to an amount in excess of the net cash proceeds to be paid to such stockholder in such transaction; and

(ii)           subject to any escrow or similar arrangement relating to such transaction with respect to an amount in excess of the net cash proceeds to be paid to such other stockholders in such transaction.

(e)            Each of the Participants participating in the sale of shares of Common Stock by BNAC under this Section 7.6 shall be paid a consideration (on a per share of Common Stock basis) on the same terms and conditions as BNAC in such sale.

8. Payment of Withholding Taxes.

8.1            General Rules.  The Company is entitled to (a) withhold and deduct from future wages of the Participant (or from other amounts that may be due and owing to the Participant from the Company or a Subsidiary), or make other arrangements for the collection of, an amount the Company reasonably determines to be the minimum statutory amount necessary to satisfy any and all federal, foreign, state and local withholding and employment-related tax requirements attributable to an Incentive Award, including the grant, vesting, or payment of dividends with respect to, an Incentive Award; (b) withhold shares of Common Stock from the shares issued or otherwise issuable to the Participant in connection with an Incentive Award; or (c) require the Participant promptly to remit the amount of such withholding to the Company before taking any action, including issuing any shares of Common Stock, with respect to an Incentive Award. Shares of Common Stock issued to the Participant in connection with an Incentive Award that gives rise to the tax withholding obligation that are withheld for purposes of satisfying the Participant’s withholding or employment-related tax obligation will be valued at their Fair Market Value on the Tax Date.

8.2            Special Rules. The Committee may, in its sole discretion and upon terms and conditions established by the Committee, permit or require a Participant to satisfy, in whole or in part, any withholding or employment-related tax obligation described in Section 8.1 by electing to tender, or by attestation as to ownership of, Previously Acquired Shares, by delivery of a promissory note (on terms acceptable to the Committee in its sole discretion), or by a combination of such methods. For purposes of satisfying a Participant’s withholding or employment-related tax obligation, Previously Acquired Shares tendered or covered by an attestation will be valued at their Fair Market Value on the Tax Date.

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9. Change in Control.

9.1            Certain Definitions. As used in this Plan, the following terms shall have the meanings set forth below:

(a)            “Affiliate” means, at the time of determination, any “parent” or “majority-owned subsidiary” of the Company, as such terms are defined in Rule 405 of the Securities Act. The Committee shall have the authority to determine the time or times at which “parent” or “majority-owned subsidiary” status is determined within the foregoing definition.

(b)            “Cash Transaction” means a merger or other transaction in which holders of the Common Stock receive a cash payment for each share exchanged or surrendered in such merger or other transaction.

(c)            “Change in Control” means (i) any merger or consolidation of the Company with or into another entity, including, without limitation, a reverse merger with a company that has common stock traded on a United States securities exchange or combination, in whatever form, with a special purpose acquisition company, (ii) any sale by the Company of all or substantially all of its assets, other than a sale of assets in which the stockholders of the Company immediately before the transaction will own immediately thereafter, directly or indirectly, securities having a majority in ordinary voting power of the outstanding securities of the acquiror of the Company’s assets, (iii) any sale or other transfer of shares of stock by one or more stockholders of the Company as a result of which any one transferee, together with the transferee’s Affiliates, will become the owner of a majority in ordinary voting power of the Company’s outstanding stock, but excluding (A) any sale or other transfer from a stockholder to a transferee who is an existing stockholder of the Company and (B) any sale or transfer of shares of stock directly by the Company or its Affiliates, or (iv) an Initial Public Offering.

9.2            Change in Control in General. In the event of a Change in Control, the Board, or any corporation or entity assuming the obligations of the Company, may take any one or a combination of the following actions as to outstanding Incentive Awards (and need not take the same action as to each such Incentive Award):

(a)            provide that an Incentive Award be vested in full or part either on the date of the Change in Control; or

(b)            provide that an Incentive Award shall be assumed, or equivalent Incentive Awards shall be substituted, by the acquiring or succeeding corporation or business entity (or an affiliate thereof).

9.3            Certain Exceptions. Notwithstanding anything herein to the contrary, the Board may provide in any Incentive Award Agreement that any or all of the preceding provisions of this Section 9 shall not apply to the Incentive Award granted under that Incentive Award Agreement.

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9.4            Stockholders’ Representative. For purposes of this section, “Stockholders’ Representative” means one or more persons or entities appointed by the Company’s stockholders to represent the interests of the stockholders in connection with a Change in Control, including with respect to matters such as: (a) determining any purchase price adjustment after the closing of the Change in Control; (b) taking any actions on behalf of the stockholders between the signing and closing of any agreement providing for such Change in Control (an “Acquisition Agreement”), including determining whether any closing conditions have been satisfied; (c) determining the amount to be paid to the stockholders after the closing of the Change in Control as the result of an earnout or other post-closing contingent payment obligation; (d) resolving any disputes relating to the payment to the stockholders of any amounts pursuant to the Acquisition Agreement, including any amounts placed in escrow in connection with the Change in Control, (e) receiving notices on behalf of the stockholders; (f) approving amendments to the Acquisition Agreement or (g) enforcing and protecting the rights and interests of the stockholders arising out of or under or in any manner relating to the Acquisition Agreement and any related agreements or documents, including entering into any settlement or instituting or defending any claim or litigation against the stockholders with respect to the matters contemplated by the Acquisition Agreement and any related agreements or documents and the transactions contemplated thereby. By receiving the grant of an Incentive Award under the Plan, each Participant agrees that (x) any Stockholders’ Representative appointed by the Company’s stockholders in connection with a Change in Control shall, without any further authorization or other action by the Participant, be appointed as such Participant’s representative and attorney-in-fact in connection with such Change in Control on the same terms and to the same extent as such Stockholders’ Representative is appointed by the Company’s stockholders in connection with such Change in Control and (y) the Participant will execute promptly on request of the Company any documents the Company deems necessary or desirable to provide further assurance of the foregoing appointment.

10. Rights of Eligible Recipients and Participants; Transferability.

10.1          Service. Nothing in the Plan or in any Incentive Award Agreement confers upon any Eligible Recipient or Participant any right to continue in the Service of the Company or any Subsidiary or interferes with or limits in any way the right of the Company or any Subsidiary to terminate the Service of any Employee at any time, with or without notice and with or without cause, subject to the terms of such Employee’s employment contract, if any.

10.2          Restrictions on Transfer.

(a)            Except pursuant to testamentary will or the laws of descent and distribution or as otherwise expressly permitted by subsection (b) below, no right or interest of any Participant in an Incentive Award of Restricted Stock Units will be assignable or transferable, or subjected to any lien, during the lifetime of the Participant, either voluntarily or involuntarily, directly or indirectly, by operation of law or otherwise and any such attempted assignment, transfer or sale, directly or indirectly, shall be void ab initio. Further, except pursuant to testamentary will or the laws of descent and distribution or as otherwise expressly permitted by Section 7.4, Section 7.5, Section 7.6 or subsection (b) below, no right or interest of any Participant in any Common Stock issued in settlement of a vested Restricted Stock Unit will be assignable or transferable, or subjected to any lien, during the lifetime of the Participant, either voluntarily or involuntarily, directly or indirectly, by operation of law or otherwise and any such attempted assignment, transfer or sale, directly or indirectly, shall be void ab initio

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(b)            A Participant will be entitled to designate a beneficiary to receive payment or settlement of an Incentive Award upon such Participant’s death, and in the event of such Participant’s death, payment of any amounts due under the Plan will be made to such beneficiary. If a deceased Participant has failed to designate a beneficiary, or if a beneficiary designated by the Participant fails to survive the Participant, payment of any amounts due under the Plan will be made to the Participant’s legal representatives, heirs and legatees. If a deceased Participant has designated a beneficiary and such beneficiary survives the Participant but dies before complete payment of all amounts due under the Plan, then such payments will be made to the legal representatives, heirs and legatees of the beneficiary. Any beneficiary, legal representative, heir or legatee of a Participant who receives an Incentive Award will remain subject to all the terms and conditions applicable to the Participant prior to such receipt.

(c)            Prior to an Initial Public Offering, a Participant (or the executor, administrator or other personal representative or other successor of a deceased Participant) may not sell, assign, transfer or otherwise dispose of vested shares of Common Stock acquired pursuant to an Incentive Award to a third party.

10.3          Non-Exclusivity of the Plan. Nothing contained in the Plan is intended to modify or rescind any previously approved compensation plans or programs of the Company or create any limitations on the power or authority of the Board to adopt such additional or other compensation arrangements as the Board may deem necessary or desirable.

11. Securities Law and Other Restrictions.

11.1          Securities Law Restrictions. Notwithstanding any other provision of the Plan or any Incentive Award Agreements, the Company will not be required to issue any shares of Common Stock under the Plan, and a Participant may not sell, assign, transfer or otherwise dispose of shares of Common Stock issued pursuant to Incentive Awards granted under the Plan: (a) unless there is in effect with respect to such shares a registration statement under the Securities Act and any applicable securities laws of a state or foreign jurisdiction or an exemption from such registration under the Securities Act and applicable state or foreign securities laws; (b) unless there has been obtained any other consent, approval or permit from any other U.S. or foreign regulatory body which the Committee, in its sole discretion, deems necessary or advisable; and (c) if at any time at which the Company is not required to file reports with the Securities and Exchange Commission (the “SEC”) pursuant to Sections 12(b), 12(g) or 15(d) of the Exchange Act or the rules and regulations thereunder, such issuance, sale or transfer would cause the number of stockholders of the Company to increase such that the Company would be within ten (10) stockholders of the number that would cause the Company to be required to file reports with the SEC pursuant to Sections 12(g) or 15(d) of the Exchange Act and the rules and regulations thereunder. The Company may condition such issuance, sale or transfer upon the receipt of any representations or agreements from the parties involved, and the placement of any legends on certificates representing shares of Common Stock, as may be deemed necessary or advisable by the Company in order to comply with such securities law or other restrictions.

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11.2          “Market Stand-Off” Restrictions. Except as otherwise approved by the Committee, the shares of Common Stock acquired in connection with the grant, vesting or settlement of an Incentive Award will be restricted following the effective date of a registration of the Company’s securities under the Securities Act, and the holder thereof will not, without the prior written consent of the Company or the representative(s) of any underwriters, (a) sell, pledge, offer to sell, contract to sell (including any short sale), sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase or otherwise transfer or dispose of, directly or indirectly, any shares of Common Stock or any securities convertible into or exercisable or exchangeable for Common Stock (whether such shares or any such securities are then owned by the Participant who exercised such option or are thereafter acquired); or (b) enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the Common Stock, whether any such transaction described in clause (a) or (b) above is to be settled by delivery of Common Stock or such other securities, in cash or otherwise. The provisions of this Section 11.2 will not apply (w) unless the executive officers and directors of the Company have agreed to be bound by substantially the same terms and conditions; (x) to public offerings other than the Company’s initial public offering and any public offering made within two (2) years thereafter; (y) to registrations relating solely to securities in connection with employee benefit plans or in connection with mergers, consolidations, reorganizations, or other transactions pursuant Rule 145 under the Securities Act; or (z) to transfers to donees who agree to be similarly bound. The time period for such market stand-off will be determined by the Company and the representative(s) of any underwriters but will in no event exceed one hundred eighty (180) days from the date of the final prospectus with respect to the applicable public offering. The Company may impose stop-transfer instructions during such stand-off period with respect to the shares of Common Stock subject to this restriction if necessary to enforce such restrictions. The underwriters in connection with any such public offering are intended third party beneficiaries of this Section 11.2 and will have the right, power and authority to enforce the provisions hereof as though they were a party hereto.

12. Compliance with Section 409A.

It is intended that the Plan and all Incentive Awards hereunder be construed and administered in a manner that will comply with the requirements of an exception to Section 409A of the Code; provided, that, in accordance with Section 6.4, an Incentive Award may be granted pursuant to an Incentive Award Agreement that is subject to and complies with the requirements of Section 409A of the Code. The Committee is authorized to adopt rules or regulations deemed necessary or appropriate to qualify for an exception from the requirements of Section 409A of the Code.

13. Plan Amendment, Modification and Termination.

The Board may amend, suspend or terminate the Plan or any portion or whole thereof at any time. The Board, may amend the Plan from time to time in such respects as the Board may deem advisable in order that Incentive Awards under the Plan will conform to any change in applicable laws or regulations or in any other respect the Board may deem to be in the best interests of the Company. Notwithstanding the immediately preceding sentences set forth in this Section 13, no termination, suspension or amendment of the Plan may adversely affect any outstanding Incentive Award without the consent of the affected Participant, including, but not limited to, any amendment, suspension or termination of the terms set forth in Section 7 herein or any modification, termination or amendment to the terms applicable to such Incentive Award; provided, however, that this sentence will not impair the right of the Committee to take whatever action it deems appropriate under Section 2.1, Section 7.3 and Section 9.

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14. Effective Date and Duration of the Plan.

The Plan is effective as of January 1, 2021 (the “Effective Date”), and shall remain valid until the earlier of (i) 6 months after an IPO or (ii) January 1, 2024, provided the obligations and rights of the Company and any Participants hereunder shall remain in full force and effect as to all outstanding unvested or vested Restricted Stock Units and all Common Stock issued to a Participant issued in settlement of a Restricted Stock Unit granted pursuant to this Plan that has not been redeemed, in its entirety, by the Company including, but not limited to, all rights and obligations set forth in Section 7 herein; provided, the Plan may be terminated prior to such time by the Board. No Incentive Award will be granted after termination of the Plan. This Plan shall survive termination solely for the outstanding Incentive Awards which have already been granted to the Participants before the expiration date or termination of the Plan, as case may be.

15. Miscellaneous.

15.1          Usage. In the Plan, except where otherwise indicated by clear contrary intention, (a) any masculine term used herein also includes the feminine, (b) the plural includes the singular, and the singular includes the plural, (c) “including” (and with correlative meaning “include”) means including without limiting the generality of any description preceding such term, and (d) “or” is used in the inclusive sense of “and/or”.

15.2          Governing Law and Venue. The validity, construction, interpretation, administration and effect of the Plan and any rules, regulations and actions relating to the Plan will be governed by and construed exclusively in accordance with the laws of the State of New York, notwithstanding the conflicts of laws principles of any jurisdictions. Any legal proceeding related to the Plan will be brought in an appropriate New York court, and the parties to any Incentive Award Agreement consent to the exclusive jurisdiction of the court for this purpose.

15.3          Successors and Assigns. The Plan will be binding upon and inure to the benefit of the successors and permitted assigns of the Company and the Participants.

15.4          Construction. Wherever possible, each provision of the Plan and any Incentive Award Agreement will be interpreted so that it is valid under the applicable law. If any provision of the Plan or any Incentive Award Agreement is to any extent invalid under the applicable law, that provision will still be effective to the extent it remains valid. The remainder of the Plan and the Incentive Award Agreement also will continue to be valid, and the entire Plan and Incentive Award Agreement will continue to be valid in other jurisdictions.

15.5          Initial Public Offering Process. It is the intent of the Company to seek an IPO on or before the third anniversary of the Effective Date of the Plan. The CEO and the Senior Management will seek to achieve or exceed the Minimum Target IPO Price as part of the Company’s pursuit of an IPO. In the event that the market conditions are not conducive to the pursuit of an IPO on or before the third anniversary of the Effective Date of the Plan, the CEO and the Senior Management, in conjunction with the Board of Directors, may elect to delay the IPO for up to one (1) year after the third anniversary of the Effective Date of the Plan. Upon or before a successful completion of an IPO, the Plan will be supplanted with a new equity incentive plan, as determined by the Board in its sole and absolute discretion. It is currently anticipated that this replacement plan would be comparable to similar plans maintained by U.S. public companies.

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IN WITNESS WHEREOF, the undersigned, on behalf of BKV Corporation, has executed this BKV Corporation 2021 Long Term Incentive Plan document effective as of January 1, 2021.

BKV CORPORATION
By:	/s/ Christopher Kalnin
Name: Christopher Kalnin
Title: CEO
Dated: December 9, 2020

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ACKNOWLEDGED AND ACCEPTED BY:
BANPU NORTH AMERICA CORPORATION
By:	/s/ Thiti Mekavichai
Name: Thiti Mekavichai
Title: CEO
Dated: December 9, 2020

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Appendix 1

PRSU KPIs

Performance Period. The following PRSU KPIs are based on the Plan’s performance period beginning on the Effective Date and ending on the earlier of December 31, 2023, the date of an IPO, the date of a Change in Control, or the date of the Company’s reverse merger with a company that has common stock traded on a United States securities exchange.

PRSU KPIs	Minimum Threshold			Target Threshold			Maximum Threshold			Weighting
Total Shareholder Return (TSR)		[***]			[***]			[***]			60	%
Return on Capital Employed (ROCE)		[***]			[***]			[***]			20	%
IPO Readiness		[***]			[***]			[***]			20	%
Payout Percentage		0	%		100	%		200	%

Total Shareholder Return (TSR).

Total Shareholder Return or “TSR” is defined as the Fair Market Value of the Fully Diluted Shares outstanding (in dollars per share) divided by the Base Price less any common dividends paid per share incorporating the timing on when such dividend payments are paid on a daily basis to accurately estimate the time weighted rate of return, stated in a percent. For purposes of determining the TSR in all scenarios, other than a reverse merger, TSR is expressed as the following formula:

TSR = [(Fair Market Value per fully diluted common share) ÷ (Base Price** less cumulative dividends paid per share (time weighted))] ^ (1/Years) less 100%

(i)            Public Company Basis. If the company has successfully completed an IPO then the TSR calculation will incorporate the IPO Average Trading Price as the basis for determining the Fair Market Value of the company. In the event of a reverse merger to go public, the Company would utilize the average trading price of the common stock of the reverse merged company over the 30 trading days following the reverse merger as the basis for Fair Market Value.

(ii)           Private Company Basis. If the company has not successfully completed an IPO, and there is no imminent plans to IPO, then on the third anniversary of the Plan Effective Date, the Fair Market Value would be determined according to Section 2.19 for utilization in the TSR calculation.

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The TSR shall be expressed as the following formula in the event of a reverse merger:

TSR=[Implied BKV Shareholders Equity Value* per share on a fully diluted common stock price) ÷ (Base Price** less cumulative dividends paid per share(time weighted))] ^(1/Years O/S) less 100%

*“Implied BKV Shareholders Equity Value per share on a fully diluted common stock price” means [[(the average 30 day closing price of the combined company’s stock, as measured 30 trading days immediately preceding the effective transaction date of the reverse merger x the number of Fully Diluted Shares owned by the BKV shareholders in the combined company’s stock as of the effective date of the reverse merger) + any cash/non-cash adjustment(s) (credit or liability) related to the reverse merger transaction to BKV shareholders, which actually increases or decreases the equity value of the BKV shareholders] ÷ the number of Fully Diluted Shares outstanding for all BKV shareholders, prior to the reverse merger transaction effective date]].

**adjusted to account for any stock split, stock distribution, recapitalization, combination or similar event.

For purposes of determining TSR, “Fully Diluted Shares” means the total number of shares of Common Stock that are outstanding and available to trade on the open market after all sources of conversion are exercised or occur, including, without limitation, any stock options, convertible bonds, vested TRSUs and vested PRSUs.

Average Return on Capital Employed (ROCE).

The Return on Capital Employed or “ROCE” is defined as the Earnings Before Interest and Tax (“EBIT”) as calculated on US GAAP basis, divided by Total Assets less Current Liabilities (including the current portion of debt). ROCE is expressed as the following formula:

ROCE = Average (EBIT / Capital Employed) over the performance period, where:

· EBIT = Earnings Before Interests & Tax (U.S. GAAP)

· Capital Employed = Total Assets – Current Liabilities including Assumed Current Portion of Debt (U.S. GAAP)

IPO Readiness.

IPO Readiness means the overall assessment of the Company’s readiness to successfully complete an IPO, as determined by a reputable third-party consultant evaluating all aspects of the Company’s capability to be publicly listed and (“Yes” or “No”) and the date at which the Company is ready (based on when the assessment was conducted).

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APPENDIX 2

BROAD PARAMETERS

The Broad Parameters approved by the Board for the CEO’s authority to grant Incentive Awards to each Employee shall be for each grant to be no more than 5 times the current salary (based upon the date of grant of such Incentive Award) of any Employee and taking into account a 4 year average duration of employment by such Employee.

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APPENDIX 3

Board Approved Parameters of INTENT for ISSUANCE OF

INCENTIVE AWARDS UNDER THE Plan

Long-term Incentive Plan (LTIP):

LTIP should not affect BKV's ability to pay dividends to holders of shares of Common Stock.

LTIP should not drive BKV to report a negative net income in any fiscal year.

Board retains discretion to reduce an Incentive Award payout by up to 20% of the total payout, at target level of achievement for PRSUs, at the sole and absolute discretion of the Board, to normalize against an irregular outcome.

Profit should be shared appropriately among all stakeholders.

In light of expensing of LTIP considerations, the LTIP grants commence on January 1, 2021, to align with a full fiscal year and to eliminate any expense implications for fiscal 2020.

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APPENDIX 4

EXAMPLE OF TRSU AND PRSU Grants

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EX-10.8

Exhibit 10.8

FIRST AMENDMENT

TO THE

BKV CORPORATION

2021 LONG TERM INCENTIVE PLAN

(ADOPTED JANUARY 1, 2021)

This First Amendment (this “Amendment”) to the BKV Corporation 2021 Long Term Incentive Plan (the “Plan”) is made by BKV Corporation, a Delaware corporation (the “Company”) this 5th day of November, 2021.

WHEREAS, the Company wishes, for accounting purposes, to treat Incentive Awards granted under the Plan and the shares of Common Stock issued in settlement of such Incentive Awards as equity rather than debt, which requires that (i) Participants (and beneficiaries) not be able to exercise their put or tender rights under an Incentive Award Agreement and the Plan for at least 181 days following the date on which such Incentive Award vests (the “Holding Period”), (ii) the Company not be permitted to exercise its right under an Incentive Award Agreement to purchase shares of Common Stock from Participants (and beneficiaries) until after the Holding Period, and (iii) a fair market value determination made quarterly to the extent necessary to affect transactions during the year; and

WHEREAS, the Company wishes to make available to Participants who receive a share of the Company’s Common Stock in settlement of an Incentive Award under the Plan, the right, following the Holding Period, to tender such shares for repurchase by the Company in accordance with and subject to the limits and other requirements established under the Company’s Sell Fund Repurchase Program as in effect from time to time (the “Sell Fund Repurchase Program”); and

WHEREAS, the Company wishes to amend the Plan (i) to impose the requirement that a Participant (or beneficiary following the Participant’s death) may not exercise their right to put any shares acquired by such Participant (or beneficiary) prior to the date that is 181 days following the date the Participant became vested in the right to receive a share of the Company’s Common Stock, (ii) to require a fair market value determination made quarterly to the extent necessary to affect transactions occurring during the year, (iii) to provide eligible Participants the right to tender such shares for repurchase by the Company in accordance with and subject to the limits and other requirements established under the Company’s Sell Fund Repurchase Program, and (iv) to prohibit the Company from exercising its right to purchase from the Participant (or beneficiary) shares acquired by such Participant (or beneficiary) prior to the date that is 181 days following the date the Participant became vested in the right to receive a share of the Company’s Common Stock.

NOW THEREFORE, the Plan is amended as follows:

1.     Section 2.19 of the Plan regarding the definition of “Fair Market Value” is amended and restated effective as of October 31, 2021 to read as follows:

2.19            “Fair Market Value” means, with respect to the Common Stock, as of any date: (a) the closing sale price of the Common Stock as of such date at the end of the regular trading session, as reported on any national securities exchange on which the Common Stock is then listed (or, if no shares were traded on such date, as of the next preceding date on which there was such a trade); or (b) if the Common Stock is not so listed as described in above, the price, on a per share of the Common Stock basis, at which a willing seller would sell, and a willing buyer would buy, the Common Stock having full knowledge of all relevant facts, in an arm’s length transaction without taking into account the minority ownership interest of any shares of the Common Stock and the rights associated with any minority ownership interest hereunder. For all purposes under this Plan (including as to taxation), the fair market value of the Common Stock as described in (b) above shall be determined quarterly during each Financial Year, if needed for transactions occurring during the year, by the Committee using the independent and impartial valuation of the Common Stock performed, on an annual basis, by Guggenheim Securities, LLC, with interim valuations based on the methodologies established in such annual Guggenheim Securities, LLC valuation prepared by the Company or a third party with valuation expertise. The annual valuation may be performed by an independent and impartial appraiser approved by the Board other than Guggenheim Securities, LLC if its fees are not at competitive market rates (as determined by the Board based upon evidence of fees charged by other United States investment banking firms for the same services).

2. Section 7 of the Plan is amended by adding a new Section 7.7 to read as follows:

7.7            Holding Period.

(a)            A Participant (or beneficiary following the Participant’s death) who receives a share of the Company’s Common Stock in settlement of an equity-based incentive award under the Plan may not exercise their right to put such share of Common Stock to the Company for repurchase under Section 7.5 or tender such share of Common Stock to the Company for purchase under Section 7.8 prior to the date that is 181 days following the date the Participant became vested in the right to receive such share of the Company’s Common Stock under the terms of the equity-based incentive award.

(b)  The Company may not exercise its right to purchase shares of the Company’s Common Stock from a Participant (or beneficiary following the Participant’s death) under Section 7.4 prior to the date that is 181 days following the date the Participant became vested in the right to receive such share of the Company’s Common Stock under the terms of the equity-based incentive award.

3. Section 7 of the Plan is amended by adding a new Section 7.8 to read as follows:

7.8            Sell Fund Repurchase Program. If, and only if, an applicable Incentive Award Agreement (including by amendment of such agreement) specifically so provides, a Participant who receives shares of the Company’s Common Stock in settlement of an Incentive Award, shall have the right, subject to the holding requirement of Section 7.7, to tender such shares for repurchase by the Company in accordance with and subject to the limits and other requirements established under the Company’s Sell Fund Repurchase Program, as in effect from time to time.

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IN WITNESS WHEREOF, the undersigned, on behalf of BKV Corporation, has executed this First Amendment to the BKV Corporation 2021 Long Term Incentive Plan document effective as of the date first above written.

BKV CORPORATION
By:	/s/ Christopher P. Kalnin
Name:	Christopher P. Kalnin
Title:	CEO

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EX-10.9

Exhibit 10.9

Portions of this document have been redacted pursuant to Item 601(b)(10)(iv) of Regulation S-K because it is both not material and is the type that the registrant treats as private or confidential. Redacted portions are indicated with the notation “[***]”.

Time Restricted Stock Unit Award and

Performance-based Restricted Stock Unit Award

BKV CORPORATION

TIME RESTRICTED STOCK UNIT AWARD AND PERFORMANCE-BASED

RESTRICTED STOCK UNIT AWARD NOTICE

2021 EQUITY INCENTIVE PLAN

BKV Corporation, a Delaware corporation (the “Company”), pursuant to its 2021 Equity Incentive Plan (the “Plan”), hereby grants to the Participant a Time Restricted Stock Unit award of the number of Time Restricted Stock Units (as defined in the Plan), set forth below (the “Time Restricted Stock Units” or “TRSUs”) and the number of Performance-based Restricted Stock Units (as defined in the Plan) set forth below (the “Performance-based Restricted Stock Units” or “PRSUs”). The Time Restricted Stock Units and the Performance-based Restricted Stock Units are subject to all of the terms and conditions as set forth in this Time Restricted Stock Unit Award and Performance-based Restricted Stock Unit Award Notice (the “Award Notice”) and in the Time Restricted Stock Unit Award and Performance-based Restricted Stock Unit Award Agreement and the Plan, both of which are attached hereto and incorporated herein in their entirety.

Participant:	[     ]
Date of Grant:	[     ]
Number of Time Restricted Stock Units:	[     ]
TRSU Vesting Schedule:	[     ] TRSUs vest on the Date of Grant; thereafter [     ] TRSUs vest on the second anniversary of the Date of Grant and each annual anniversary thereafter; provided that the Participant’s Service has continued from the Date of Grant through each such date.
PRSU Vesting Schedule:	See Exhibit A attached hereto. At Target Payout, [      ] PRSUs, subject to adjustment under the Plan.
Performance Period:	January 1, 2021 to the earlier of December 31, 2023, an IPO or a Change in Control.
PRSUs Settlement Date:	Vested Performance-based Restricted Stock Units will be settled and shares of Common Stock underlying the vested Performance-based Restricted Stock Units will be issued immediately following the vesting thereof.

The undersigned Participant acknowledges that he or she has received a copy of this Time Restricted Stock Award and Performance-based Restricted Stock Unit Award Notice, the Time Restricted Stock Award and Performance-based Restricted Stock Unit Award Agreement and the Plan. As an express condition to the grant of the Award hereunder, the Participant agrees to be bound by the terms of this Time Restricted Stock Award and Performance-based Restricted Stock Unit Award Notice, the Time Restricted Stock Award and Performance-based Restricted Stock Unit Award Agreement and the Plan. The undersigned Participant further acknowledges that as of the Date of Grant, this Time Restricted Stock Award and Performance-based Restricted Stock Unit Award Notice, the Time Restricted Stock Award Agreement and Performance-based Restricted Stock Unit Award, and the Plan set forth the entire understanding between the Participant and the Company regarding the award of stock in the Company and supersede all prior oral and written agreements on that subject with the exception of (i) awards previously granted and delivered to the Participant by the Company, and (ii) any agreements noted in an attachment to this Time Restricted Stock Award and Performance-based Restricted Stock Unit Award Notice.

BKV CORPORATION:		PARTICIPANT:
By:

Name:	Date:
Title:	Address:
Date:

TIME RESTRICTED STOCK UNIT AWARD AND PERFORMANCE-BASED

RESTRICTED STOCK UNIT AWARD AGREEMENT

UNDER THE

BKV CORPORATION 2021 EQUITY INCENTIVE PLAN

Pursuant to the Time Restricted Stock Unit Award and Performance-based Restricted Stock Unit Award Notice (the “Award Notice”), and subject to the terms of this Time Restricted Stock Unit Award and Performance-based Restricted Stock Unit Award Agreement (this “Agreement”) and the BKV Corporation 2021 Equity Incentive Plan (the “Plan”), BKV Corporation, a Delaware corporation (the “Company”), and the Participant agree as follows. Capitalized terms not otherwise defined in this Agreement or in the Award Notice will have the same meanings as set forth in the Plan.

1.             Award.

(a)           Award of Time Restricted Stock Units. Subject to the terms and conditions set forth herein and in the Plan, the Company hereby grants to the Participant Time Restricted Stock Units, as set forth in the Award Notice, subject to adjustment as provide in the Plan, and each of which, if vested and earned pursuant to this Agreement, will be settled in one (1) share of the Company’s common stock, $0.01 par value per share, (“Common Stock”), at the time and subject to the terms, conditions and restrictions set forth in this Agreement and the Plan (the “TRSU Award Shares”).

(b)           Award of Performance-based Restricted Stock Units. Subject to the terms and conditions set forth herein and in the Plan, the Company hereby grants to the Participant Performance-based Restricted Stock Units, as set forth in the Award Notice, subject to adjustment as provided in the Plan, and each of which, if vested and earned pursuant to this Agreement, will be settled in one (1) share of the Company’s Common Stock, at the time and subject to the terms, conditions and restrictions set forth in this Agreement and the Plan (the “PRSU Award Shares” and collectively with the TRSU Award Shares, the “Award Shares”).

2.            Vesting.

(a)           Time Restricted Stock Units.

(i)            Vesting Schedule; Accelerated Vesting. Except as otherwise provided in this Section 2(a) or the Plan, the Time Restricted Stock Units will vest in the amounts and on the date(s) as indicated in the Vesting Schedule set forth in the Award Notice (each a “TRSU Vesting Date”), provided the Participant remains in the Service of the Company or Subsidiary through the applicable TRSU Vesting Date. In addition, all non-vested Time Restricted Stock Units that have not been forfeited shall vest upon an initial public offering of the Company’s shares of Common Stock or a Change in Control of the Company, provided the Participant remains in the Service of the Company or a Subsidiary through such date. Subject to the limitations contained herein and in the Plan, upon Participant’s termination of Service from the Company and all Subsidiaries the Time Restricted Stock Units that have not vested as of the date of such termination shall be forfeited and terminate; provided, however, that upon a Participant’s termination of Service, the Committee may, in its sole discretion cause any Time Restricted Stock Units then held by such Participant to terminate, vest or become free of restrictions and conditions to payment, in each case in the manner determined by the Committee; provided, further, that any such action adversely affecting any outstanding Incentive Award may not be effective without the consent of the affected Participant (subject to the right of the Committee to take whatever action it deems appropriate under Sections 3.2(c), 7.3 and 9 of the Plan).

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(b)           Performance-based Vesting; Determination of Amount of Performance-based Restricted Stock Units.

(i)            Performance Vesting; Performance Measures and Performance Goals. Except as otherwise provided in this Section 2(b) or the Plan, the Performance-based Restricted Stock Units will vest and the number of shares of Common Stock payable in settlement of such vested Performance-based Restricted Stock Units shall be determined at the end of the Performance Period (the “PRSU Vesting Date”) by reference to the level of achievement of the PRSU KPIs during the Performance Period in accordance with the table set forth in Exhibit A to this Agreement and may range from 0% to 200% of the Participant’s Target Payout as set forth in the Award Notice, provided the Participant remains in the Service of the Company or Subsidiary through the applicable PRSU Vesting Date. The PRSU KPIs for the Performance Period and their respective weightings and their respective Minimum Threshold, Target Threshold and Maximum Threshold levels, are described in the table set forth in Exhibit A to this Agreement; provided, however, that upon a Participant’s termination of Service, the Committee may, in its sole discretion, cause any Performance-based Restricted Stock Units then held by such Participant to terminate, vest or become free of restrictions and conditions to payment, in each case in the manner determined by the Committee; provided, further, that any such action adversely affecting any outstanding Incentive Award may not be effective without the consent of the affected Participant (subject to the right of the Committee to take whatever action it deems appropriate under Sections 3.2(c), 7.3 and 9 of the Plan). In addition, all non-vested Performance-based Restricted Stock Units that have not been forfeited shall vest at the Target Payout level upon an initial public offering of the Company’s shares of Common Stock or on the date of a Change in Control of the Company, provided the Participant remains in the Service of the Company or a Subsidiary through such date.

(ii)           Determination of Amount of Earned Performance-based Restricted Stock Units. The number of Performance-based Restricted Stock Units to be settled in PRSU Award Shares (the “Earned Performance-based Restricted Stock Units”) will be determined by prorated, straight-line interpolation between the Minimum Threshold and Target Threshold, or Target Threshold and Maximum Threshold if the level of performance achieved for the PRSU KPIs for the Performance Period falls between such levels, as specified in the table set forth in Exhibit A to this Agreement, and the determination will be rounded up to the nearest whole number of Performance-based Restricted Stock Units. The Earned Performance-based Restricted Stock Units will be settled in shares of Common Stock as provided in Section 3(b) of this Agreement.

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(iii)          Requirement to Exceed Minimum Threshold Level of Performance. Except as otherwise provided in Section 2(b)(i) of this Agreement and Sections 6.2(a) and Section 7.2 of the Plan and to the extent not previously forfeited or terminated pursuant to this Agreement or the Plan, the Performance-based Restricted Stock Units shall be immediately forfeited and terminated as of the end of the Performance Period if the Committee reasonably determines the PRSU KPIs do not exceed the Minimum Threshold as described in the table set forth in Exhibit A to this Agreement and that no accelerated vesting event has occurred.

(c)           Forfeiture Events. If the Participant is determined by the Committee, acting in its sole discretion, to have taken any action that would constitute Cause or an Adverse Action, irrespective of whether such action or the Committee’s determination occurs before or after termination of the Participant’s Service and irrespective of whether or not the Participant was terminated for Cause: (i) all rights of the Participant under this Agreement and the Plan will terminate and be forfeited without notice of any kind; and (ii) the Committee, in its sole discretion, may require the Participant to surrender and return to the Company all or any shares of Common Stock received, or to disgorge all or any profits or any other economic value (however defined by the Committee) made or realized by the Participant, during the period beginning one year prior to the Participant’s termination of Service in connection with the Performance-based Restricted Stock Units.

(d)           Adjustment by Board. Notwithstanding anything herein to the contrary, the Board has reserved the right to reduce the amount of the settlement of a vested PRSU by up to 20% of the vested amount of the PRSU at Target Threshold, as reflected in Exhibit A, or a vested TRSU by up to 20% of the vested amount.

3.            Settlement; Issuance of Common Stock.

(a)           Time Restricted Stock Units.

(i)            Timing and Manner of Settlement. Immediately following the vesting of Time Restricted Stock Units under Section 2(a), such vested Time Restricted Stock Units will be converted to shares of Common Stock which the Company will issue and deliver to the Participant (either by delivering one or more certificates for such shares or by entering such shares in book entry form in the name of the Participant or depositing such shares for the Participant’s benefit with any broker with which the Participant has an account relationship or the Company has engaged to provide such services under the Plan) within sixty (60) days following the TRSU Vesting Date, except to the extent that shares of Common Stock are withheld to pay tax withholding obligations pursuant to Section 3(c) of this Agreement.

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(b)            Performance-based Restricted Stock Units.

(i)            Amount of Payment. In the event of the achievement in excess of the Minimum Threshold level of performance with respect to a PRSU KPI described in the table set forth in Exhibit A to this Agreement during the Performance Period, which achievement shall be certified in writing by the Committee as soon as practicable following the expiration of the Performance Period, the Participant shall vest in the Earned Performance-based Restricted Stock Units up to the Maximum Threshold payout as determined pursuant to Section 2(b) and Exhibit A to this Agreement. The Participant may not be entitled to receive a greater number of PRSU Award Shares than the Earned Performance-based Restricted Stock Units at the Maximum Threshold payout, subject to adjustment as provided in the Plan. In the event Performance-based Restricted Stock Units are forfeited or cancelled for any reason pursuant to this Agreement or otherwise, no shares of Common Stock will be issued or payment made in settlement of such Performance-based Restricted Stock Units.

(ii)           Timing and Manner of Settlement. Earned Performance-based Restricted Stock Units, including if vesting is accelerated as provided under the Plan, will be converted to shares of Common Stock which the Company will issue and deliver to the Participant (either by delivering one or more certificates for such shares or by entering such shares in book entry form in the name of the Participant or depositing such shares for the Participant’s benefit with any broker with which the Participant has an account relationship or the Company has engaged to provide such services under the Plan) within sixty (60) days following the PRSU Vesting Date, except to the extent that shares of Common Stock are withheld to pay tax withholding obligations pursuant to Section 3(c) of this Agreement.

(c)           Withholding Taxes. Whenever any Time Restricted Stock Units and Performance-based Restricted Stock Units granted under the terms of this Agreement vest and shares of Common Stock are issued in settlement thereof, the Participant is responsible to provide to the Company when due, the minimum amount necessary for the Company to satisfy all of its federal, state and local withholding (including FICA) tax requirements relating to such taxable event. The Committee may, in its sole discretion and upon terms and conditions established by the Committee, permit or require the Participant to satisfy these minimum withholding tax obligations in connection with the settlement of the Time Restricted Stock Units and Performance-based Restricted Stock Units by withholding shares of Common Stock issuable upon settlement of the Time Restricted Stock Units or Performance-based Restricted Stock Units. When withholding shares of Common Stock for taxes is effected under this Agreement and the Plan, it will be withheld only up to the minimum amount the Company reasonably determines is necessary to satisfy any tax withholding obligation in the Participant’s applicable tax jurisdiction.

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4.            Rights of Participant; Transferability.

(a)           No Right to Continued Employment. Nothing in the Plan or in this Agreement confers upon the Participant any right to continue in the Service of the Company or any Subsidiary or interferes with or limits in any way the right of the Company or any Subsidiary to terminate the Service of the Participant at any time, with or without notice and with or without cause.

(b)           Rights as a Stockholder. Except as otherwise provided in the Plan, notwithstanding any restrictions to which Time Restricted Stock Units and Performance-based Restricted Stock Units may be subject, a Participant will have all voting, dividend, liquidation and other rights with respect to Award Shares issued in settlement of Earned Time Restricted Stock Units and Earned Performance-based Restricted Stock Units only upon the Participant becoming the holder of record of such shares as if such Participant were a holder of record of such shares.

(c)           Dividends. The Participant will not receive any cash dividends or Dividend Equivalents based on the dividends declared on the Common Stock underlying the Time Restricted Stock Units and Performance-based Restricted Stock Units during the period between the Grant Date and the date the Earned Time Restricted Stock Units or Earned Performance-based Restricted Stock Units are settled in shares of Common Stock.

(d)           Non-Transferability. Except as otherwise expressly permitted by the Plan, unless approved by the Committee in its sole discretion, no right or interest of the Participant in the Award Shares prior to the vesting of an Award and issuance of the Award Shares, will be assignable or transferable, or subjected to any lien, during the lifetime of the Participant, either voluntarily or involuntarily, directly or indirectly, by operation of law or otherwise.

5.            Purchase and Sale Rights Relating to Common Stock.

(a)           Restriction on Transfer of Common Stock. Except pursuant to testamentary will or the laws of descent and distribution or as otherwise expressly permitted by this Section 5, prior to an initial public offering of shares of Common Stock, a Participant (or the executor, administrator or other personal representative or other successor of a deceased Participant) may not sell, assign, transfer or otherwise dispose of, directly or indirectly, by operation of law or otherwise, Award Shares acquired pursuant to an Incentive Award to a third party without prior approval of such sale, assignment, transfer or disposition by the Committee or the Board, and any such attempted assignment, transfer or sale, directly or indirectly, shall be void ab initio. A Participant may transfer, for no value, vested Award Shares to a trust established by the Participant for estate planning purposes and controlled by the Participant.

(b)           Repurchase Right. If the Participant either (A) commits any material breach of such Participant’s employment agreement or service contract with the Company and either (1) that breach is not capable of being remedied or (2) if capable of remedy, the Participant does not remedy that breach as soon as possible and in any event within thirty (30) days of receiving a notice from the Company requiring the Participant to remedy that breach, or (B) the Participant’s employment with the Company is terminated for any reason, including due to death or disability, the Company shall have the right, as determined by the Board, to repurchase all (and not less than all) of the vested shares of Common Stock acquired by the Participant under this Plan, in accordance with the terms of this Section 5(b):

(i)            The selling price of the vested shares of Common Stock purchased by the Company pursuant to this Section 5(b) shall be equal to the Fair Market Value of such shares at the time of the repurchase.

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(ii)           The Company may exercise its election to acquire the Participant’s vested shares of Common Stock by delivery of ninety (90) days’ written notice to the Participant (or the Participant’s beneficiary in the event of the Participant’s death).

(iii)           The closing of the purchase of the vested shares of Common Stock pursuant to this Section 5(b) shall take place at the principal office of the Company not later than thirty (30) days following receipt of such notice by the Participant (or the Participant’s beneficiary in the event of the Participant’s death).

(iv)           The Participant (or the Participant’s beneficiary in the event of the Participant’s death) shall make such customary representations and warranties as may be reasonably requested by the Company regarding such seller’s good title to, and the absence of liens on, such vested shares of Common Stock.

(v)           The Company will pay the purchase price for the vested shares of Common Stock purchased by the Company under this Section 5(b) in cash, payable by wire transfer of immediately available funds to the bank account provided to the Company by the Participant (or the Participant’s beneficiary in the event of the Participant’s death)

(c)           Put Right. In the event (A) the Participant’s employment with the Company is terminated for any reason, including due to death or disability (but excluding by voluntary resignation by the Participant) or (B) the Participant’s employment with the Company is terminated by virtue of the Participant’s voluntary resignation after more than thirty-six (36) months have passed from the date of the first grant of an Incentive Award under the Plan to the Participant, and, in each case, the Company has not exercised its right under Section 5(b) to repurchase the Participant’s shares of Common Stock, the Participant (or the Participant’s beneficiary in the event of death) shall have the right to elect to sell to the Company, and the Company shall be required to purchase from the Participant, all (and not less than all) of the vested Award Shares acquired by the Participant under the Plan, in accordance with the terms of this Section 5(c):

(i)            The selling price of the vested Award Shares purchased by the Company pursuant to this Section 5(c) shall be equal to the Fair Market Value of such shares at the time of the election to sell.

(ii)           The Participant (or the Participant’s beneficiary in the event of the Participant’s death) may exercise an election to sell vested Award Shares by delivery of thirty (30) days’ written notice specifying the number of vested Award shares to be sold.

(iii)          The closing of the purchase of vested Award Shares of Common Stock pursuant to this Section 5(c) shall take place to the principal office of the Company not later than thirty (30) days following receipt of such notice by the Company.

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(iv)          The Participant (or the Participant’s beneficiary in the event of the Participant’s death) shall make such customary representations and warranties as may be reasonably requested by the Company regarding such seller’s good title to, and the absence of liens on, such vested Award Shares.

(v)           The Company will pay the purchase price for the vested Award Shares purchased by the Company under this Section 5(c) in cash, payable by wire transfer of immediately available funds to the bank account provided to the Company by the Participant (or the Participant’s beneficiary in the event of the Participant’s death).

(d)           Drag-Along Rights. If at any time BNAC (alone or together with any of the other Company stockholders) proposes to effect the sale of shares of Common Stock representing more than eighty percent (80%) of the total issued and outstanding shares of Common Stock, BNAC may require the participation of all (and not less than all) of the shares of Common Stock owned by the Participant in such sale in the manner set forth in this Section 5(d).

(i)            BNAC shall exercise its rights pursuant to this Section 5(d) by delivering to the Company and each of the other Company stockholders a written notice (the “Drag-along Notice”) of such proposed sale no later than fifteen (15) days prior to the proposed closing thereof. Any Drag-along Notice shall make reference to the Participants’ obligations under this Section 5(d) and shall describe in reasonable detail:

(A)          the number of shares of Common Stock to be sold by BNAC;

(B)          the person to whom such shares of Common Stock are proposed to be sold;

(C)          the material terms and conditions of the sale, including the consideration to be paid; and

(D)          the proposed date, time and location of the closing of the sale.

(ii)           In any sale is subject to this Section 5(d), each of the Participants shall agree to sell all (and not less than all) of the shares of Common Stock owned by the Participant, free and clear of any liens and on the same terms and conditions as BNAC in such sale.

(iii)          If BNAC (alone or together with any of the other Company stockholders) proposes to effect the sale of shares of Common Stock representing more than eighty percent (80%) of the total issued and outstanding shares of the Company’s Common Stock pursuant to this Section 5(d), the Participants shall agree to consent to and not object to or exercise any appraisal or dissenters’ rights in connection with such transaction. Without limiting the foregoing, each of the Participants will agree, if requested by BNAC, to execute and deliver a power of attorney and custody agreement, in form and substance satisfactory to BNAC, with respect to the shares of Common Stock that are to be included by them in any sale pursuant to this Section 5(d). The power of attorney and custody agreement will provide, among other things, that each such Participant will:

(A)          deliver to and deposit into custody with BNAC, named as the custodian therein, a certificate or certificates representing such shares of Common Stock (duly endorsed in blank by the owner or owners thereof or accompanied by duly endorsed stock powers in blank); and

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(B)           irrevocably appoint BNAC as such stockholder’s agent and attorney-in-fact with full power to act thereunder on behalf of such stockholder with respect to the matters specified therein.

(iv)          Each Participant shall fully cooperate with BNAC and shall take all necessary actions to effectuate the sale of shares of Common Stock pursuant to this Section 5(d), including entering into such agreements and delivering such certificates and instruments, as may be reasonably requested from time to time by BNAC, provided that no Participant shall be:

(A)          liable for any indemnification obligations to any potential purchaser in respect of such representations and warranties on a joint, rather than several, basis, and in no event with respect to an amount in excess of the net cash proceeds to be paid to such stockholder in such transaction; and

(B)           subject to any escrow or similar arrangement relating to such transaction with respect to an amount in excess of the net cash proceeds to be paid to such other stockholders in such transaction.

(v)           Each of the Participants participating in the sale of shares of Common Stock by BNAC under this Section 5(d) shall be paid a consideration (on a per share of Common Stock basis) on the same terms and conditions as BNAC in such sale.

6.             Change in Control.

(a)           Acceleration; Alternative Treatment. If a Change in Control of the Company occurs, then, except to the extent that an equivalent or substituted Award is provided to the Participant to replace the Award pursuant to Section 9.2(b) of the Plan, or unless otherwise provided by the Committee in its sole discretion at any time on or after the Date of Grant, the Award Shares will vest immediately and become non-forfeitable, regardless of whether the Participant remains in the employ or service of the Company or any Subsidiary or any acquiring entity or successor to the Company. In connection with a Change in Control, the Committee in its sole discretion, in lieu of providing an equivalent or substituted Award to the Participant, may determine that all or any portion of the Award and corresponding Award Shares, whether or not vested, will be terminated and forfeited and that in connection with such termination the Participant will receive for each Award Share a cash payment (or the delivery of shares of stock, other securities or a combination of cash, stock and securities with a fair market value (as determined by the Committee in good faith) equivalent to such cash payment) equal to the difference, if any, between the consideration received by stockholders of the Company in respect of a share of Common Stock in connection with such Change in Control and the purchase price per share, if any, under the Award, multiplied by the number of Award Shares subject to the grant; provided, however, that if such product is zero ($0) or less, the Award may be canceled and terminated without payment therefor.

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(b)           Stockholders’ Representative. In connection with any Change in Control, the Participant agrees that (i) any Stockholders’ Representative appointed by the Company’s stockholders in connection with such Change in Control shall, without any further authorization or other action by the Participant, be appointed as such Participant’s representative and attorney-in-fact in connection with such Change in Control on the same terms and to the same extent as such Stockholders’ Representative is appointed by the Company’s stockholders in connection with such Change in Control and (ii) the Participant will execute promptly on request of the Company any documents the Company deems necessary or desirable to provide further assurance of the foregoing appointment.

7.             Securities Laws Restrictions.

(a)           General Restrictions. Notwithstanding any other provision of the Plan or this Agreement, the Company will not be required to issue any shares of Common Stock pursuant to the Award, and the Participant may not sell, assign, transfer or otherwise dispose of shares of Common Stock issued pursuant to the Award: (i) unless there is in effect with respect to such shares a registration statement under the Securities Act and any applicable securities laws of a state or foreign jurisdiction or an exemption from such registration under the Securities Act and applicable state or foreign securities laws; (ii) unless there has been obtained any other consent, approval or permit from any other U.S. or foreign regulatory body which the Committee, in its sole discretion, deems necessary or advisable; and (iii) if at any time at which the Company is not required to file reports with the SEC pursuant to Sections 12(b), 12(g) or 15(d) of the Exchange Act or the rules and regulations thereunder, such issuance, sale or transfer would cause the number of stockholders of the Company to increase such that the Company would be within ten (10) stockholders of the number that would cause the Company to be required to file reports with the SEC pursuant to Sections 12(g) or 15(d) of the Exchange Act and the rules and regulations thereunder. The Company may condition such issuance, sale or transfer upon the receipt of any representations or agreements from the parties involved, and the placement of any legends on certificates representing shares of Common Stock, as may be deemed necessary or advisable by the Company in order to comply with such securities law or other restrictions.

(b)           Market Stand-Off Restrictions. The Participant agrees that, for a 180-day period following the effective date of a registration of the Company’s securities under the Securities Act, and subject to the terms and conditions of Section 11.2 of the Plan, the Participant will not, without the prior written consent of the Company or the representative(s) of any underwriters, (i) sell, pledge, offer to sell, contract to sell (including any short sale), sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase or otherwise transfer or dispose of, directly or indirectly, any shares of Common Stock or any securities convertible into or exercisable or exchangeable for Common Stock (whether such shares or any such securities are then owned by the Participant or are thereafter acquired); or (ii) enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the Common Stock, whether any such transaction described in clause (i) or (ii) above is to be settled by delivery of Common Stock or such other securities, in cash or otherwise.

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8.            Miscellaneous.

(a)           Award Shares Subject to the Plan. This Time Restricted Stock Award Agreement and the shares of Common Stock granted and issued pursuant to this Agreement have been granted and issued under, and are subject to the terms of, the Plan. The terms of the Plan are incorporated by reference in this Agreement in their entirety, and the Participant, by execution of the Time Restricted Stock Award Notice, acknowledges having received a copy of the Plan. The provisions of this Agreement will be interpreted as to be consistent with the Plan, and any ambiguities in this Agreement will be interpreted by reference to the Plan. If any provision of this Agreement is inconsistent with the terms of the Plan, the terms of the Plan will prevail.

(b)           Section 409A. It is intended that payments under this Agreement qualify as short-term deferrals exempt from the requirements of Section 409A of the Code. This Agreement shall be construed and administer to give full effect to such intention

(c)           Binding Effect. This Agreement will be binding upon and inure to the benefit of the successors and permitted assigns of the parties to this Agreement.

(d)           Governing Law and Venue. This Agreement and all rights and obligations under this Agreement will be construed in accordance with the Plan and governed by the laws of the State of New York, without regard to conflicts of laws provisions of any jurisdictions. Any legal proceeding related to this Agreement will be brought in an appropriate New York court, and the parties to this Agreement consent to the exclusive jurisdiction of the court for this purpose.

(e)           Entire Agreement. This Agreement, the Time Restricted Stock Unit Award and Performance-based Restricted Stock Unit Award Notice and the Plan set forth the entire agreement and understanding of the parties to this Agreement with respect to the award of Award Shares and the administration of the Plan and supersede all prior agreements, arrangements, plans and understandings relating to the award of the Award Shares and the administration of the Plan.

(f)           Amendment and Waiver. Other than as provided in the Plan, this Agreement may be amended, waived, modified or canceled only by a written instrument executed by the parties to this Agreement or, in the case of a waiver, by the party waiving compliance.

(g)           Construction. Wherever possible, each provision of this Agreement will be interpreted so that it is valid under the applicable law. If any provision of this Agreement is to any extent invalid under the applicable law, such provision will still be effective to the extent it remains valid. The remainder of this Agreement also will continue to be valid, and the entire Agreement will continue to be valid in other jurisdictions.

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EXHIBIT A

PRSU KPIs

Performance Period. The following PRSU KPIs are based on the performance period beginning on January 1, 2021 and ending on the earlier of December 31, 2023, the date of an IPO, or the date of a Change in Control.

  

PRSU KPIs	Minimum Threshold			Target Threshold			Maximum Threshold			Weighting
Total Shareholder Return (TSR)		[***]			[***]			[***]			60	%
Return on Capital Employed (ROCE)		[***]			[***]			[***]			20	%
IPO Readiness		[***]			[***]			[***]			20	%
Payout Percentage		0	%		100	%		200	%

Total Shareholder Return (TSR)

Total Shareholder Return or “TSR”is defined as the Fair Market Value of the Fully Diluted Shares [defined?] outstanding (in dollars per share) divided by the Base Price less any common dividends paid per share incorporating the timing on when such dividend payments are paid on a daily basis to accurately estimate the time weighted rate of return, stated in a percent. TSR is expressed as the following formula:

TSR = [(Fair Market Value per fully diluted common share) ÷ (Base Price less cumulative dividends paid per share (time weighted))] ^ (1/Years) less 100%

(i)            Public Company Basis. If the company has successfully completed an IPO then the TSR calculation will incorporate the IPO Average Trading Price as the basis for determining the Fair Market Value of the company. In the event of a reverse merger to go public, the Company would utilize the average trading price of the common stock of the reverse merged company over the 30 trading days following the reverse merger as the basis for Fair Market Value.

(ii)            Private Company Basis. If the company has not successfully completed an IPO, and there is no imminent plans to IPO, then on the third anniversary of the Plan Effective Date, the Fair Market Value would be determined according to Section 2.19 for utilization in the TSR calculation.

The TSR shall be expressed as the following formula in the event of a reverse merger:

TSR=[Implied BKV Shareholders Equity Value* per Share** on a fully diluted common stock price) ÷ (common stock par value less cumulative dividends paid per share)] ^(1/Years O/S) less 100%

*“Implied BKV Shareholders Equity Value” means the average market value that the existing (pre-merger) shareholders of the Company own, based on the average 30 day closing price of the combined company’s stock, as measured 30 trading days immediately preceding the effective transaction date of the reverse merger.

** “Share” means the number of Fully Diluted Shares outstanding for BKV shareholders, prior to the reverse merger transaction effective date.

For purposes of determining TSR, “Fully Diluted Shares” means the total number of shares of Common Stock that are outstanding and available to trade on the open market after all sources of conversion are exercised or occur, including, without limitation, any stock options, convertible bonds, vested TRSUs and vested PRSUs.

Average Return on Capital Employed (ROCE).

The Return on Capital Employed or “ROCE” is defined as the Earnings Before Interest and Tax (“EBIT”) as calculated on US GAAP basis, divided by Total Assets less Current Liabilities (including the current portion of debt). ROCE is expressed as the following formula:

ROCE = Average (EBIT / Capital Employed) over the performance period, where:

● EBIT = Earnings Before Interests & Tax (U.S. GAAP)

● Capital Employed = Total Assets – Current Liabilities including Assumed Current Portion of Debt (U.S. GAAP)

IPO Readiness.

IPO Readiness means the overall assessment of the Company’s readiness to successfully complete an IPO, as determined by a reputable third-party consultant evaluating all aspects of the Company’s capability to be publicly listed and (“Yes” or “No”) and the date at which the Company is ready (based on when the assessment was conducted).

EX-10.10

Exhibit 10.10

Time Restricted Stock Unit Award

BKV CORPORATION

TIME RESTRICTED STOCK UNIT AWARD NOTICE

2021 EQUITY INCENTIVE PLAN

BKV Corporation, a Delaware corporation (the “Company”), pursuant to its 2021 Equity Incentive Plan (the “Plan”), hereby grants to the Participant a Time Restricted Stock Unit award of the number of Time Restricted Stock Units (as defined in the Plan), set forth below (the “Time Restricted Stock Units” or “TRSUs”). The Time Restricted Stock Units are subject to all of the terms and conditions as set forth in this Time Restricted Stock Unit Award Notice (the “Award Notice”) and in the Time Restricted Stock Unit Award Agreement and the Plan, both of which are attached hereto and incorporated herein in their entirety.

Participant:	[     ]
Date of Grant:	[     ]
Number of Time Restricted Stock Units:	[     ]
Vesting Schedule:	[     ] TRSUs vest on the Date of Grant; thereafter [     ] TRSUs vest on the second and third anniversary of the Date of Grant and all remaining TRSUs vest on the fourth anniversary of the Date of Grant; provided that the Participant’s Service has continued from the Date of Grant through each such date.

The undersigned Participant acknowledges that he or she has received a copy of this Time Restricted Stock Award Notice, the Time Restricted Stock Award Agreement and the Plan. As an express condition to the grant of the Award hereunder, the Participant agrees to be bound by the terms of this Time Restricted Stock Award Notice, the Time Restricted Stock Award Agreement and the Plan. The undersigned Participant further acknowledges that as of the Date of Grant, this Time Restricted Stock Award Notice, the Time Restricted Stock Award Agreement and the Plan set forth the entire understanding between the Participant and the Company regarding the award of stock in the Company and supersede all prior oral and written agreements on that subject with the exception of (i) awards previously granted and delivered to the Participant by the Company, and (ii) any agreements noted in an attachment to this Time Restricted Stock Award Notice.

BKV CORPORATION:	PARTICIPANT:
By:
Name:	Date:
Title:	Address:
Date:

TIME RESTRICTED STOCK UNIT AWARD AGREEMENT

UNDER THE

BKV CORPORATION 2021 EQUITY INCENTIVE PLAN

Pursuant to the Time Restricted Stock Unite Award Notice (the “Award Notice”), and subject to the terms of this Time Restricted Stock Unit Award Agreement (this “Agreement”) and the BKV Corporation 2021 Equity Incentive Plan (the “Plan”), BKV Corporation, a Delaware corporation (the “Company”), and the Participant agree as follows. Capitalized terms not otherwise defined in this Agreement or in the Award Notice will have the same meanings as set forth in the Plan.

1.            Award of Time Restricted Stock Units. Subject to the terms and conditions set forth herein and in the Plan, the Company hereby grants to the Participant Time Restricted Stock Units, as set forth in the Award Notice, subject to adjustment as provide in the Plan, and each of which, if vested and earned pursuant to this Agreement, will be settled in one (1) share of the Company’s common stock, $0.01 par value per share, (“Common Stock”), at the time and subject to the terms, conditions and restrictions set forth in this Agreement and the Plan (the “Award Shares”).

2.            Vesting.

(a)            Vesting Schedule; Accelerated Vesting. Except as otherwise provided in this Section 2 or the Plan, the Time Restricted Stock Units will vest in the amounts and on the date(s) as indicated in the Vesting Schedule set forth in the Award Notice (each a “TRSU Vesting Date”), provided the Participant remains in the Service of the Company or Subsidiary through the applicable TRSU Vesting Date. In addition, all non-vested Time Restricted Stock Units that have not been forfeited shall vest upon an initial public offering of the Company’s shares of Common Stock or a Change in Control of the Company, provided the Participant remains in the Service of the Company or a Subsidiary through such date. Subject to the limitations contained herein and in the Plan, upon Participant’s termination of Service from the Company and all Subsidiaries the Time Restricted Stock Units that have not vested as of the date of such termination shall be forfeited and terminate; provided, however, that upon a Participant’s termination of Service, the Committee may, in its sole discretion cause any Time Restricted Stock Units then held by such Participant to terminate, vest or become free of restrictions and conditions to payment, in each case in the manner determined by the Committee; provided, further, that any such action adversely affecting any outstanding Incentive Award may not be effective without the consent of the affected Participant (subject to the right of the Committee to take whatever action it deems appropriate under Sections 3.2(c), 7.3 and 9 of the Plan).

(b)            Forfeiture Events. If the Participant is determined by the Committee, acting in its sole discretion, to have taken any action that would constitute Cause or an Adverse Action, irrespective of whether such action or the Committee’s determination occurs before or after termination of the Participant’s Service and irrespective of whether or not the Participant was terminated for Cause: (i) all rights of the Participant under this Agreement and the Plan will terminate and be forfeited without notice of any kind; and (ii) the Committee, in its sole discretion, may require the Participant to surrender and return to the Company all or any shares of Common Stock received, or to disgorge all or any profits or any other economic value (however defined by the Committee) made or realized by the Participant, during the period beginning one year prior to the Participant’s termination of Service in connection with the Award Shares.

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(c)            Adjustment by Board. Notwithstanding anything herein to the contrary, the Board has reserved the right to reduce the amount of the settlement of a vested TRSU by up to 20% of the vested amount.

3.            Settlement; Issuance of Common Stock.

(a)            Timing and Manner of Settlement. Immediately following the vesting of Time Restricted Stock Units under Section 2, such vested Time Restricted Stock Units will be converted to shares of Common Stock which the Company will issue and deliver to the Participant (either by delivering one or more certificates for such shares or by entering such shares in book entry form in the name of the Participant or depositing such shares for the Participant’s benefit with any broker with which the Participant has an account relationship or the Company has engaged to provide such services under the Plan) within sixty (60) days following the TRSU Vesting Date, except to the extent that shares of Common Stock are withheld to pay tax withholding obligations pursuant to Section 2(b) of this Agreement.

(b)            Withholding Taxes. Whenever any Time Restricted Stock Units granted under the terms of this Agreement vest and shares of Common Stock are issued in settlement thereof, the Participant is responsible to provide to the Company when due, the amount necessary for the Company to satisfy all of its federal, state and local withholding (including FICA) tax requirements relating to such taxable event. The Committee may, in its sole discretion and upon terms and conditions established by the Committee, permit or require the Participant to satisfy these withholding tax obligations in connection with the settlement of the Time Restricted Stock Units by withholding shares of Common Stock issuable upon settlement of the Time Restricted Stock Units. When withholding shares of Common Stock for taxes is effected under this Agreement and the Plan, it will be withheld only up to the amount the Company reasonably determines is necessary to satisfy any tax withholding obligation in the Participant’s applicable tax jurisdiction.

4.            Rights of Participant; Transferability.

(a)            No Right to Continued Employment. Nothing in the Plan or in this Agreement confers upon the Participant any right to continue in the Service of the Company or any Subsidiary or interferes with or limits in any way the right of the Company or any Subsidiary to terminate the Service of the Participant at any time, with or without notice and with or without cause.

(b)            Rights as a Stockholder. Except as otherwise provided in the Plan, notwithstanding any restrictions to which Time Restricted Stock Units may be subject, a Participant will have all voting, dividend, liquidation and other rights with respect to shares of Common Stock issued in settlement of earned Time Restricted Stock Units only upon the Participant becoming the holder of record of such shares as if such Participant were a holder of record of such shares.

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(c)            Dividends. The Participant will not receive any cash dividends or Dividend Equivalents based on the dividends declared on the Common Stock underlying the Time Restricted Stock Units during the period between the Grant Date and the date the earned Time Restricted Stock Units are settled in shares of Common Stock.

(d)            Non-Transferability. Except as otherwise expressly permitted by the Plan, unless approved by the Committee in its sole discretion, no right or interest of the Participant in the Award Shares prior to the vesting of an Award and issuance of the Award Shares, will be assignable or transferable, or subjected to any lien, during the lifetime of the Participant, either voluntarily or involuntarily, directly or indirectly, by operation of law or otherwise.

5.            Purchase and Sale Rights Relating to Common Stock.

(a)            Restriction on Transfer of Common Stock. Prior to an initial public offering of shares of Common Stock, a Participant (or the executor, administrator or other personal representative or other successor of a deceased Participant) may not sell, assign, transfer or otherwise dispose of Award Shares acquired pursuant to an Incentive Award to a third party without prior approval of such sale, assignment, transfer or disposition by the Committee or the Board. A Participant may transfer, for no value, vested Award Shares to a trust established by the Participant for estate planning purposes and controlled by the Participant.

(b)            Repurchase Right. If a Participant is not a Founding Stockholder and the Participant either (A) commits any material breach of such Participant’s employment agreement or service contract with the Company and either (1) that breach is not capable of being remedied or (2) if capable of remedy, the Participant does not remedy that breach as soon as possible and in any event within thirty (30) days of receiving a notice from the Company requiring the Participant to remedy that breach, or (B) the Participant’s employment with the Company is terminated for any reason, including due to death or disability, the Company shall have the right, as determined by the Board, to repurchase all (and not less than all) of the vested shares of Common Stock acquired by the Participant under this Plan, in accordance with the terms of this Section 5(b):

(i)             The selling price of the vested shares of Common Stock purchased by the Company pursuant to this Section 5(b) shall be equal to the Fair Market Value of such shares at the time of the repurchase.

(ii)            The Company may exercise its election to acquire the Participant’s vested shares of Common Stock by delivery of ninety (90) days’ written notice to the Participant (or the Participant’s beneficiary in the event of the Participant’s death).

(iii)           The closing of the purchase of the vested shares of Common Stock pursuant to this Section 5(b) shall take place at the principal office of the Company not later than thirty (30) days following receipt of such notice by the Participant (or the Participant’s beneficiary in the event of the Participant’s death).

(iv)           The Participant (or the Participant’s beneficiary in the event of the Participant’s death) shall make such customary representations and warranties as may be reasonably requested by the Company regarding such seller’s good title to, and the absence of liens on, such vested shares of Common Stock.

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(v)            The Company will pay the purchase price for the vested shares of Common Stock purchased by the Company under this Section 5(b) in cash, payable by wire transfer of immediately available funds to the bank account provided to the Company by the Participant (or the Participant’s beneficiary in the event of the Participant’s death)

(c)            Put Right. In the event (A) the Participant’s employment with the Company is terminated for any reason, including due to death or disability (but excluding by voluntary resignation by the Participant) or (B) the Participant’s employment with the Company is terminated by virtue of the Participant’s voluntary resignation after more than thirty-six (36) months have passed from the date of the first grant of an Incentive Award under the Plan to the Participant, and, in each case, the Company has not exercised its right under Section 5(b) to repurchase the Participant’s shares of Common Stock the Participant (or the Participant’s beneficiary in the event of death) shall have the right to elect to sell to the Company, and the Company shall be required to purchase from the Participant, all (and not less than all) of the vested Award Shares acquired by the Participant under the Plan, in accordance with the terms of this Section 5(c):

(i)             The selling price of the vested Award Shares purchased by the Company pursuant to this Section 5(c) shall be equal to the Fair Market Value of such shares at the time of the election to sell.

(ii)            The Participant (or the Participant’s beneficiary in the event of the Participant’s death) may exercise an election to sell vested Award Shares by delivery of thirty (30) days’ written notice specifying the number of vested Award shares to be sold.

(iii)           The closing of the purchase of vested Award Shares of Common Stock pursuant to this Section 5(c) shall take place to the principal office of the Company not later than thirty (30) days following receipt of such notice by the Company.

(iv)          The Participant (or the Participant’s beneficiary in the event of the Participant’s death) shall make such customary representations and warranties as may be reasonably requested by the Company regarding such seller’s good title to, and the absence of liens on, such vested Award Shares.

(v)           The Company will pay the purchase price for the vested Award Shares purchased by the Company under this Section 5(c) in cash, payable by wire transfer of immediately available funds to the bank account provided to the Company by the Participant (or the Participant’s beneficiary in the event of the Participant’s death).

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(d)            Drag-Along Rights. If at any time BNAC (alone or together with any of the other Company stockholders) proposes to effect the sale of shares of Common Stock representing more than eighty percent (80%) of the total issued and outstanding shares of Common Stock, BNAC may require the participation of all (and not less than all) of the shares of Common Stock owned by the Participant in such sale in the manner set forth in this Section 5(d).

(i)            BNAC shall exercise its rights pursuant to this Section 5(d) by delivering to the Company and each of the other Company stockholders a written notice (the “Drag-along Notice”) of such proposed sale no later than fifteen (15) days prior to the proposed closing thereof. Any Drag-along Notice shall make reference to the Participants’ obligations under this Section 5(d) and shall describe in reasonable detail:

(A)            the number of shares of Common Stock to be sold by BNAC;

(B)            the person to whom such shares of Common Stock are proposed to be sold;

(C)            the material terms and conditions of the sale, including the consideration to be paid; and

(D)            the proposed date, time and location of the closing of the sale.

(ii)            In any sale is subject to this Section 5(d), each of the Participants shall agree to sell all (and not less than all) of the shares of Common Stock owned by the Participant, free and clear of any liens and on the same terms and conditions as BNAC in such sale.

(iii)           If BNAC (alone or together with any of the other Company stockholders) proposes to effect the sale of shares of Common Stock representing more than eighty percent (80%) of the total issued and outstanding shares of the Company’s Common Stock pursuant to this Section 5(d), the Participants shall agree to consent to and not object to or exercise any appraisal or dissenters’ rights in connection with such transaction. Without limiting the foregoing, each of the Participants will agree, if requested by BNAC, to execute and deliver a power of attorney and custody agreement, in form and substance satisfactory to BNAC, with respect to the shares of Common Stock that are to be included by them in any sale pursuant to this Section 5(d). The power of attorney and custody agreement will provide, among other things, that each such Participant will:

(A)            deliver to and deposit into custody with BNAC, named as the custodian therein, a certificate or certificates representing such shares of Common Stock (duly endorsed in blank by the owner or owners thereof or accompanied by duly endorsed stock powers in blank); and

(B)            irrevocably appoint BNAC as such stockholder’s agent and attorney-in-fact with full power to act thereunder on behalf of such stockholder with respect to the matters specified therein.

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(iv)          Each Participant shall fully cooperate with BNAC and shall take all necessary actions to effectuate the sale of shares of Common Stock pursuant to this Section 5(d), including entering into such agreements and delivering such certificates and instruments, as may be reasonably requested from time to time by BNAC, provided that no Participant shall be:

(A)            liable for any indemnification obligations to any potential purchaser in respect of such representations and warranties on a joint, rather than several, basis, and in no event with respect to an amount in excess of the net cash proceeds to be paid to such stockholder in such transaction; and

(B)            subject to any escrow or similar arrangement relating to such transaction with respect to an amount in excess of the net cash proceeds to be paid to such other stockholders in such transaction.

(v)            Each of the Participants participating in the sale of shares of Common Stock by BNAC under this Section 5(d) shall be paid a consideration (on a per share of Common Stock basis) on the same terms and conditions as BNAC in such sale.

(e)            Holding Period.

(i)            The Participant (or beneficiary following the Participant’s death) who receives shares of the Company’s Common Stock in settlement of a vested TRSU may not exercise the right to put such shares of Common Stock to the Company for repurchase under Section 5(c) of this Agreement or tender such shares of Common Stock to the Company for purchase under Section 5(f) of this Agreement prior to the date that is 181 days following the applicable TRSU Vesting Date.

(ii)            The Company’s right to repurchase shares of the Company’s Common Stock under Section 5(b) of this Agreement may not be exercised by the Company prior to the date that is 181 days following the applicable TRSU Vesting Date.

(f)            Sell Fund Repurchase Program. The Participant (or beneficiary following the Participant’s death) who receives shares of the Company’s Common Stock in settlement of a vested TRSU, shall have the right, subject to the holding requirement of Section 5(e) of this Agreement, to tender such shares for repurchase by the Company in accordance with and subject to the limits and other requirements established under the Company’s Sell Fund Repurchase Program, as in effect from time to time.

6.            Change in Control.

(a)            Acceleration; Alternative Treatment. If a Change in Control of the Company occurs, then, except to the extent that an equivalent or substituted Award is provided to the Participant to replace the Award pursuant to Section 9.2(b) of the Plan, or unless otherwise provided by the Committee in its sole discretion at any time on or after the Date of Grant, the Award Shares will vest immediately and become non-forfeitable, regardless of whether the Participant remains in the employ or service of the Company or any Subsidiary or any acquiring entity or successor to the Company. In connection with a Change in Control, the Committee in its sole discretion, in lieu of providing an equivalent or substituted Award to the Participant, may determine that all or any portion of the Award and corresponding Award Shares, whether or not vested, will be terminated and forfeited and that in connection with such termination the Participant will receive for each Award Share a cash payment (or the delivery of shares of stock, other securities or a combination of cash, stock and securities with a fair market value (as determined by the Committee in good faith) equivalent to such cash payment) equal to the difference, if any, between the consideration received by stockholders of the Company in respect of a share of Common Stock in connection with such Change in Control and the purchase price per share, if any, under the Award, multiplied by the number of Award Shares subject to the grant; provided, however, that if such product is zero ($0) or less, the Award may be canceled and terminated without payment therefor.

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(b)            Stockholders’ Representative. In connection with any Change in Control, the Participant agrees that (i) any Stockholders’ Representative appointed by the Company’s stockholders in connection with such Change in Control shall, without any further authorization or other action by the Participant, be appointed as such Participant’s representative and attorney-in-fact in connection with such Change in Control on the same terms and to the same extent as such Stockholders’ Representative is appointed by the Company’s stockholders in connection with such Change in Control and (ii) the Participant will execute promptly on request of the Company any documents the Company deems necessary or desirable to provide further assurance of the foregoing appointment.

7.            Securities Laws Restrictions.

(a)            General Restrictions. Notwithstanding any other provision of the Plan or this Agreement, the Company will not be required to issue any shares of Common Stock pursuant to the Award, and the Participant may not sell, assign, transfer or otherwise dispose of shares of Common Stock issued pursuant to the Award: (i) unless there is in effect with respect to such shares a registration statement under the Securities Act and any applicable securities laws of a state or foreign jurisdiction or an exemption from such registration under the Securities Act and applicable state or foreign securities laws; (ii) unless there has been obtained any other consent, approval or permit from any other U.S. or foreign regulatory body which the Committee, in its sole discretion, deems necessary or advisable; and (iii) if at any time at which the Company is not required to file reports with the SEC pursuant to Sections 12(b), 12(g) or 15(d) of the Exchange Act or the rules and regulations thereunder, such issuance, sale or transfer would cause the number of stockholders of the Company to increase such that the Company would be within ten (10) stockholders of the number that would cause the Company to be required to file reports with the SEC pursuant to Sections 12(g) or 15(d) of the Exchange Act and the rules and regulations thereunder. The Company may condition such issuance, sale or transfer upon the receipt of any representations or agreements from the parties involved, and the placement of any legends on certificates representing shares of Common Stock, as may be deemed necessary or advisable by the Company in order to comply with such securities law or other restrictions.

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(b)            Market Stand-Off Restrictions. The Participant agrees that, for a 180-day period following the effective date of a registration of the Company’s securities under the Securities Act, and subject to the terms and conditions of Section 11.2 of the Plan, the Participant will not, without the prior written consent of the Company or the representative(s) of any underwriters, (i) sell, pledge, offer to sell, contract to sell (including any short sale), sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase or otherwise transfer or dispose of, directly or indirectly, any shares of Common Stock or any securities convertible into or exercisable or exchangeable for Common Stock (whether such shares or any such securities are then owned by the Participant or are thereafter acquired); or (ii) enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the Common Stock, whether any such transaction described in clause (i) or (ii) above is to be settled by delivery of Common Stock or such other securities, in cash or otherwise.

8.            Miscellaneous.

(a)            Award Shares Subject to the Plan. This Time Restricted Stock Award Agreement and the shares of Common Stock granted and issued pursuant to this Agreement have been granted and issued under, and are subject to the terms of, the Plan. The terms of the Plan are incorporated by reference in this Agreement in their entirety, and the Participant, by execution of the Time Restricted Stock Award Notice, acknowledges having received a copy of the Plan. The provisions of this Agreement will be interpreted as to be consistent with the Plan, and any ambiguities in this Agreement will be interpreted by reference to the Plan. If any provision of this Agreement is inconsistent with the terms of the Plan, the terms of the Plan will prevail.

(b)            Section 409A. It is intended that payments under this Agreement qualify as short-term deferrals exempt from the requirements of Section 409A of the Code. This Agreement shall be construed and administer to give full effect to such intention

(c)            Binding Effect. This Agreement will be binding upon and inure to the benefit of the successors and permitted assigns of the parties to this Agreement.

(d)            Governing Law and Venue. This Agreement and all rights and obligations under this Agreement will be construed in accordance with the Plan and governed by the laws of the State of New York, without regard to conflicts of law provisions of any jurisdiction. Any legal proceeding related to this Agreement will be brought in an appropriate New York court, and the parties to this Agreement consent to the exclusive jurisdiction of the court for this purpose.

(e)            Entire Agreement. This Agreement, the Time Restricted Stock Award Notice and the Plan set forth the entire agreement and understanding of the parties to this Agreement with respect to the award of Award Shares and the administration of the Plan and supersede all prior agreements, arrangements, plans and understandings relating to the award of the Award Shares and the administration of the Plan.

(f)            Amendment and Waiver. Other than as provided in the Plan, this Agreement may be amended, waived, modified or canceled only by a written instrument executed by the parties to this Agreement or, in the case of a waiver, by the party waiving compliance.

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(g)            Construction. Wherever possible, each provision of this Agreement will be interpreted so that it is valid under the applicable law. If any provision of this Agreement is to any extent invalid under the applicable law, such provision will still be effective to the extent it remains valid. The remainder of this Agreement also will continue to be valid, and the entire Agreement will continue to be valid in other jurisdictions.

(h)            Electronic Delivery of Documents. The Company may, in its sole discretion, deliver any documents related to this Agreement by electronic means. The Participant hereby consents to receive all applicable documentation by electronic delivery and to participate in the Plan through an on-line system established and maintained by the Company or a third-party vendor designated by the Company.

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EX-10.11

Exhibit 10.11

BKV CORPORATION
2020 EMPLOYEE STOCK PURCHASE PLAN
(ADOPTED BY THE BOARD OF DIRECTORS ON JULY 16, 2020)

1.            General.

1.1            Purpose of Plan. This BKV Corporation 2020 Employee Stock Purchase Plan (the “Plan”) is intended to provide Eligible Employees of the Company with the opportunity to acquire an ownership interest in the Company through the purchase of shares of Common Stock from the Company.

1.2            Effective Date. The Plan is effective as of July 1, 2020 (the “Effective Date”) and shall be valid until the date of admission to a United States securities exchange of all or any part of the Common Stock capital or depository receipts (or the equivalent) representing common stock of the Company.

1.3            Status of Plan. The Plan is not intended to be a qualified employee stock purchase plan under Section 423 of the Internal Revenue Code of 1986, as amended (the “Code”) and is not intended to be subject to the provisions of the Employee Retirement Income Security Act of 1974 (“ERISA”). The Plan is intended to be exempt from the requirements of Section 409A of the Code and the Plan and any Stock Purchase Agreement granted under the Plan will be construed and administered to give full effect to such intention.

2.            Definitions. Whenever used herein, the following words and phrases shall have the meanings stated below unless a different meaning is plainly required by the context. Terms defined elsewhere in the Plan will have the same meanings throughout the Plan.

2.1            BNAC. “BNAC” means BANPU North America Corporation, a Delaware corporation.

2.2            Board. “Board” means the Board of Directors of the Company.

2.3            Committee. As used in the Plan, “Committee” means the committee administering the Plan, as provided in Section 7.1 of the Plan.

2.4            Common Stock. “Common Stock” means the common stock of the Company, at a par value per share $0.01.

2.5            Company. “Company” means BKV Corporation, a Delaware corporation.

2.6            Eligible Employee. An “Eligible Employee” means any Employee of the Company who (i) has been employed by the Company for at least twelve (12) consecutive months and (ii) is customarily scheduled to work at least forty (40) hours per week.

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2.7            Employee. “Employee” means any individual treated as an employee in the records of the Company (including an officer or a Director of the Company who is also treated as an employee in such records). The Committee will determine in good faith and in the exercise of its sole discretion whether an individual has become or has ceased to be an Employee and the effective date of such individual’s employment or termination of employment, as the case may be. For purposes of an individual’s rights, if any, under the terms of the Plan as of the time of the Committee’s determination of whether or not the individual is an Employee, all such determinations by the Committee will be final, binding and conclusive as to such rights, if any, notwithstanding that the Company or any court of law or governmental agency subsequently makes a contrary determination as to such individual’s status as an Employee.

2.8            Exchange Act. “Exchange Act” means the Securities Exchange Act of 1934, as amended. Any reference to a section of the Exchange Act in the Plan will be deemed to include a reference to any applicable rules and regulations issued thereunder.

2.9            Fair Market Value. “Fair Market Value” means, with respect to the Common Stock, as of any date: (a) the closing sale price of the Common Stock as of such date at the end of the regular trading session, as reported on any national securities exchange on which the Common Stock is then listed (or, if no shares were traded on such date, as of the next preceding date on which there was such a trade); or (b) if the Common Stock is not so listed as described in (a) above, such price as the Committee determines in good faith to be the fair market value, on a per share of Common Stock basis, at which a willing seller would sell, and a willing buyer would buy, the Common Stock having full knowledge of all relevant facts, in an arm’s length transaction, without taking into account the minority ownership interest of any shares of Common Stock and the rights associated with any minority ownership interest. The Fair Market Value of the shares of Common Stock as described in (b) above shall be determined each Financial Year by the Committee using the independent and impartial valuation of the Company’s Common Stock performed at least annually by Guggenheim Securities, LLC (or by another independent and impartial valuation firm selected by the Committee and subject to the approval of the Board). Such Fair Market Value shall apply during the Financial Year in which it is obtained or until a new valuation is performed for the Committee’s determination of the Fair Market Value. For the avoidance of doubt, during the period as from the adopted date hereof that the Company does not have a Fair Market Value determination as described in subpart (b) above, the Fair Market Value shall be $10.00 per share of Common Stock and will apply until the valuation is performed for the Committee’s first determination of the Fair Market Value.

2.10            Financial Year. “Financial Year” means a financial year of the Company.

2.11            Insolvency Event. “Insolvency Event” means, in relation to a Participant, (i) the Participant entering into or resolving to enter into any assignment for the benefit of creditor, including any arrangement, composition or compromise with such creditor, or any class of them in any relevant jurisdiction, (ii) the Participant being unable to pay its debts when they are due, having its liabilities greater than its assets, or being deemed under any statutory provision of any relevant jurisdiction to be insolvent, or (iii) a liquidator or provisional liquidator being appointed for the Participant or a receiver, receiver and manager, trustee or similar official being appointed over any of the assets or undertakings of the Participant, or an event analogous with any such event occurring in any relevant jurisdiction.

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2.12            Founding Stockholder. “Founding Stockholder” means a Participant who is a party to the Stockholders’ Agreement.

2.13            Participant. “Participant” means each Eligible Employee who participates in this Plan by execution of a Stock Purchase Agreement issued to such Employee under the Plan.

2.14            Plan. “Plan” means the BKV Corporation 2020 Employee Stock Purchase Plan, as set forth herein and may hereafter be amended.

2.15            Securities Act. “Securities Act” means the Securities Act of 1933, as amended. Any reference to a section of the Securities Act in the Plan will be deemed to include a reference to any applicable rules and regulations thereunder.

2.16            Stockholders’ Agreement. “Stockholders’ Agreement” means that certain Stockholders’ Agreement dated May 1, 2020 by and among BNAC, the Company and the Founding Stockholders as listed therein as parties thereto.

2.17            Stock Purchase Account. “Stock Purchase Account” means a non-interest bearing account consisting of all amounts deposited by a Participant Compensation for the purpose of purchasing shares of Common Stock for such Participant under the Plan reduced by all amounts applied to the purchase of shares of Common Stock for such Participant under the Plan. The amounts received from a Participant shall be deposited with the general funds of the Company. No interest shall be paid or payable with respect to any amount held in any Participant's Stock Purchase Account.

2.18            Stock Purchase Agreement. “Stock Purchase Agreement” means a written or electronic agreement between the Company and a Participant setting forth the terms, conditions and restrictions of the offer to purchase shares of Common Stock granted to the Participant under the Plan.

3.            Participation.

Participants in the Plan will be those Eligible Employees who, in the judgment of the CEO of the Company, have contributed, are contributing or are expected to contribute to the achievement of economic objectives of the Company and are not in material breach of their respective employment agreements or service contracts with the Company or the work rules or internal policies of the Company established by the Board from time to time. Eligible Employees may be granted from time to time the right to purchase shares of Common Stock under the Plan, as may be determined by the CEO of the Company in his sole discretion.

4.            Stock Purchase.

4.1            Reservation of Shares. There shall be 7,470,588 shares of Common Stock reserved for the Plan. Subject to adjustment in accordance with the anti-dilution provisions of Section 5, the aggregate number of shares that may be purchased under the Plan shall not exceed the number of shares reserved for the Plan. The shares will be treasury or newly issued shares of Common Stock.

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4.2            Grant of Purchase Right. An Eligible Employee who the CEO of the Company determines has satisfied the requirements set forth in Section 3 may be granted the right to purchase shares of Common Stock under the Plan, pursuant to the terms of a Stock Purchase Agreement issued by the Company to such Eligible Employee. The Committee shall require the payment by the Participant of a specified purchase price in connection with a grant of the right to purchase shares of Common Stock.

4.3            Purchase Price of Shares. The purchase price at which shares of Common Stock shall be sold to a Participant under the Plan shall not be less than the greater of (i) ten dollars ($10.00) per share of Common Stock or (ii) the Fair Market Value of the shares of Common Stock as determined under Section 2.9.

4.4            Exercise of Purchase Right; Payment for Shares of Common Stock. Subject to any limitations imposed by the Committee or the Plan on the number of shares of Common Stock available for purchase by a Participant, the Company will issue to the Participant, pursuant to the terms of a Stock Purchase Agreement, the number of shares of Common Stock as can be purchased with the amount then standing to the Participant’s credit in the Stock Purchase Account. The purchase price for all shares of Common Stock purchased by a Participant pursuant to a Stock Purchase Agreement shall be paid out of the Participant’s Stock Purchase Account. Any remaining balance standing to the Participant’s credit in the Stock Purchase Account following the closing of a purchase, shall be refunded by the Company to the Participant within thirty (30) days of such closing date. No interest shall be paid on payable with respect to any amount held in the Participant’s Stock Purchase Account.

4.5            Establishment of Stock Purchase Account. Each Participant shall deposit funds with the Company for the purpose of funding such Participant’s Stock Purchase Account.

4.6            Stock Ownership. A Participant will have all voting, dividend, liquidation and other rights with respect to shares of Common Stock upon the Participant becoming the holder of record of such shares of Common Stock on the close of business on the purchase date for such shares.

4.7            Issuance of Certificates to a Participant. As soon as reasonably practicable after each purchase date, the Company will arrange for the delivery to each Participant certificates representing the shares of Common Stock purchased, which certificates may be issued electronically via Carta.

5.            Special Adjustment - Anti-Dilution Provision.

The aggregate number of shares of Common Stock reserved for purchase under the Plan, as hereinabove provided in Section 4.1, and the calculation of the Fair Market Value per share of Common Stock may be appropriately adjusted to reflect any increase or decrease in the number of issued shares of Common Stock resulting from a subdivision or consolidation of shares or other capital adjustment, or the payment of a stock dividend, or other increase or decrease in such shares, if effected without receipt of consideration by the Company. Any such adjustment shall be made by the Committee acting with the prior consent of, and subject to the approval of, the Board of Directors.

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6.            Stock Purchase and Sale Rights.

6.1            Put Right. In the event a Participant’s employment with the Company is terminated for any reason, including, without limitation, due to resignation, death or a disability that renders such Participant incapable of continued employment in his or her current position and the carrying out of the normal duties for that position, as certified by a medical professional, and the Company has not exercised its right under Section 6.2 to repurchase the shares of Common Stock, the Participant (or the Participant’s beneficiary in the event of death) shall have the right to elect to sell to the Company, and the Company shall be required to purchase from the Participant, all (and not less than all) of the shares of Common Stock acquired by the Participant under the Plan, in accordance with the terms of this Section 6.1:

(a)            The selling price of the shares of Common Stock to be purchased by the Company pursuant to this Section 6.1 shall be equal to the Fair Market Value of such shares at the time the election to sell is made.

(b)            The Participant (or the Participant’s beneficiary in the event of the Participant’s death) may exercise an election to sell shares of Common Stock by delivery of prior written notice to the Company no later than thirty (30) days following such termination of employment.

(c)            The closing of the purchase of shares of Common Stock pursuant to this Section 6.1 shall take place to the principal office of the Company not later than thirty (30) days following receipt of such notice by the Company.

(d)            The Participant (or the Participant’s beneficiary in the event of the Participant’s death) shall make such customary representations and warranties as may be reasonably requested by the Company regarding such seller’s due capacity and authority, good legal and beneficial title to, and the absence of liens on, such shares.

(e)            The Company will pay the purchase price for the shares of Common Stock purchased by the Company under this Section 6.1 in cash, payable by wire transfer of immediately available funds to the bank account of the Participant (or the Participant’s beneficiary in the event of the Participant’s death) provided to the Company by the Participant (or the Participant’s beneficiary in the event of the Participant’s death) prior to the closing date.

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6.2            Repurchase Right. If a Participant either (i) commits any material breach under such Participant’s employment agreement or service contract with the Company (or, in case of a Founding Stockholder, commits any material breach under the Stockholders’ Agreement) and either (1) that breach is not capable of being remedied or (2) if capable of remedy, the Participant does not remedy that breach as soon as possible and in any event within thirty (30) days of receiving a notice from the Company requiring the Participant to remedy that breach; or (ii) becomes or is reasonably expected to become, subject to an Insolvency Event; or (iii) the Participant’s employment with the Company is terminated for any reason, including, without limitation, due to resignation, death or a disability that renders such Participant incapable of continued employment in his or her current position and carrying out the normal duties for that position, as certified by a medical professional, the Company shall have the right, as determined by the Board, to repurchase, and the Participant (or the Participant’s beneficiary in the event of the Participant’s death) shall be required to sell to the Company all (and not less than all) of the shares of Common Stock acquired by the Participant under this Plan, in accordance with the terms of this Section 6.2:

(a)            The selling price of the shares of Common Stock to be purchased by the Company pursuant to this Section 6.2 shall be equal to the Fair Market Value of such shares at the time of the repurchase.

(b)            The Company may exercise its election to acquire the Participant’s shares of Common Stock by delivery of prior written notice to the Participant (or the Participant’s beneficiary in the event of the Participant’s death) no later than ninety (90) days following the occurrence of an event described above in the first paragraph of this Section 6.2.

(c)            The closing of the purchase of the shares of Common Stock pursuant to this Section 6.2 shall take place at the principal office of the Company not later than thirty (30) days following receipt of such notice by the Participant (or the Participant’s beneficiary in the event of the Participant’s death).

(d)            The Participant (or the Participant’s beneficiary in the event of the Participant’s death) shall make such customary representations and warranties as may be reasonably requested by the Company regarding such seller’s due capacity and authority, good legal and beneficial title to, and the absence of liens on, such shares of Common Stock.

(e)            The Company will pay the purchase price for the shares of Common Stock purchased by the Company under this Section 6.2 in cash, payable by wire transfer of immediately available funds to the bank account of the Participant (or the Participant’s beneficiary in the event of the Participant’s death) provided to the Company by the Participant (or the Participant’s beneficiary in the event of the Participant’s death) prior to the closing date.

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6.3            Right of First Refusal. In addition to the restrictions on transfer set forth in Sections 8.1 and 8.6, if any Participant (or the Participant’s successor in the event of the Participant’s death) who has received shares of Common Stock under the Plan (the “Selling Participant”) shall, at any time, desire to sell some or all of such shares (the “Offered Shares”) to a third party (the “Third Party”) on price, terms and conditions agreed with such Third Party and receives prior written approval from the Board for such a sale, the Selling Participant shall give written notice of such desire to the Company, which notice shall contain the number of Offered Shares, the agreed price, terms and conditions of the sale and the names and addresses of both the Selling Participant and such Third Party. The Company shall have the right of first refusal for a period of thirty (30) days following the date the Selling Participant gives such written notice to the Company to acquire the Offered Shares, in accordance with the terms of this Section 6.3:

(a)            The selling price, terms and conditions shall be the same as agreed with such Third Party.

(b)            If the Company does not exercise its right of first refusal within the required thirty (30) day period provided above, the Selling Participant shall have the right, at any time following the expiration of such thirty (30) day period, to dispose of the Offered Shares to such Third Party; provided, however, that (i) no disposition shall be made to such Third Party on price, terms and conditions more favorable to the Third Party than those set forth in the written notice delivered by the Selling Participant above, and (ii) if such disposition shall not be made within thirty (30) days following the expiration of such thirty (30) day period to such Third Party on the terms offered to the Company, the Offered Shares shall again be subject to the right of first refusal set forth above.

(c)            The closing pursuant to the exercise of the right of first refusal under this Section 6.3 shall take place shall take place to the principal office of the Company not later than thirty (30) days following receipt of such notice by the Selling Participant of the Company’s exercise of the right of first refusal. At such closing, the Selling Participant shall deliver certificates representing the Offered Shares duly endorsed in blank for transfer, or with stock powers attached duly executed in blank, and the Company shall deliver to the Selling Participant the purchase price for the Offered Shares purchased by the Company under this Section 6.3 in cash, payable by wire transfer of immediately available funds to the bank account of the Selling Participant provided to the Company by the Selling Participant prior to the closing date.

(d)            The Selling Participant shall make such customary representations and warranties as may be reasonably requested by the Company regarding such seller’s due capacity and authority, good legal and beneficial title to, and the absence of liens on, such Offered Shares.

6.4            Drag-Along Rights. If at any time BNAC (alone or together with any of the other Company stockholders) proposes to effect the sale of shares of Common Stock representing more than eighty percent (80%) of the total issued and outstanding shares of Common Stock, BNAC (and BNAC alone) may require the participation of all (and not less than all) of the shares of Common Stock owned by the Participant (other than a Participant who is a Founding Stockholder subject to the drag-along rights under the Stockholders’ Agreement) in such sale in the manner set forth in this Section 6.4.

(a)            BNAC shall exercise its rights pursuant to this Section 6.4 by delivering to the Company and each of the other Company stockholders a written notice (the “Drag-along Notice”) of such proposed sale no later than fifteen (15) days prior to the proposed closing thereof. Any Drag-along Notice shall make reference to the Participants’ obligations under this Section 6.4 and shall describe in reasonable detail:

(i)            the number of shares of Common Stock to be sold by BNAC;

(ii)            the person to whom such shares of Common Stock are proposed to be sold;

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(iii)            the material terms and conditions of the sale, including the consideration to be paid; and

(iv)            the proposed date, time and location of the closing of the sale.

(b)            In any sale is subject to this Section 6.4 each of the Participants shall agree to sell all (and not less than all) of the shares of Common Stock owned by the Participant, free and clear of any liens and on the same terms and conditions as BNAC in such sale.

(c)            If BNAC (alone or together with any of the other Company stockholders) proposes to effect the sale of shares of Common Stock representing more than eighty percent (80%) of the total issued and outstanding shares of the Company’s Common Stock pursuant to this Section 6.4, the Participants shall consent to and not object to or exercise any appraisal or dissenters’ rights in connection with such transaction. Without limiting the foregoing, each of the Participants shall, if requested by BNAC, execute and deliver a power of attorney and custody agreement, in form and substance satisfactory to BNAC, with respect to the shares of Common Stock that are to be included by them in any sale pursuant to this Section 6.4. The power of attorney and custody agreement will provide, among other things, that each such Participant will:

(i)            deliver to and deposit into custody with BNAC, named as the custodian therein, a certificate or certificates representing such shares of Common Stock (duly endorsed in blank by the owner or owners thereof or accompanied by duly endorsed stock powers in blank); and

(ii)            irrevocably appoint BNAC as such stockholder’s agent and attorney-in-fact with full power to act thereunder on behalf of such stockholder with respect to the matters specified therein.

(d)            Each Participant shall fully cooperate with BNAC and shall take all necessary actions to effectuate the sale of shares of Common Stock pursuant to this Section 6.4, including entering into such agreements and delivering such certificates and instruments, as may be reasonably requested from time to time by BNAC, provided that no Participant shall be:

(i)            liable for any indemnification obligations to any potential purchaser in respect of such representations and warranties on a joint, rather than several, basis, and in no event with respect to an amount in excess of the net cash proceeds to be paid to such stockholder in such transaction; and

(ii)            subject to any escrow or similar arrangement relating to such transaction with respect to an amount in excess of the net cash proceeds to be paid to such other stockholders in such transaction.

(e)            Each of the Participants participating in the sale of shares of Common Stock by BNAC under this Section 6.4 shall be paid a consideration (on a per share of Common Stock basis) on the same terms and conditions as BNAC in such sale.

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6.5            Tax Matters. By execution of a Stock Purchase Agreement, the Participant expressly acknowledges and agrees that neither the Company, BNAC nor any of their respective agents, makes any representations on behalf of the Company or BNAC with respect to the tax treatment of any transaction contemplated under Section 6. The Participant (or the Participant’s beneficiary in the event of the Participant’s death) shall be solely responsible for the payment of any and all income, transfer and other taxes, filing and recording fees and similar charges relating to any transaction contemplated under this Section 6.

7.            Plan Administration.

7.1            The Committee. The Plan will be administered by the Compensation Committee established by the Board or by the Board if such Compensation Committee is dissolved. Such a committee, if established, will act by simple majority approval of the members (but may also take action by the written consent of a simple majority of the members of such committee), and any simple majority of the members of such a committee will constitute a quorum.

7.2            Authority of the Committee. The Committee shall have the authority and power to administer the Plan and to make, adopt, construe, and enforce rules and regulations not inconsistent with the provisions of the Plan. In addition, the Committee shall adopt and prescribe the contents of all forms required in connection with the administration of the Plan. To the extent consistent with the applicable corporate law of the Company’s jurisdiction of incorporation, the Committee may delegate to any officers of the Company the duties, power and authority of the Committee under the Plan in accordance with such conditions or limitations as the Committee or Board may establish. The Committee may exercise its duties, power and authority under the Plan in its sole and absolute discretion without the consent of any Participant or other party, unless the Plan specifically provides otherwise. The Committee will not be obligated to treat Participants or Eligible Employees uniformly, and determinations made under the Plan may be made by the Committee selectively among Participants or Eligible Employees, whether or not such Participants and Eligible Employees are similarly situated. Each determination, interpretation or other action made or taken by the Committee pursuant to the provisions of the Plan, including the determination of Eligible Employee or Fair Market Value, will be final, conclusive and binding for all purposes and on all persons, including the Company, the stockholders of the Company, the Participants and their respective heirs, transferees, assigns and other successors-in-interest. No member of the Board or the Committee will be liable for any action or determination made in good faith with respect to the Plan or any Stock Purchase Agreement issued under the Plan, including any determination regarding current Fair Market Values of the shares of Common Stock that is made in good faith.

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8.            Miscellaneous.

8.1            Non-Alienation; Restrictions on Transfer. The right to purchase shares of Common Stock pursuant to a Stock Purchase Agreement issued under the Plan is personal to the Participant, is exercisable only by the Participant during the Participant's lifetime while employed, except as hereinafter set forth, and may not be assigned or otherwise transferred by the Participant. Notwithstanding the foregoing, there shall be delivered to the executor, administrator or other personal representative of a deceased Participant such shares of Common Stock and such residual balance as may remain in the Participant's Stock Purchase Account as of the time the Company becomes aware of the Participant's death, including shares of Common Stock purchased as of that date or prior thereto with moneys deposited in the Participant's Stock Purchase Account. In addition, prior to an initial public offering of shares of Common Stock, a Participant (or the executor, administrator or other personal representative or other successor of a deceased Participant) may not sell, assign, transfer or otherwise dispose of shares of Common Stock issued pursuant to the right to purchase shares of Common Stock granted under the Plan to a third party without prior approval of such sale, assignment, transfer or disposition by the Committee or the Board.

8.2            No Right to Continued Employment. Nothing in the Plan confers upon any Eligible Employee or Participant any right to continue in the employment of the Company or interferes with or limits in any way the right of the Company to terminate the employment of any Eligible Employee or Participant at any time, with or without notice and with or without cause, subject to the terms of such Employee’s employment agreement or service contract, if any.

8.3            Governing Law and Venue. The validity, construction, interpretation, administration and effect of the Plan and any rules, regulations and actions relating to the Plan will be governed by and construed exclusively in accordance with the laws of the State of New York, notwithstanding the conflicts of laws principles thereunder or under any jurisdiction that would cause the application of the laws of any jurisdiction other than the State of New York. Any legal proceeding related to the Plan will be brought in an appropriate New York court, and the parties to any Stock Purchase Agreement consent to the exclusive jurisdiction of the court for this purpose.

8.4            Successors and Assigns. The Plan will be binding upon and inure to the benefit of the successors and permitted assigns of the Company and the Participants.

8.5            Non-Exclusivity of the Plan. Nothing contained in the Plan is intended to modify or rescind any previously approved compensation plans or programs of the Company or create any limitations on the power or authority of the Board to adopt such additional or other compensation arrangements as the Board may deem necessary or desirable.

8.6            Securities Law Restrictions.

(a)            Securities Law Restrictions. Notwithstanding any other provision of the Plan or any Stock Purchase Agreement, the Company will not be required to issue any shares of Common Stock under the Plan, and a Participant may not sell, assign, transfer or otherwise dispose of shares of Common Stock issued pursuant to the right to purchase shares of Common Stock granted under the Plan: (i) unless there is in effect with respect to such shares a registration statement under the Securities Act and any applicable securities laws of a state or foreign jurisdiction or an exemption from such registration under the Securities Act and applicable state or foreign securities laws; (ii) unless there has been obtained any other consent, approval or permit from any other U.S. or foreign regulatory body which the Committee, in its sole discretion, deems necessary or advisable; and (iii) if at any time at which the Company is not required to file reports with the Securities and Exchange Commission (the “SEC”) pursuant to Sections 12(b), 12(g) or 15(d) of the Exchange Act or the rules and regulations thereunder, such issuance, sale or transfer would cause the number of stockholders of the Company to increase such that the Company would be within ten (10) stockholders of the number that would cause the Company to be required to file reports with the SEC pursuant to Sections 12(g) or 15(d) of the Exchange Act and the rules and regulations thereunder. The Company may condition such issuance, sale or transfer upon the receipt of any representations or agreements from the parties involved, and the placement of any legends on certificates representing shares of Common Stock, as may be deemed necessary or advisable by the Company in order to comply with such securities law or other restrictions.

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(b)            “Market Stand-Off” Restrictions. Except as otherwise approved by the Committee, the shares of Common Stock acquired in connection with the grant of the right to purchase shares of Common Stock under the Plan will be restricted following the effective date of a registration of the Company’s securities under the Securities Act, and the holder thereof will not, without the prior written consent of the Company or the representative(s) of any underwriters, (i) sell, pledge, offer to sell, contract to sell (including any short sale), sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase or otherwise transfer or dispose of, directly or indirectly, any shares of Common Stock or any securities convertible into or exercisable or exchangeable for Common Stock (whether such shares or any such securities are then owned by the Participant who exercised such Option or are thereafter acquired); or (ii) enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the Common Stock, whether any such transaction described in clause (i) or (ii) above is to be settled by delivery of Common Stock or such other securities, in cash or otherwise. The provisions of this Section 8.6(b) will not apply (w) unless the executive officers and directors of the Company have agreed to be bound by substantially the same terms and conditions; (x) to public offerings other than the Company’s initial public offering and any public offering made within two (2) years thereafter; (y) to registrations relating solely to securities in connection with employee benefit plans or in connection with mergers, consolidations, reorganizations, or other transactions pursuant Rule 145 under the Securities Act; or (z) to transfers to donees who agree to be similarly bound. The time period for such market stand-off will be determined by the Company and the representative(s) of any underwriters but will in no event exceed one hundred eighty (180) days from the date of the final prospectus with respect to the applicable public offering. The Company may impose stop-transfer instructions during such stand-off period with respect to the shares of Common Stock subject to this restriction if necessary to enforce such restrictions. The underwriters in connection with any such public offering are intended third party beneficiaries of this Section 8.6(b) and will have the right, power and authority to enforce the provisions hereof as though they were a party hereto.

8.7            Plan Amendment, Modification and Termination. The Board may amend, modify, suspend or terminate the Plan or any portion thereof at any time, except that no amendment may accomplish any of the following without the approval of the Corporation's stockholders:

(a)            increase the number of shares reserved for purposes of the Plan; or

(b)            allow any person who is not an Eligible Employee to become a Participant.

8.8            Construction. Wherever possible, each provision of the Plan and any Stock Purchase Agreement will be interpreted so that it is valid under the applicable law. If any provision of the Plan or any Stock Purchase Agreement is to any extent invalid under the applicable law, that provision will still be effective to the extent it remains valid. The remainder of the Plan and the Stock Purchase Agreement also will continue to be valid, and the entire Plan and Stock Purchase Agreement will continue to be valid in other jurisdictions.

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EX-10.12

Exhibit 10.12

FIRST AMENDMENT

TO THE

BKV CORPORATION

2020 EMPLOYEE STOCK PURCHASE PLAN
(ADOPTED BY THE BOARD OF DIRECTORS ON JULY 16, 2020)

This First Amendment (this “Amendment”) to the BKV Corporation 2020 Employee Stock Purchase Plan (the “Plan”) is made by BKV Corporation (the “Company”) this 5^th day of November, 2021.

WHEREAS, the Company wishes, for accounting purposes, to treat the sale of shares of the Company’s Common Stock under the Plan as equity rather than debt, which requires that (i) Participants not be able to exercise their put or tender rights under the Plan for at least 181 days following the date on which such shares were acquired (the “Holding Period”), (ii) the Company may not exercise its right to purchase shares of Common Stock from Participants (and beneficiaries) prior to the end of the Holding Period, and (iii) a fair market value determination made quarterly to the extent necessary to affect transactions during the year; and

WHEREAS, the Company wishes to amend the Plan (i) to impose the requirement that a Participant (or beneficiary following the Participant’s death) may not exercise their right to put or tender for repurchase any shares acquired by such Participant under the Plan prior to the end of the Holding Period, (ii) to require a fair market value determination made quarterly to the extent necessary to affect transactions occurring during the year, and (iii) to prohibit the Company from exercising its right to purchase from the Participant (or beneficiary) shares acquired by such Participant (or beneficiary) prior to the date that is 181 days following the date the Participant became vested in the right to receive a share of the Company’s Common Stock; and

WHEREAS, the Company desires to expand the Plan’s eligibility requirements on a prospective basis to include non-employee directors of the Company’s Board and employees of BANPU North America Corporation so that they may be given the opportunity to purchase Common Stock under the Plan in the same manner as Eligible Employees currently enjoy, subject to approval of the Company’s stockholders as required by Section 8.7 of the Plan.

NOW THEREFORE, the Plan is amended as follows:

Changes to Ensure Equity Treatment for Accounting Purposes

1.            Section 2.9 of the Plan regarding the definition of “Fair Market Value” is amended and restated effective as of the 5^th day of November, 2021 to read as follows:

2.9            Fair Market Value. “ Fair Market Value” means, with respect to the Common Stock, as of any date: (a) the closing sale price of the Common Stock as of such date at the end of the regular trading session, as reported on any national securities exchange on which the Common Stock is then listed (or, if no shares were traded on such date, as of the next preceding date on which there was such a trade); or (b) if the Common Stock is not so listed as described in above, the price, on a per share of the Common Stock basis, at which a willing seller would sell, and a willing buyer would buy, the Common Stock having full knowledge of all relevant facts, in an arm’s length transaction without taking into account the minority ownership interest of any shares of the Common Stock and the rights associated with any minority ownership interest hereunder. For all purposes under this Plan (including as to taxation), the fair market value of the Common Stock as described in (b) above shall be determined quarterly, if needed for transaction occurring during the Financial Year, by the Committee using the independent and impartial valuation of the Common Stock performed, on an annual basis, by Guggenheim Securities, LLC, with interim valuations based on the methodologies established in such annual Guggenheim Securities, LLC valuation prepared by the Company or a third party with valuation expertise. The annual valuation may be performed by an independent and impartial appraiser approved by the Board other than Guggenheim Securities, LLC if its fees are not at competitive market rates (as determined by the Board based upon evidence of fees charged by other United States investment banking firms for the same services).

2. Section 6 of the Plan is amended by adding a new Section 6.6 to read as follows:

6.6            Holding Period.

(a)  A Participant (or beneficiary following the Participant’s death) who acquired shares of the Company’s Common Stock under the Plan may not exercise their right to put such shares of Common Stock to the Company for repurchase under Section 6.1 prior to the date that is 181 days following the date the Participant acquired such shares.

(b)  The Company may not exercise its right to purchase shares of the Company’s Common Stock from a Participant (or beneficiary following the Participant’s death) under Section 6.2 prior to the date that is 181 days following the date the Participant acquired such shares.

Expand Eligibility

3.            Section 2 of the Plan is amended to include a new Section 2.5A Director immediately after the definition of “Company” at Section 2.5:

2.5A Director. “Director” means an Employee or a non-Employee of the Company who serves as a member of the Board.

4.            Section 2 of the Plan is amended to add a new Section 2.6A Eligible Recipients immediately after the definition of “Eligible Employee” at Section 2.6:

2.6A            Eligible Recipients. “Eligible Recipients” mean Eligible Employees and/or Directors who satisfy the conditions set forth in Section 3 herein.

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5. Section 2.6 of the Plan is amended and restated to read as follows:

2.6            Eligible Employee. An “Eligible Employee” means any Employee of the Company or BNAC who (i) has been employed by the Company or BNAC for at least twelve (12) consecutive months and (ii) is customarily scheduled to work at least forty (40) hours per week.

6.            Section 2.7 of the Plan is amended by amending and restating the first sentence of such Section to read as follows:

“Employee means any individual treated as an employee in the records of the Company or BNAC (including an officer or a Director of the Company or BNAC who is also treated as an employee in such records).

7. Section 2.13 of the Plan is amended and restated to read as follows:

2.13            Participant. “Participant” means each Eligible Recipient who participates in this Plan by execution of a Stock Purchase Agreement issued to such individual under the Plan.

8.            Section 3 of the Plan is amended to include the following sentence to the end of such section:

A Director who is not an Employee may be granted from time to time the right to purchase shares of Common Stock under the Plan, as may be determined by the Board in its sole discretion and in accordance with the internal policies or bylaws established by the Board from time to time.

9.            Section 4.2 of the Plan is amended and restated to read as follows:

4.2            Grant of Purchase Right. An Eligible Employee who the CEO of the Company determines has satisfied the requirements set forth in Section 3 may be granted the right to purchase shares of Common Stock under the Plan, pursuant to the terms of a Stock Purchase Agreement issued by the Company to such Eligible Employee. The Committee shall require the payment by the Participant of a specified purchase price in connection with a grant of the right to purchase shares of Common Stock

10.            Section 8.2 of the Plan is amended and restated in its entirety as follows:

8.2            Employment. Nothing in the Plan confers upon any Eligible Recipient or Participant any right to future or continued employment with the Company or infers with or limits in any way the right of the Company to terminate the employment of any Eligible Employee or Participant at any time, with or without notice and with or without cause, subject to the terms of such Employee’s employment agreement or service contract, if any.

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11.            Sections 1.1, 7.2, and 8.7 of the Plan are amended by striking the term “Eligible Employee” or “Eligible Employees” and inserting “Eligible Recipient(s)” in each place such phrase occurs in such sections.

12.            The changes made by the foregoing Items 3 through 11 of this Amendment are conditioned on and subject to approval by the Company’s stockholders as required by Section 8.7 of the Plan.

IN WITNESS WHEREOF, the undersigned, on behalf of BKV Corporation, has executed this First Amendment to the BKV Corporation 2020 Employee Stock Purchase Plan document effective as of the 5^th day of November, 2021.

BKV CORPORATION
By:	/s/ Christopher Pungya Kalnin
	Christopher Pungya Kalnin, CEO

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EX-10.13

Exhibit 10.13

SECOND AMENDMENT

TO THE

BKV CORPORATION

2020 EMPLOYEE STOCK PURCHASE PLAN
(ADOPTED BY THE BOARD OF DIRECTORS ON JULY 16, 2020)

This Second Amendment (this “Amendment”) to the BKV Corporation 2020 Employee Stock Purchase Plan (the “Plan”) is made by BKV Corporation (the “Company”) this 21^st day of April, 2022.

WHEREAS, the Company desires to expand the Plan’s eligibility requirements to include employees of the Company’s affiliates and subsidiaries, subject to approval of the Company’s stockholders as required by Section 8.7 of the Plan; and

WHEREAS, the Company desires to remove a typographical error contained in Section 2.17.

NOW THEREFORE, the Plan is amended effective as of March 17, 2022, as follows:

1. Section 2.5 is amended by adding the following language to the end of such section:

For purposes of Section 2.7 (first sentence), Section 8.2, and Section 8.5, “Company” shall include any affiliate or subsidiary of the Company, as such terms are defined under Section 2.6.

2. Section 2.6 is amended and restated to read as follows:

2.6           Eligible Employee. An “Eligible Employee” means any Employee of the Company, any affiliate or subsidiary of the Company, or BNAC who (i) has been employed by the Company, any affiliate or subsidiary of the Company, or BNAC, for at least twelve (12) consecutive months, and (ii) is customarily scheduled to work at least forty (40) hours per week. For purposes of this section and the Plan, “affiliate of the Company” means a corporation or other entity (including a partnership or a limited liability company) that is engaged in the business of oil and gas exploration and production and is controlled by the Company (where “control” means ownership of more than fifty percent (50%) of the voting equity of any entity), and “subsidiary of the Company” means any corporation or other entity, whether domestic or foreign, that is engaged in the business of oil and gas exploration and production and in which the Company has or obtains, directly or indirectly, an ownership interest of more than fifty percent (50%) by reason of stock ownership or otherwise. For the avoidance of doubt, “affiliate or subsidiary of the Company” specifically includes Kalnin Ventures LLC, BKV Barnett, LLC, BKV Operating, LLC, BKV Chelsea, LLC, and BKV Chaffee Corners, LLC, and specifically excludes BKV-BPP Power, LLC and any business developed by the Company for the purpose of carbon capture, utilization and storage (“CCUS”).

3. Section 2.17 of the Plan is amended by amending and restating the first sentence of such Section to read as follows:

“Stock Purchase Account” means a noninterest-bearing account consisting of all amounts deposited by a Participant for the purpose of purchasing shares of Common Stock for such Participant under the Plan reduced by all amounts applied to the purchase of shares of Common Stock for such Participant under the Plan.

IN WITNESS WHEREOF, the undersigned, on behalf of BKV Corporation, has executed this Second Amendment to the BKV Corporation 2020 Employee Stock Purchase Plan document effective as of the 21^st day of April 2022.

BKV CORPORATION

By:	/s/ Christopher Pungya Kalnin
	Christopher Pungya Kalnin, CEO

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EX-10.14

Exhibit 10.14

FORM OF

BKV Corporation

2022 EQUITY and INCENTIVE Compensation PLAN

1.             Purpose. The purpose of this Plan is to permit award grants to non-employee Directors, officers and other employees of the Company and its Subsidiaries, and certain consultants to the Company and its Subsidiaries, and to provide to such persons incentives and rewards for service and/or performance.

2.             Definitions. As used in this Plan:

(a)           “Appreciation Right” means a right granted pursuant to Section 5 of this Plan.

(b)           “Base Price” means the price to be used as the basis for determining the Spread upon the exercise of an Appreciation Right.

(c)           “Board” means the Board of Directors of the Company.

(d)           “Cash Incentive Award” means a cash award granted pursuant to Section 8 of this Plan.

(e)           “Change in Control” has the meaning set forth in Section 12 of this Plan.

(f)            “Code” means the Internal Revenue Code of 1986, as amended from time to time, and the regulations thereunder, as such law and regulations may be amended from time to time.

(g)           “Committee” means the Compensation Committee of the Board (or its successor(s)), or any other committee of the Board designated by the Board to administer this Plan pursuant to Section 10 of this Plan.

(h)           “Common Shares” means the shares of common stock, par value $0.01 per share, of the Company or any security into which such common shares may be changed by reason of any transaction or event of the type referred to in Section 11 or Section 12 of this Plan.

(i)            “Company” means BKV Corporation, a Delaware corporation, and its successors.

(j)            “Company Voting Securities” means the voting securities of the Company entitled to vote generally in the election of Directors.

(k)           “Date of Grant” means the date provided for by the Committee on which a grant of Option Rights, Appreciation Rights, Performance Shares, Performance Units, Cash Incentive Awards, or other awards contemplated by Section 9 of this Plan, or a grant or sale of Restricted Shares, Restricted Stock Units, or other awards contemplated by Section 9 of this Plan, will become effective (which date will not be earlier than the date on which the Committee takes action with respect thereto).

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(l)            “Director” means a member of the Board.

(m)          “Effective Date” means the date this Plan is approved by the Shareholders.

(n)           “Evidence of Award” means an agreement, certificate, resolution or other type or form of writing or other evidence approved by the Committee that sets forth the terms and conditions of the awards granted under this Plan. An Evidence of Award may be in an electronic medium, may be limited to notation on the books and records of the Company and, unless otherwise determined by the Committee, need not be signed by a representative of the Company or a Participant.

(o)           “Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time, and the rules and regulations thereunder, as such law, rules and regulations may be amended from time to time.

(p)           “Exempt Person” means each of Banpu Public Company Limited, a public company incorporated in and existing under the Laws of Thailand, and any corporation, company or other entity that is wholly-owned by Banpu Public Company Limited, as of the relevant time.

(q)           “Management Objectives” means the measurable performance objective or objectives established pursuant to this Plan for Participants who have received grants of Performance Shares, Performance Units or Cash Incentive Awards or, when so determined by the Committee, Option Rights, Appreciation Rights, Restricted Shares, Restricted Stock Units, dividend equivalents or other awards pursuant to this Plan. If the Committee determines that a change in the business, operations, corporate structure or capital structure of the Company, or the manner in which it conducts its business, or other events or circumstances render the Management Objectives unsuitable, the Committee may in its discretion modify such Management Objectives or the goals or actual levels of achievement regarding the Management Objectives, in whole or in part, as the Committee deems appropriate and equitable.

(r)            “Market Value per Share” means, as of any particular date, the closing price of a Common Share as reported for that date on the New York Stock Exchange or, if the Common Shares are not then listed on the New York Stock Exchange, on any other national securities exchange on which the Common Shares are listed, or if there are no sales on such date, on the next preceding trading day during which a sale occurred. If there is no regular public trading market for the Common Shares, then the Market Value per Share shall be the fair market value as determined in good faith by the Committee. The Committee is authorized to adopt another fair market value pricing method provided such method is stated in the applicable Evidence of Award and is in compliance with the fair market value pricing rules set forth in Section 409A of the Code.

(s)            “Optionee” means the optionee named in an Evidence of Award evidencing an outstanding Option Right.

(t)            “Option Price” means the purchase price payable on exercise of an Option Right.

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(u)           “Option Right” means the right to purchase Common Shares upon exercise of an award granted pursuant to Section 4 of this Plan.

(v)           “Participant” means a person who is selected by the Committee to receive benefits under this Plan and who is at the time (i) a non-employee Director, (ii) an officer or other employee of the Company or any Subsidiary, or (iii) a person, including a consultant, who provides services to the Company or any Subsidiary that are equivalent to those typically provided by an employee (provided that such person satisfies the Form S-8 definition of an “employee”).

(w)           “Performance Period” means, in respect of a Cash Incentive Award, Performance Share or Performance Unit, a period of time established pursuant to Section 8 of this Plan within which the Management Objectives relating to such Cash Incentive Award, Performance Share or Performance Unit are to be achieved.

(x)            “Performance Share” means a bookkeeping entry that records the equivalent of one Common Share awarded pursuant to Section 8 of this Plan.

(y)           “Performance Unit” means a bookkeeping entry awarded pursuant to Section 8 of this Plan that records a unit equivalent to $1.00 or such other value as is determined by the Committee.

(z)            “Plan” means this BKV Corporation 2022 Equity and Incentive Compensation Plan, as may be amended or amended and restated from time to time.

(aa)         “Predecessor Plan” means the BKV Corporation 2021 Long Term Incentive Plan, adopted January 1, 2021, as amended.

(bb)         “Restricted Shares” means Common Shares granted or sold pursuant to Section 6 of this Plan as to which neither the substantial risk of forfeiture nor the prohibition on transfers has expired.

(cc)         “Restricted Stock Units” means an award made pursuant to Section 7 of this Plan of the right to receive Common Shares, cash or a combination thereof at the end of the applicable Restriction Period.

(dd)         “Restriction Period” means the period of time during which Restricted Stock Units are subject to restrictions, as provided in Section 7 of this Plan.

(ee)         “Shareholder” means an individual or entity that owns one or more Common Shares.

(ff)           “Spread” means the excess of the Market Value per Share on the date when an Appreciation Right is exercised over the Base Price provided for with respect to the Appreciation Right.

(gg)         “Subsidiary” means a corporation, company or other entity (i) more than 60% of whose outstanding shares or securities (representing the right to vote for the election of directors or other managing authority) are, or (ii) which does not have outstanding shares or securities (as may be the case in a partnership, joint venture, limited liability company, unincorporated association or other similar entity), but more than 60% of whose ownership interest representing the right generally to make decisions for such other entity is, now or hereafter, owned or controlled, directly or indirectly, by the Company.

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(hh)         “Voting Power” means, at any time, the combined voting power of the then-outstanding securities entitled to vote generally in the election of Directors in the case of the Company or members of the board of directors or similar body in the case of another entity.

3.             Shares Available Under this Plan.

(a) Maximum Shares Available Under this Plan.

(i) Subject to adjustment as provided in Section 11 of this Plan and the share counting rules set forth in Section 3(b) of this Plan, the number of Common Shares available under this Plan for awards of (A) Option Rights or Appreciation Rights, (B) Restricted Shares, (C) Restricted Stock Units, (D) Performance Shares or Performance Units, (E) awards contemplated by Section 9 of this Plan, or (F) dividend equivalents paid with respect to awards made under this Plan will not exceed in the aggregate [                ] Common Shares. Such shares may be shares of original issuance or treasury shares or a combination of the foregoing.

(ii) Subject to the share counting rules set forth in Section 3(b) of this Plan, the aggregate number of Common Shares available under Section 3(a)(i) of this Plan will be reduced by one Common Share for every one Common Share subject to an award granted under this Plan.

(b)             Share Counting Rules.

(i) Except as provided in Section 22 of this Plan, if any award granted under this Plan (in whole or in part) is cancelled or forfeited, expires, is settled for cash, or is unearned, the Common Shares subject to such award will, to the extent of such cancellation, forfeiture, expiration, cash settlement, or unearned amount, again be available under Section 3(a)(i) above.

(ii) Notwithstanding anything to the contrary contained in this Plan: (A) Common Shares withheld by the Company, tendered or otherwise used in payment of the Option Price of an Option Right will not be added (or added back, as applicable) to the aggregate number of Common Shares available under Section 3(a)(i) of this Plan; (B) Common Shares withheld by the Company, tendered or otherwise used to satisfy tax withholding will not be added (or added back, as applicable) to the aggregate number of Common Shares available under Section 3(a)(i) of this Plan; (C) Common Shares subject to a share-settled Appreciation Right that are not actually issued in connection with the settlement of such Appreciation Right on the exercise thereof will not be added (or added back, as applicable) to the aggregate number of Common Shares available under Section 3(a)(i) of this Plan; and (D) Common Shares reacquired by the Company on the open market or otherwise using cash proceeds from the exercise of Option Rights will not be added (or added back, as applicable) to the aggregate number of Common Shares available under Section 3(a)(i) of this Plan.

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(iii) If, under this Plan, a Participant has elected to give up the right to receive compensation in exchange for Common Shares based on fair market value, such Common Shares will not count against the aggregate limit under Section 3(a)(i) of this Plan.

(c)           Non-Employee Director Compensation Limit. Notwithstanding anything to the contrary contained in this Plan, in no event will any non-employee Director in any one calendar year be granted compensation for such service having an aggregate maximum value (measured at the Date of Grant as applicable, and calculating the value of any awards based on the grant date fair value for financial reporting purposes) in excess of $750,000.

4.             Option Rights. The Committee may, from time to time and upon such terms and conditions as it may determine, authorize the granting to Participants of Option Rights. Each such grant may utilize any or all of the authorizations, and will be subject to all of the requirements, contained in the following provisions:

(a)           Each grant will specify the number of Common Shares to which it pertains subject to the limitations set forth in Section 3 of this Plan.

(b)           Each grant will specify an Option Price per Common Share, which Option Price (except with respect to awards under Section 22 of this Plan) may not be less than the Market Value per Share on the Date of Grant.

(c)           Each grant will specify whether the Option Price will be payable (i) in cash, by check acceptable to the Company or by wire transfer of immediately available funds, (ii) by the actual or constructive transfer to the Company of Common Shares owned by the Optionee having a value at the time of exercise equal to the total Option Price, (iii) subject to any conditions or limitations established by the Committee, by the withholding of Common Shares otherwise issuable upon exercise of an Option Right pursuant to a “net exercise” arrangement (it being understood that, solely for purposes of determining the number of treasury shares held by the Company, the Common Shares so withheld will not be treated as issued and acquired by the Company upon such exercise), (iv) by a combination of such methods of payment, or (v) by such other methods as may be approved by the Committee.

(d)           To the extent permitted by law, any grant may provide for deferred payment of the Option Price from the proceeds of sale through a bank or broker on a date satisfactory to the Company of some or all of the Common Shares to which such exercise relates.

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(e)           Each grant will specify the period or periods of continuous service by the Optionee with the Company or any Subsidiary, if any, that is necessary before any Option Rights or installments thereof will vest. Option Rights may provide for continued vesting or the earlier vesting of such Option Rights, including in the event of the retirement, death, disability or termination of employment or service of a Participant or in the event of a Change in Control.

(f)            Any grant of Option Rights may specify Management Objectives regarding the vesting of such rights.

(g)           Option Rights granted under this Plan are not intended to qualify under Section 422 of the Code or any successor provision.

(h)           No Option Right will be exercisable more than 10 years from the Date of Grant. The Committee may provide in any Evidence of Award for the automatic exercise of an Option Right upon such terms and conditions as established by the Committee.

(i)            Option Rights granted under this Plan may not provide for any dividends or dividend equivalents thereon.

(j)            Each grant of Option Rights will be evidenced by an Evidence of Award. Each Evidence of Award will be subject to this Plan and will contain such terms and provisions, consistent with this Plan, as the Committee may approve.

5.             Appreciation Rights.

(a)           The Committee may, from time to time and upon such terms and conditions as it may determine, authorize the granting to any Participant of Appreciation Rights. An Appreciation Right will be the right of the Participant to receive from the Company an amount determined by the Committee, which will be expressed as a percentage of the Spread (not exceeding 100%) at the time of exercise.

(b)           Each grant of Appreciation Rights may utilize any or all of the authorizations, and will be subject to all of the requirements, contained in the following provisions:

(i) Each grant may specify that the amount payable on exercise of an Appreciation Right will be paid by the Company in cash, Common Shares or any combination thereof.

(ii) Each grant will specify the period or periods of continuous service by the Participant with the Company or any Subsidiary, if any, that is necessary before the Appreciation Rights or installments thereof will vest. Appreciation Rights may provide for continued vesting or the earlier vesting of such Appreciation Rights, including in the event of the retirement, death, disability or termination of employment or service of a Participant or in the event of a Change in Control.

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(iii) Any grant of Appreciation Rights may specify Management Objectives regarding the vesting of such Appreciation Rights.

(iv) Appreciation Rights granted under this Plan may not provide for any dividends or dividend equivalents thereon.

(v) Each grant of Appreciation Rights will be evidenced by an Evidence of Award. Each Evidence of Award will be subject to this Plan and will contain such terms and provisions, consistent with this Plan, as the Committee may approve.

(c)             Also, regarding Appreciation Rights:

(i) Each grant will specify in respect of each Appreciation Right a Base Price, which (except with respect to awards under Section 22 of this Plan) may not be less than the Market Value per Share on the Date of Grant; and

(ii) No Appreciation Right granted under this Plan may be exercised more than 10 years from the Date of Grant. The Committee may provide in any Evidence of Award for the automatic exercise of an Appreciation Right upon such terms and conditions as established by the Committee.

6.             Restricted Shares. The Committee may, from time to time and upon such terms and conditions as it may determine, authorize the grant or sale of Restricted Shares to Participants. Each such grant or sale may utilize any or all of the authorizations, and will be subject to all of the requirements, contained in the following provisions:

(a)           Each such grant or sale will constitute an immediate transfer of the ownership of Common Shares to the Participant in consideration of the performance of services, entitling such Participant to voting, dividend and other ownership rights, but subject to the substantial risk of forfeiture and restrictions on transfer hereinafter described.

(b)           Each such grant or sale may be made without additional consideration or in consideration of a payment by such Participant that is less than the Market Value per Share on the Date of Grant.

(c)           Each such grant or sale will provide that the Restricted Shares covered by such grant or sale will be subject to a “substantial risk of forfeiture” within the meaning of Section 83 of the Code for a period to be determined by the Committee on the Date of Grant or until achievement of Management Objectives referred to in Section 6(e) of this Plan.

(d)           Each such grant or sale will provide that during or after the period for which such substantial risk of forfeiture is to continue, the transferability of the Restricted Shares will be prohibited or restricted in the manner and to the extent prescribed by the Committee on the Date of Grant (which restrictions may include rights of repurchase or first refusal of the Company or provisions subjecting the Restricted Shares to a continuing substantial risk of forfeiture while held by any transferee).

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(e)           Any grant of Restricted Shares may specify Management Objectives regarding the vesting of such Restricted Shares.

(f)            Notwithstanding anything to the contrary contained in this Plan, Restricted Shares may provide for continued vesting or the earlier vesting of such Restricted Shares, including in the event of the retirement, death, disability or termination of employment or service of a Participant or in the event of a Change in Control.

(g)           Any such grant or sale of Restricted Shares may require that any and all dividends or other distributions paid thereon during the period of such restrictions be automatically deferred and/or reinvested in additional Restricted Shares, which will be subject to the same restrictions as the underlying award. For the avoidance of doubt, any such dividends or other distributions on Restricted Shares shall be deferred until, and paid contingent upon, the vesting of such Restricted Shares.

(h)           Each grant or sale of Restricted Shares will be evidenced by an Evidence of Award. Each Evidence of Award will be subject to this Plan and will contain such terms and provisions, consistent with this Plan, as the Committee may approve. Unless otherwise directed by the Committee, (i) all certificates representing Restricted Shares will be held in custody by the Company until all restrictions thereon will have lapsed, together with a stock power or powers executed by the Participant in whose name such certificates are registered, endorsed in blank and covering such shares or (ii) all Restricted Shares will be held at the Company’s transfer agent in book entry form with appropriate restrictions relating to the transfer of such Restricted Shares.

7.             Restricted Stock Units. The Committee may, from time to time and upon such terms and conditions as it may determine, authorize the granting or sale of Restricted Stock Units to Participants. Each such grant or sale may utilize any or all of the authorizations, and will be subject to all of the requirements, contained in the following provisions:

(a)           Each such grant or sale will constitute the agreement by the Company to deliver Common Shares or cash, or a combination thereof, to the Participant in the future in consideration of the performance of services, but subject to the fulfillment of such conditions (which may include achievement regarding Management Objectives) during the Restriction Period as the Committee may specify.

(b)           Each such grant or sale may be made without additional consideration or in consideration of a payment by such Participant that is less than the Market Value per Share on the Date of Grant.

(c)           Notwithstanding anything to the contrary contained in this Plan, Restricted Stock Units may provide for continued vesting or the earlier lapse or other modification of the Restriction Period, including in the event of the retirement, death, disability or termination or employment of service of a Participant or in the event of a Change in Control.

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(d)           During the Restriction Period, the Participant will have no right to transfer any rights under his or her award and will have no rights of ownership in the Common Shares deliverable upon payment of the Restricted Stock Units and will have no right to vote them, but the Committee may, at or after the Date of Grant, authorize the payment of dividend equivalents on such Restricted Stock Units on a deferred and contingent basis, either in cash or in additional Common Shares; provided, however, that dividend equivalents or other distributions on Common Shares underlying Restricted Stock Units shall be deferred until and paid contingent upon the vesting of such Restricted Stock Units.

(e)           Each grant or sale of Restricted Stock Units will specify the time and manner of payment of the Restricted Stock Units that have been earned. Each grant or sale will specify that the amount payable with respect thereto will be paid by the Company in Common Shares or cash, or a combination thereof.

(f)            Each grant or sale of Restricted Stock Units will be evidenced by an Evidence of Award. Each Evidence of Award will be subject to this Plan and will contain such terms and provisions, consistent with this Plan, as the Committee may approve.

8.             Cash Incentive Awards, Performance Shares and Performance Units. The Committee may, from time to time and upon such terms and conditions as it may determine, authorize the granting of Cash Incentive Awards, Performance Shares and Performance Units. Each such grant may utilize any or all of the authorizations, and will be subject to all of the requirements, contained in the following provisions:

(a)           Each grant will specify the number or amount of Performance Shares or Performance Units, or amount payable with respect to a Cash Incentive Award, to which it pertains, which number or amount may be subject to adjustment to reflect changes in compensation or other factors.

(b)           The Performance Period with respect to each Cash Incentive Award or grant of Performance Shares or Performance Units will be such period of time as will be determined by the Committee, which may be subject to continued vesting or earlier lapse or other modification, including in the event of the retirement, death, disability or termination of employment or service of a Participant or in the event of a Change in Control.

(c)           Each grant of a Cash Incentive Award, Performance Shares or Performance Units will specify Management Objectives regarding the earning of the award.

(d)           Each grant will specify the time and manner of payment of a Cash Incentive Award, Performance Shares or Performance Units that have been earned.

(e)           The Committee may, on the Date of Grant of Performance Shares or Performance Units, provide for the payment of dividend equivalents to the holder thereof either in cash or in additional Common Shares, which dividend equivalents shall be subject to deferral and payment on a contingent basis based on the Participant’s earning and vesting of the Performance Shares or Performance Units, as applicable, with respect to which such dividend equivalents are paid.

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(f)             Each grant of a Cash Incentive Award, Performance Shares or Performance Units will be evidenced by an Evidence of Award. Each Evidence of Award will be subject to this Plan and will contain such terms and provisions, consistent with this Plan, as the Committee may approve.

9.             Other Awards.

(a)           Subject to applicable law and the applicable limits set forth in Section 3 of this Plan, the Committee may authorize the grant to any Participant of Common Shares or such other awards that may be denominated or payable in, valued in whole or in part by reference to, or otherwise based on, or related to, Common Shares or factors that may influence the value of such shares, including, without limitation, convertible or exchangeable debt securities, other rights convertible or exchangeable into Common Shares, purchase rights for Common Shares, awards with value and payment contingent upon performance of the Company or specified subsidiaries, affiliates or other business units thereof or any other factors designated by the Committee, and awards valued by reference to the book value of the Common Shares or the value of securities of, or the performance of specified subsidiaries or affiliates or other business units of the Company. The Committee will determine the terms and conditions of such awards. Common Shares delivered pursuant to an award in the nature of a purchase right granted under this Section 9 will be purchased for such consideration, paid for at such time, by such methods, and in such forms, including, without limitation, Common Shares, other awards, notes or other property, as the Committee determines.

(b)           Cash awards, as an element of or supplement to any other award granted under this Plan, may also be granted pursuant to this Section 9.

(c)           The Committee may authorize the grant of Common Shares as a bonus, or may authorize the grant of other awards in lieu of obligations of the Company or a Subsidiary to pay cash or deliver other property under this Plan or under other plans or compensatory arrangements, subject to such terms as will be determined by the Committee in a manner that complies with Section 409A of the Code.

(d)           The Committee may, at or after the Date of Grant, authorize the payment of dividends or dividend equivalents on awards granted under this Section 9 on a deferred and contingent basis, either in cash or in additional Common Shares; provided, however, that dividend equivalents or other distributions on Common Shares underlying awards granted under this Section 9 shall be deferred until and paid contingent upon the earning and vesting of such awards.

(e)           Each grant of an award under this Section 9 will be evidenced by an Evidence of Award. Each such Evidence of Award will be subject to this Plan and will contain such terms and provisions, consistent with this Plan, as the Committee may approve, and will specify the time and terms of delivery of the applicable award.

(f)            Notwithstanding anything to the contrary contained in this Plan, awards under this Section 9 may provide for the earning or vesting of, or earlier elimination of restrictions applicable to, such award, including in the event of the retirement, death, disability or termination of employment or service of a Participant or in the event of a Change in Control.

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10.           Administration of this Plan.

(a)           This Plan will be administered by the Committee; provided, that, with respect to awards to non-employee Directors, the Board shall have the same powers and authorities as the Committee and may, in its discretion, exercise such powers in lieu of the Committee.

(b)           The interpretation and construction by the Committee of any provision of this Plan or of any Evidence of Award (or related documents) and any determination by the Committee pursuant to any provision of this Plan or of any such agreement, notification or document will be final and conclusive. No member of the Committee shall be liable for any such action or determination made in good faith. In addition, the Committee is authorized to take any action it determines in its sole discretion to be appropriate subject only to the express limitations contained in this Plan, and no authorization in any Plan section or other provision of this Plan is intended or may be deemed to constitute a limitation on the authority of the Committee.

(c)           To the extent permitted by law, the Committee may delegate to one or more officers of the Company such administrative duties or powers as it may deem advisable, and the Committee or any officer of the Company to whom duties or powers have been delegated as aforesaid, may employ one or more persons to render advice with respect to any responsibility the Committee or such officer may have under this Plan. The Committee may, by resolution, authorize one or more officers of the Company to do one or both of the following on the same basis as the Committee: (i) designate employees to be recipients of awards under this Plan; and (ii) determine the size of any such awards; provided, however, that (A) the Committee will not delegate such responsibilities to any such officer for awards granted to an employee who is an officer (for purposes of Section 16 of the Exchange Act), Director, or more than 10% “beneficial owner” (as such term is defined in Rule 13d-3 promulgated under the Exchange Act) of any class of the Company’s equity securities that is registered pursuant to Section 12 of the Exchange Act, as determined by the Committee in accordance with Section 16 of the Exchange Act; (B) the resolution providing for such authorization shall set forth the total number of Common Shares such officer(s) may grant; and (C) the officer(s) will report periodically to the Committee regarding the nature and scope of the awards granted pursuant to the authority delegated.

11.           Adjustments. The Committee shall make or provide for such adjustments in the number of and kind of Common Shares covered by outstanding Option Rights, Appreciation Rights, Restricted Shares, Restricted Stock Units, Performance Shares and Performance Units granted hereunder and, if applicable, in the number of and kind of Common Shares covered by other awards granted pursuant to Section 9 of this Plan, in the Option Price and Base Price provided in outstanding Option Rights and Appreciation Rights, respectively, in Cash Incentive Awards, and in other award terms, as the Committee, in its sole discretion, exercised in good faith, determines is equitably required to prevent dilution or enlargement of the rights of Participants that otherwise would result from (a) any extraordinary cash dividend, stock dividend, stock split, combination of shares, recapitalization or other change in the capital structure of the Company, (b) any merger, consolidation, spin-off, split-off, spin-out, split-up, reorganization, partial or complete liquidation or other distribution of assets, issuance of rights or warrants to purchase securities, or (c) any other corporate transaction or event having an effect similar to any of the foregoing. Moreover, in the event of any such transaction or event , the Committee may provide in substitution for any or all outstanding awards under this Plan such alternative consideration (including cash), if any, as it, in good faith, may determine to be equitable in the circumstances and shall require in connection therewith the surrender of all awards so replaced in a manner that complies with Section 409A of the Code. In addition, for each Option Right or Appreciation Right with an Option Price or Base Price, respectively, greater than the consideration offered in connection with any such transaction or event, the Committee may in its discretion elect to cancel such Option Right or Appreciation Right without any payment to the person holding such Option Right or Appreciation Right. The Committee shall also make or provide for such adjustments in the number of Common Shares specified in Section 3 of this Plan as the Committee in its sole discretion, exercised in good faith, determines is appropriate to reflect any transaction or event described in this Section 11.

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12.           Change in Control.

(a)           Upon a Change in Control, the Committee, acting in its sole discretion without the consent or approval of any Participant, may (i) provide that an outstanding Award shall be assumed by, or a substitute award shall be granted by the surviving entity resulting from a transaction described in Section 12(b)(iii), (ii) provide for acceleration of the vesting and exercisability of, or lapse of restrictions, in whole or in part, with respect to, an Award and, if the transaction is a cash merger, provide for the termination of any portion of the Award that remains unexercised at the time of such transaction, (iii) cancel an Award in exchange for a cash payment in an amount that the Committee shall determine in its sole discretion is equal to the fair market value of such Award on the date of such event, which in the case of Option Rights or Appreciation Rights shall be the excess of the Market Value of Shares on such date over the Option Price or Base Price, as applicable, of such Award (it being understood that, for each Option Right or Appreciation Right with an Option Price or Base Price, respectively, greater than the consideration offered in connection with the Change in Control, the Committee may in its discretion elect to cancel such Option Right or Appreciation Right without any payment to the person holding such Option Right or Appreciation Right), or (iv) make such adjustments, if any, to the Awards then outstanding as the Committee deems appropriate to reflect such Change in Control. The Committee may effect one or more of such alternatives, which may vary among individual Participants and which may vary among Awards held by any individual Participant:

(b)           For purposes of this Plan, except as may be otherwise prescribed by the Committee in an Evidence of Award made under this Plan, a “Change in Control” will be deemed to have occurred upon the occurrence (after the Effective Date) of any of the following events:

(i) the acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of Company Voting Securities where such acquisition causes such Person to own 40% or more of the combined voting power of the then outstanding Company Voting Securities; provided, however, that for purposes of this subsection (a), the following acquisitions shall not be deemed to result in a Change in Control: (i) any acquisition by the Company or a wholly-owned subsidiary of the Company, (ii) any acquisition directly from the Company that is approved by the Board prior to the transaction, (iii) any acquisition by any Exempt Person or by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (iv) any acquisition by any corporation pursuant to a transaction that complies with clauses (A), (B) and (C) of Section 12(b)(iii) below;

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(ii) the replacement of a majority of the Board over a two–year period of the directors who constituted the Board at the beginning of such period, and such replacement shall not have been approved by a vote of at least a majority of the Board then still in office who either were members of such Board at the beginning of such period or whose election as a member of such Board was previously so approved; provided, that any such person whose initial assumption of office is in connection with an actual or threatened election contest relating to the election of members of the Board or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board, including by reason of agreement intended to avoid or settle any such actual or threatened contest or solicitation, shall not be considered to have been so approved;

(iii) the consummation of a reorganization, merger or consolidation or the sale or other disposition of all or substantially all of the assets of the Company, whether in one or a series of related transactions, (“Business Combination”) excluding, however, such a Business Combination pursuant to which (A) the individuals and entities who were the beneficial owners of the outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors of the entity resulting from such Business Combination in substantially the same proportions as their ownership of the Common Shares and Company Voting Securities immediately prior to such Business Combination (including, without limitation, an entity that as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries), and (ii) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

(iv) approval by the Shareholders of a complete liquidation or dissolution of the Company except pursuant to a Business Combination that complies with clauses (A), (B) and (C) of Section 12(b)(iii) above.

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13.           Detrimental Activity and Recapture Provisions. Any Evidence of Award may reference a clawback policy of the Company or provide for the cancellation or forfeiture of an award or the forfeiture and repayment to the Company of any gain related to an award, or other provisions intended to have a similar effect, upon such terms and conditions as may be determined by the Committee from time to time, if a Participant, either (a) during employment or other service with the Company or a subsidiary, or (b) within a specified period after termination of such employment or service, engages in any detrimental activity, as described in the applicable Evidence of Award or such clawback policy. In addition, notwithstanding anything in this Plan to the contrary, any Evidence of Award or such clawback policy may also provide for the cancellation or forfeiture of an award or the forfeiture and repayment to the Company of any Common Shares issued under and/or any other benefit related to an award, or other provisions intended to have a similar effect, including upon such terms and conditions as may be required by the Committee or under Section 10D of the Exchange Act and any applicable rules or regulations promulgated by the Securities and Exchange Commission or any national securities exchange or national securities association on which the Common Shares may be traded.

14.           Non-U.S. Participants. In order to facilitate the making of any grant or combination of grants under this Plan, the Committee may provide for such special terms for awards to Participants who are foreign nationals or who are employed by the Company or any Subsidiary outside of the United States of America or who provide services to the Company or any Subsidiary under an agreement with a foreign nation or agency, as the Committee may consider necessary or appropriate to accommodate differences in local law, tax policy or custom. Moreover, the Committee may approve such supplements to or amendments, restatements or alternative versions of this Plan (including sub-plans) as it may consider necessary or appropriate for such purposes, without thereby affecting the terms of this Plan as in effect for any other purpose, and the secretary or other appropriate officer of the Company may certify any such document as having been approved and adopted in the same manner as this Plan. No such special terms, supplements, amendments or restatements, however, will include any provisions that are inconsistent with the terms of this Plan as then in effect unless this Plan could have been amended to eliminate such inconsistency without further approval by the Shareholders.

15.           Transferability.

(a)           Except as otherwise determined by the Committee, and subject to compliance with Section 17(b) of this Plan and Section 409A of the Code, no Option Right, Appreciation Right, Restricted Share, Restricted Stock Unit, Performance Share, Performance Unit, Cash Incentive Award, award contemplated by Section 9 of this Plan or dividend equivalents paid with respect to awards made under this Plan will be transferable by the Participant except by will or the laws of descent and distribution. In no event will any such award granted under this Plan be transferred for value. Where transfer is permitted, references to “Participant” shall be construed, as the Committee deems appropriate, to include any permitted transferee to whom such award is transferred. Except as otherwise determined by the Committee, Option Rights and Appreciation Rights will be exercisable during the Participant’s lifetime only by him or her or, in the event of the Participant’s legal incapacity to do so, by his or her guardian or legal representative acting on behalf of the Participant in a fiduciary capacity under state law or court supervision.

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(b)           The Committee may specify on the Date of Grant that part or all of the Common Shares that are (i) to be issued or transferred by the Company upon the exercise of Option Rights or Appreciation Rights, upon the termination of the Restriction Period applicable to Restricted Stock Units or upon payment under any grant of Performance Shares or Performance Units or (ii) no longer subject to the substantial risk of forfeiture and restrictions on transfer referred to in Section 6 of this Plan, will be subject to further restrictions on transfer, including minimum holding periods.

16.           Withholding Taxes. To the extent that the Company is required to withhold federal, state, local or foreign taxes or other amounts in connection with any payment made or benefit realized by a Participant or other person under this Plan, and the amounts available to the Company for such withholding are insufficient, it will be a condition to the receipt of such payment or the realization of such benefit that the Participant or such other person make arrangements satisfactory to the Company for payment of the balance of such taxes or other amounts required to be withheld, which arrangements (in the discretion of the Committee) may include relinquishment of a portion of such benefit. If a Participant’s benefit is to be received in the form of Common Shares, and such Participant fails to make arrangements for the payment of taxes or other amounts, then, unless otherwise determined by the Committee, the Company will withhold Common Shares having a value equal to the amount required to be withheld. Notwithstanding the foregoing, when a Participant is required to pay the Company an amount required to be withheld under applicable income, employment, tax or other laws, the Participant may elect, unless otherwise determined by the Committee, to satisfy the obligation, in whole or in part, by having withheld, from the Common Shares required to be delivered to the Participant, Common Shares having a value equal to the amount required to be withheld or by delivering to the Company other Common Shares held by such Participant. The Common Shares used for tax or other withholding will be valued at an amount equal to the fair market value of such Common Shares on the date the benefit is to be included in Participant’s income. In no event will the fair market value of the Common Shares to be withheld and delivered pursuant to this Section 16 exceed the minimum amount required to be withheld, unless (i) an additional amount can be withheld and not result in adverse accounting consequences, (ii) such additional withholding amount is authorized by the Committee, and (iii) the total amount withheld does not exceed the Participant’s estimated tax obligations attributable to the applicable transaction. Participants will also make such arrangements as the Company may require for the payment of any withholding tax or other obligation that may arise in connection with the disposition of Common Shares acquired upon the exercise of Option Rights.

17.           Compliance with Section 409A of the Code.

(a)           To the extent applicable, it is intended that this Plan and any grants made hereunder be exempt from the provisions of Section 409A of the Code or, if not so exempt, that this Plan and any grants made hereunder comply with the provisions of Section 409A of the Code, so that the income inclusion provisions of Section 409A(a)(1) of the Code do not apply to the Participants. This Plan and any grants made hereunder will be administered in a manner consistent with this intent. Any reference in this Plan to Section 409A of the Code will also include any regulations or any other formal guidance promulgated with respect to such section by the U.S. Department of the Treasury or the Internal Revenue Service.

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(b)           Neither a Participant nor any of a Participant’s creditors or beneficiaries will have the right to subject any deferred compensation (within the meaning of Section 409A of the Code) payable under this Plan and grants hereunder to any anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, attachment or garnishment. Except as permitted under Section 409A of the Code, any deferred compensation (within the meaning of Section 409A of the Code) payable to a Participant or for a Participant’s benefit under this Plan and grants hereunder may not be reduced by, or offset against, any amount owed by a Participant to the Company or any of its subsidiaries.

(c)           If, at the time of a Participant’s separation from service (within the meaning of Section 409A of the Code), (i) the Participant will be a specified employee (within the meaning of Section 409A of the Code and using the identification methodology selected by the Company from time to time) and (ii) the Company makes a good faith determination that an amount payable hereunder constitutes deferred compensation (within the meaning of Section 409A of the Code) the payment of which is required to be delayed pursuant to the six-month delay rule set forth in Section 409A of the Code in order to avoid taxes or penalties under Section 409A of the Code, then the Company will not pay such amount on the otherwise scheduled payment date but will instead pay it, without interest, on the tenth business day of the seventh month after such separation from service.

(d)           Solely with respect to any award that constitutes nonqualified deferred compensation subject to Section 409A of the Code and that is payable on account of a Change in Control (including any installments or stream of payments that are accelerated on account of a Change in Control), a Change in Control shall occur only if such event also constitutes a “change in the ownership,” “change in effective control,” and/or a “change in the ownership of a substantial portion of assets” of the Company as those terms are defined under Treasury Regulation §1.409A-3(i)(5), but only to the extent necessary to establish a time and form of payment that complies with Section 409A of the Code, without altering the definition of Change in Control for any purpose in respect of such award.

(e)           Notwithstanding any provision of this Plan and grants hereunder to the contrary, in light of the uncertainty with respect to the proper application of Section 409A of the Code, the Company reserves the right to make amendments to this Plan and grants hereunder as the Company deems necessary or desirable to avoid the imposition of taxes or penalties under Section 409A of the Code. In any case, a Participant will be solely responsible and liable for the satisfaction of all taxes and penalties that may be imposed on a Participant or for a Participant’s account in connection with this Plan and grants hereunder (including any taxes and penalties under Section 409A of the Code), and neither the Company nor any of its affiliates will have any obligation to indemnify or otherwise hold a Participant harmless from any or all of such taxes or penalties.

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18.           Amendments.

(a)           The Board may at any time and from time to time amend this Plan in whole or in part; provided, however, that if an amendment to this Plan, for purposes of applicable stock exchange rules and except as permitted under Section 11 of this Plan, (i) would materially increase the benefits accruing to Participants under this Plan, (ii) would materially increase the number of securities which may be issued under this Plan, (iii) would materially modify the requirements for participation in this Plan, or (iv) must otherwise be approved by the Shareholders in order to comply with applicable law or the rules of the New York Stock Exchange or, if the Common Shares are not traded on the New York Stock Exchange, the principal national securities exchange upon which the Common Shares are traded or quoted, all as determined by the Board, then, such amendment will be subject to Shareholder approval and will not be effective unless and until such approval has been obtained.

(b)           Except in connection with a corporate transaction or event described in Section 11 of this Plan or in connection with a Change in Control, the terms of outstanding awards may not be amended to reduce the Option Price of outstanding Option Rights or the Base Price of outstanding Appreciation Rights, or cancel outstanding “underwater” Option Rights or Appreciation Rights (including following a Participant’s voluntary surrender of “underwater” Option Rights or Appreciation Rights) in exchange for cash, other awards or Option Rights or Appreciation Rights with an Option Price or Base Price, as applicable, that is less than the Option Price of the original Option Rights or Base Price of the original Appreciation Rights, as applicable, without Shareholder approval. This Section 18(b) is intended to prohibit the repricing of “underwater” Option Rights and Appreciation Rights and will not be construed to prohibit the adjustments provided for in Section 11 or Section 12 of this Plan. Notwithstanding any provision of this Plan to the contrary, this Section 18(b) may not be amended without approval by the Shareholders.

(c)           If permitted by Section 409A of the Code, but subject to the paragraph that follows, including in the case of termination of employment or service, or in the case of unforeseeable emergency or other circumstances or in the event of a Change in Control, to the extent a Participant holds an Option Right or Appreciation Right not immediately exercisable in full, or any Restricted Shares as to which the substantial risk of forfeiture or the prohibition or restriction on transfer has not lapsed, or any Restricted Stock Units as to which the Restriction Period has not been completed, or any Cash Incentive Awards, Performance Shares or Performance Units which have not been fully earned, or any dividend equivalents or other awards made pursuant to Section 9 of this Plan subject to any vesting schedule or transfer restriction, or who holds Common Shares subject to any transfer restriction imposed pursuant to Section 15(b) of this Plan, the Committee may, in its sole discretion, provide for continued vesting or accelerate the time at which such Option Right, Appreciation Right or other award may vest or be exercised or the time at which such substantial risk of forfeiture or prohibition or restriction on transfer will lapse or the time when such Restriction Period will end or the time at which such Cash Incentive Awards, Performance Shares or Performance Units will be deemed to have been earned or the time when such transfer restriction will terminate or may waive any other limitation or requirement under any such award.

(d)           Subject to Section 18(b) of this Plan, the Committee may amend the terms of any award theretofore granted under this Plan prospectively or retroactively. Except for adjustments made pursuant to Section 11 of this Plan, no such amendment will materially impair the rights of any Participant without his or her consent. The Board may, in its discretion, terminate this Plan at any time. Termination of this Plan will not affect the rights of Participants or their successors under any awards outstanding hereunder and not exercised in full on the date of termination.

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19.           Governing Law. This Plan and all grants and awards and actions taken hereunder will be governed by and construed in accordance with the internal substantive laws of the State of Delaware.

20.           Effective Date/Termination. This Plan will be effective as of the Effective Date. No grants will be made on or after the Effective Date under the Predecessor Plan, provided that outstanding awards granted under the Predecessor Plan will continue unaffected following the Effective Date. No grant will be made under this Plan on or after the tenth anniversary of the Effective Date, but all grants made prior to such date will continue in effect thereafter subject to the terms thereof and of this Plan. For clarification purposes, the terms and conditions of this Plan shall not apply to or otherwise impact previously granted and outstanding awards under the Predecessor Plan, as applicable.

21.           Miscellaneous Provisions.

(a)           The Company will not be required to issue any fractional Common Shares pursuant to this Plan. The Committee may provide for the elimination of fractions or for the settlement of fractions in cash.

(b)           This Plan will not confer upon any Participant any right with respect to continuance of employment or other service with the Company or any Subsidiary, nor will it interfere in any way with any right the Company or any Subsidiary would otherwise have to terminate such Participant’s employment or other service at any time.

(c)           No award under this Plan may be exercised by the holder thereof if such exercise, and the receipt of cash or shares thereunder, would be, in the opinion of counsel selected by the Company, contrary to law or the regulations of any duly constituted authority having jurisdiction over this Plan.

(d)           Absence on leave approved by a duly constituted officer of the Company or any of its Subsidiaries will not be considered interruption or termination of service of any employee for any purposes of this Plan or awards granted hereunder.

(e)           No Participant will have any rights as a Shareholder with respect to any Common Shares subject to awards granted to him or her under this Plan prior to the date as of which he or she is actually recorded as the holder of such Common Shares upon the share records of the Company.

(f)           The Committee may condition the grant of any award or combination of awards authorized under this Plan on the surrender or deferral by the Participant of his or her right to receive a cash bonus or other compensation otherwise payable by the Company or a Subsidiary to the Participant.

(g)           Except with respect to Option Rights and Appreciation Rights, the Committee may permit Participants to elect to defer the issuance of Common Shares under this Plan pursuant to such rules, procedures or programs as it may establish for purposes of this Plan and which are intended to comply with the requirements of Section 409A of the Code. The Committee also may provide that deferred issuances and settlements include the crediting of dividend equivalents or interest on the deferral amounts.

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(h)           If any provision of this Plan is or becomes invalid or unenforceable in any jurisdiction, or would disqualify this Plan or any award under any law deemed applicable by the Committee, such provision will be construed or deemed amended or limited in scope to conform to applicable laws or, in the discretion of the Committee, it will be stricken and the remainder of this Plan will remain in full force and effect. Notwithstanding anything in this Plan or an Evidence of Award to the contrary, nothing in this Plan or in an Evidence of Award prevents a Participant from providing, without prior notice to the Company, information to governmental authorities regarding possible legal violations or otherwise testifying or participating in any investigation or proceeding by any governmental authorities regarding possible legal violations, and for purpose of clarity a Participant is not prohibited from providing information voluntarily to the Securities and Exchange Commission pursuant to Section 21F of the Exchange Act.

22.           Share-Based Awards in Substitution for Awards Granted by Another Company. Notwithstanding anything in this Plan to the contrary:

(a)           Awards may be granted under this Plan in substitution for or in conversion of, or in connection with an assumption of, stock options, stock appreciation rights, restricted shares, restricted stock units or other share or share-based awards held by awardees of an entity engaging in a corporate acquisition or merger transaction with the Company or any subsidiary. Any conversion, substitution or assumption will be effective as of the close of the merger or acquisition, and, to the extent applicable, will be conducted in a manner that complies with Section 409A of the Code. The awards so granted may reflect the original terms of the awards being assumed or substituted or converted for and need not comply with other specific terms of this Plan, and may account for Common Shares substituted for the securities covered by the original awards and the number of shares subject to the original awards, as well as any exercise or purchase prices applicable to the original awards, adjusted to account for differences in stock prices in connection with the transaction.

(b)           In the event that a company acquired by the Company or any subsidiary or with which the Company or any subsidiary merges has shares available under a pre-existing plan previously approved by shareholders and not adopted in contemplation of such acquisition or merger, the shares available for grant pursuant to the terms of such plan (as adjusted, to the extent appropriate, to reflect such acquisition or merger) may be used for awards made after such acquisition or merger under this Plan; provided, however, that awards using such available shares may not be made after the date awards or grants could have been made under the terms of the pre-existing plan absent the acquisition or merger, and may only be made to individuals who were not employees or directors of the Company or any subsidiary prior to such acquisition or merger.

(c)           Any Common Shares that are issued or transferred by, or that are subject to any awards that are granted by, or become obligations of, the Company under Sections 22(a) or 22(b) of this Plan will not reduce the Common Shares available for issuance or transfer under this Plan or otherwise count against the limits contained in Section 3 of this Plan. In addition, no Common Shares subject to an award that is granted by, or becomes an obligation of, the Company under Sections 22(a) or 22(b) of this Plan, will be added to the aggregate limit contained in Section 3(a)(i) of this Plan.

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EX-10.19

Exhibit 10.19

EXECUTION VERSION

EMPLOYMENT AGREEMENT

This EMPLOYMENT AGREEMENT (this “Agreement”) is entered into on August 4, 2020 by and between BKV Corporation, a Delaware corporation (the “Corporation”), and Christopher Pungya Kalnin (“Executive”). In consideration of the mutual covenants contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

1.             Certain Definitions. Certain words or phrases used herein with initial capital letters shall have the meanings set forth in paragraph 8 hereof.

2.             Employment. The Corporation offers to employ Executive with the Corporation, and Executive accepts such employment with the Corporation, upon and subject to the terms and conditions set forth in this Agreement for the period beginning on May 1, 2020 (the “Effective Date”) and ending as provided in paragraph 5 hereof (the “Employment Period”), it being understood that the parties agree to renegotiate, in good faith, the terms and conditions of Executive’s employment with the Corporation in the event the Employment Period has not concluded by December 31, 2030.

3.             Position and Duties.

(a)            During the Employment Period, Executive shall serve as the Chief Executive Officer (“CEO”) of the Corporation and/or an executive of any subsidiary of the Corporation as may be designated by the Corporation and agreed upon by Executive from time to time (such subsidiaries, collectively, the “Group Companies” and, each and any of them, a “Group Company”) and shall have the normal duties, responsibilities and authority of an executive serving in such position subject to the terms and conditions of the Stockholders’ Agreement, the Bylaws, and the work rules and internal policies established by the Board, in good faith, from time to time. For so long as Executive holds the position of CEO, the Corporation shall use its good faith efforts to nominate Executive for election and re-election to the Board and to procure his election thereto at any applicable meeting of shareholders held for the purpose of electing directors, and Executive agrees to serve on the Board. Executive agrees that, unless specifically addressed in writing by the Corporation’s parent entity, Executive’s separation from employment or termination as the Corporation’s CEO shall constitute his immediate and automatic resignation from the Board.

(b)            During the Employment Period, Executive shall report solely to the Board.

(c)            During the Employment Period, Executive shall devote all of Executive’s reasonable best efforts and Executive’s full business time and attention (except for permitted paid time off periods and reasonable periods of illness or other incapacity) to the Business; provided, however, that Executive may (i) engage in charitable and civic activities, (ii) manage his personal and/or family finances and/or investments, and (iii) subject to the consent of the Board, serve on any board of directors for other public or private companies, in each case so long as such activities do not compete with the Business, create any conflict with the interest of any Group Company or materially interfere, individually or in the aggregate, with the performance of his duties hereunder.

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(d)            Executive shall perform Executive’s duties and responsibilities to the best of Executive’s abilities in a diligent, trustworthy, businesslike and efficient manner.

(e)            During the Employment Period, Executive shall perform Executive’s duties and responsibilities principally at the Corporation’s headquarters in Denver, Colorado area; provided, however, that Executive acknowledges that he may from time to time be required to engage in travel in connection with the performance of his duties hereunder.

4.             Compensation and Benefits.

(a)            Salary. Under this Agreement, Executive’s initial annual base salary shall be $500,000.00, payable in 12 monthly installments based on the Corporation’s payroll practices in the amount of $41,666.67 per month (prorated for any partial month). The annual base salary of Executive in effect from time to time is hereinafter referred to as the “Base Salary”. The Board shall review the Base Salary annually commencing in the 2021 Financial Year and may, in its sole discretion, increase it.

(b)            Annual Incentive Compensation. During the Employment Period, Executive will be eligible to receive an annual incentive compensation payment, based on the achievement of goals reasonably determined in good faith by the Board, which may include Executive’s historical and anticipated future performance, the Business’s growth and profitability, and other relevant considerations (the “Annual Incentive Compensation”).

(i)            Target of Annual Incentive Compensation. During the Employment Period, with respect to the 2020 Financial Year and each Financial Year thereafter, Executive’s target incentive compensation amount is equal to 100% of the amount of the Base Salary for such Financial Year (“Target Incentive Compensation Amount”).

(ii)           Payment of Annual Incentive Compensation. The Annual Incentive Compensation will be calculated on a sliding scale, with ranges above and below target, consistent with the Annual Incentive Compensation calculations prepared by the Corporation’s compensation committee for the Board, as approved by the Board, and provided to Executive during the applicable Financial Year. Except as otherwise set forth herein, Executive will be required to be employed by the Corporation on December 31st of the Financial Year to which the Annual Incentive Compensation relates in order to be eligible to receive the applicable Annual Incentive Compensation payment under this subparagraph 4(b). The Annual Incentive Compensation will be paid by no later than March 15th of the Financial Year following the Financial Year to which such Annual Incentive Compensation relates.

(c)            Paid Time Off. During the Employment Period, Executive shall be entitled to eight (8) weeks of paid time off during each Financial Year (prorated for any partial Financial Year). Any accrued paid time off that is not used in the Financial Year in which it is earned will not be eligible to be carried forward to, or otherwise used in, any subsequent Financial Year.

(d)            Holidays. During the Employment Period, Executive shall be entitled to holidays consistent with the Corporation’s policy established by the Board, which may be amended from time to time by the Board.

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(e)            Standard Benefits Package. Executive shall be eligible during the Employment Period to participate, on the same basis as other employees of the Corporation, in the Corporation’s Standard Benefits Package. The Corporation’s “Standard Benefits Package” means those benefits that are offered to all employees of the Corporation on a uniform and nondiscriminatory basis, including health insurance coverage and participation in a 401(k) plan, if such programs are sponsored by the Corporation.

(f)             Long-Term Incentive Compensation. With respect to each Financial Year during the Employment Period beginning with the 2020 Financial Year, Executive shall be eligible to participate in the Corporation’s 2020 Employee Equity Incentive Plan, maintained by the Corporation (and any successor plan thereto) (the “Equity Plan”) at a level commensurate with his position as CEO. Notwithstanding anything herein to the contrary, it is agreed that each year for a period of four years (2020, 2021, 2022 and 2023) Executive shall be granted an equity award in the form of restricted stock units (each an “Annual RSU Grant”) that is equal to, at least, 325,900 shares of the share reserve under the Equity Plan per year in accordance with and subject to the terms of the Equity Plan.

5.             Employment Period. The Employment Period shall end early upon the first to occur of any of the following events:

(a)            Executive’s death;

(b)            a separation of Executive’s employment hereunder that is effected by the Corporation due to Executive’s Permanent Disability;

(c)            the Corporation and Executive mutually agree in writing to terminate this Agreement without agreeing to enter into a new employment contract that would become effective on or about the time that this Agreement terminates;

(d)            a Separation For Cause;

(e)            a Separation Without Cause;

(f)             a Separation With Good Reason; or

(g)            a Voluntary Separation.

6.             Post-Employment Payments.

(a)            At the end of Executive’s employment for any reason, Executive shall cease to have any rights to salary, equity awards, expense reimbursements or other benefits, except that Executive shall be entitled to (i) any portion of the Base Salary which has accrued but is unpaid, (ii) any Annual Incentive Compensation set forth in subparagraph 4(b) above that has been earned for a prior Financial Year but is unpaid, (iii) any reimbursable expenses which have been incurred but are unpaid, (iv) any paid time off days which have accrued pursuant to the Corporation’s paid time off policy, as in effect from time to time, but are unused, as of the end of the Employment Period, and (v) any benefits to which Executive is entitled under Part 6 of Subtitle B of Title I of the Employee Retirement Income Security Act of 1974, as amended (“COBRA”) (the foregoing (i) through (v) being, the “Accrued Rights”).

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(b)            If the Employment Period ends pursuant to paragraph 5 on account of a Separation For Cause or a Voluntary Separation, the Corporation shall pay Executive (i) the Accrued Rights and (ii) any option or other equity-grant rights or plan benefits to the extent that they have already vested in accordance with the Corporation’s Equity Plan by the time of such separation.

(c)            If the Employment Period ends pursuant to paragraph 5 on account of a Separation Without Cause or a Separation With Good Reason, any outstanding Annual RSU Grant shall become vested and the Corporation shall pay Executive (i) the Accrued Rights and (ii) an amount equal to 200% of the aggregate amount of the Base Salary plus the Target Incentive Compensation Amount at the time of such separation. The amounts payable under clause (ii) of the preceding sentence shall be paid in a lump sum on the 61st day after the date on which such separation of employment occurs (the “Severance Payment Date”), it being understood that the amounts payable under clause (i) of the preceding sentence shall be payable in accordance with applicable law or their applicable terms, but in no event later than the Severance Payment Date.

(d)            If the Employment Period ends pursuant to paragraph 5 on account of a Separation Without Cause or Separation With Good Reason, if Executive elects continuation coverage under the Corporation’s medical plan pursuant to COBRA, the Corporation shall reimburse Executive (provided such reimbursement does not result in material taxes or penalties for the Corporation) for the full amount of Executive’s COBRA premium payments for such coverage and his eligible dependents until the earlier of (i) Executive’s eligibility for any such coverage under another employer’s or any other medical plan or (ii) the date that is eighteen (18) months following the separation of Executive’s employment. The Corporation shall make any such reimbursement within thirty (30) days following receipt of evidence from Executive of Executive’s payment of the COBRA premium.

(e)            It is expressly understood that the Corporation’s payment obligations under subparagraphs 6(b), 6(c) or 6(d), as applicable, shall cease in the event Executive breaches in any material respect any of the agreements in paragraphs 7 or 9 hereof. Each payment under subparagraphs 6(b), 6(c) or 6(d), as applicable, shall be considered a separate payment and not one of a series of payments for purposes of Section 409A.

(f)             Executive shall not be required to mitigate the amount of any payment provided for under subparagraphs 6(b), (c) or 6(d), as applicable, by seeking other employment and such amounts shall not be reduced whether or not Executive obtains other employment, except as provided in subparagraph 6(e).

(g)            Release. Notwithstanding anything in this Agreement to the contrary, the Corporation shall not be obligated to make any payment under subparagraphs 6(b), 6(c) or 6(d), as applicable, unless (1) Executive timely executes the Release Agreement attached hereto as Exhibit A within the Consideration Period (as defined therein) and (ii) Executive does not revoke such execution or signature within the Revocation Period (as defined therein).

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7.             Competitive Activity; Confidentiality; Non-Solicitation.

(a)            Acknowledgements and Agreements. Executive hereby understands and agrees that trade secrets and Confidential Information of the Corporation and the Group Companies, more fully described in subparagraph 7(e)(i), gained by Executive during Executive’s association with the Corporation or any Group Company, have been developed by the Corporation or such Group Company (as applicable) through substantial expenditures of time, effort and money and constitute valuable and unique property of the Corporation or such Group Company (as applicable). Executive further understands and agrees that the foregoing makes it necessary for the protection of the Business that Executive not compete with the Corporation or any Group Company during his employment with the Corporation, and not compete with the Corporation or any Group Company for a reasonable period thereafter, as further provided in the following subparagraphs. In consideration for Executive’s receipt of trade secrets and Confidential Information, Executive agrees to the following restrictive covenants:

(b)            Covenants.

(i)            Covenants During Employment. While being employed by the Corporation, Executive will not compete with the Corporation or any Group Company anywhere in the world. In accordance with this restriction, but without limiting its terms, while employed by the Corporation, Executive will not do or attempt to do any of the following:

(A)           entering into or engaging in any business which competes with the Business;

(B)            soliciting any customers, business, assets, investments or patronage (or customer, business, asset, investment or patronage prospects) for, or selling, any products or services in competition with or for, any business that competes with the Business;

(C)            diverting, enticing or otherwise taking away any customers, business, assets or investments or patronage (or customer, business, asset, investment or patronage prospects) of the Corporation or any Group Company; or

(D)            promoting, managing or assisting, financially or otherwise, any Person, firm, association, partnership, corporation or other entity engaged in any business which competes with the Business.

(ii)           Covenants Following Separation. For a period of eighteen (18) months following a separation of Executive’s employment, Executive shall not:

(A)           enter into or engage in any business which competes with the Business within the Restricted Territory;

(B)            solicit any known customers, business, assets, investments or patronage (or customer, business, asset, investment or patronage prospects) for, or sell, any products or services in competition with or for, any business that competes with the Business within the Restricted Territory;

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(C)            divert, entice or otherwise take away any known customers, business, assets or investments or patronage (or customer, business, asset, investment or patronage prospects) of the Corporation or any Group Company within the Restricted Territory; or

(D)            promote, manage or assist, financially or otherwise, any Person, firm, association, partnership, corporation or other entity engaged in any business which competes with the Business within the Restricted Territory.

Notwithstanding the foregoing, following a separation of Executive’s employment as a result of a Separation Without Cause or a Separation With Good Reason, Executive shall not be considered to have breached this subparagraph 7(b)(ii) if Executive provides services to a business unit, division or subsidiary of an entity that otherwise competes with the Business through another business unit, division or subsidiary of such entity, so long as Executive only provides services to the business unit, division or subsidiary that does not compete with the Business and Executive takes no actions that would compete with the Business or otherwise violate any of the provisions of this paragraph 7 or of paragraph 9. For purposes of this subparagraph 7(b)(ii), customers, business or patronage (or active customer, business or patronage prospects) shall be presumed as “known” to the extent the Corporation, in good faith, treated such customers, business or patronage (or active customer, business or patronage prospects) as such at any time during the twelve (12) month period prior to Executive’s separation of employment.

(iii)          Indirect Competition. For the purposes of subparagraphs 7(b)(i) and (ii), but without limiting such provisions, Executive will be in violation thereof if Executive engages in any or all of the activities set forth therein directly as an individual on Executive’s own account, or indirectly as a partner, joint venturer, employee, agent, salesperson, consultant, officer and/or director of any firm, association, partnership, corporation or other entity, or as a shareholder of any corporation (or owner of any other type of equity interest in any other entity) in which Executive or Executive’s spouse (to the extent Executive and Executive’s spouse are not legally separated), minor child or parent sharing the same household as Executive owns, directly or indirectly, individually or in the aggregate, more than one percent (1%) of the outstanding stock or other equity interests.

(iv)          If it is judicially determined, or by consent of Executive, that Executive has violated this subparagraph 7(b) and the Corporation obtains an order, injunction or other equitable relief, then the period applicable to each obligation that Executive has been determined to have violated will be automatically extended by a period of time equal in length to the period during which such violation occurred.

(c)            The Corporation. For purposes of this paragraph 7, the Corporation shall include the Corporation, the Group Companies and any and all other direct and indirect subsidiary, parent, affiliated, or related companies of the Corporation for which Executive worked or had responsibility at the time of separation of his employment and at any time prior to such separation.

(d)            Non-Solicitation; Non-Association. Executive will not directly or indirectly at any time during the period of Executive’s employment, or for a period eighteen (18) months following a separation of Executive’s employment, disrupt, damage, impair or interfere with the Business by raiding any of the Corporation’s or any Group Company’s employees, soliciting any of them to resign from their employment by the Corporation or such Group Company (as applicable) or associating with any of them for the express purpose of encouraging them to resign from their employment by the Corporation or such Group Company (as applicable), or by disrupting the relationship between the Corporation or any Group Company and any of its consultants, agents or representatives, or attempt to do any of the foregoing; provided, however, that this subparagraph 7(d) shall not prohibit Executive from providing references for the Corporation’s or a Group Company’s employees, when contacted by a prospective employer. Executive acknowledges that this covenant is necessary to enable the Corporation and the Group Companies to maintain a stable workforce and remain in business.

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(e)            Further Covenants.

(i)            Executive will keep in strict confidence, and will not, directly or indirectly, at any time, during or after Executive’s employment with the Corporation, disclose, furnish, disseminate, make available or, except in the course of performing Executive’s duties of employment, use any trade secrets, proprietary data and information relating to the Corporation or any Group Company’s past, present, or future business and products, price lists, customer lists, customer contracts, processes, procedures, plans or standards, know-how, manuals, business strategies, records, drawings, specifications, designs, financial information, whether or not reduced to writing, registered or labeled as confidential, or information or data that the Corporation or any Group Company advises Executive should be treated as confidential information, including without limitation as to when or how Executive may have acquired such information (“Confidential Information”), except (A) as required in the performance of his duties to the Corporation, (B) to the extent that Executive is required by law, or requested by subpoena, court order or governmental, regulatory or self-regulatory body with apparent authority to disclose any Confidential Information (provided that in such case, Executive shall (x) provide the Board, to the extent legally permitted, with notice as soon as practicable following such request that such disclosure has been requested or is or may be required, (y) reasonably cooperate with the Board, at the Corporation’s expense, in protecting, to the maximum extent legally permitted, the confidential or proprietary nature of such Confidential Information, and (z) disclose only that Confidential Information which he is legally required to disclose), (C) disclosing information that has been or is hereafter made public through no act or omission of Executive in violation of this Agreement, the Stockholders’ Agreement or any other confidentiality obligation or duty owed to the Corporation or any Group Company, (D) disclosing information and documents to his attorney or tax adviser for the purpose of securing legal or tax advice (provided that such advisors undertake to the Corporation to keep such information confidential), or (E) disclosing information and documents to the extent reasonably appropriate in connection with any litigation or arbitration between Executive and the Corporation or any Group Company. Executive specifically acknowledges that all such Confidential Information, whether reduced to writing, maintained on any form of electronic media, or maintained in the mind or memory of Executive and whether compiled by the Corporation or any Group Company, and/or Executive, derives independent economic value from not being readily known to or ascertainable by proper means by others who can obtain economic value from its disclosure or use, that reasonable efforts have been made by the Corporation and the Group Companies to maintain the secrecy of such information, that such information is the sole property of the Corporation or the Group Companies (as applicable) and that any retention and use of such information by Executive during Executive’s employment with the Corporation (except in the course of performing Executive’s duties and obligations to the Corporation) or after the separation of Executive’s employment shall constitute a misappropriation of the Corporation’s and the Group Companies’ trade secrets.

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(ii)           The U.S. Defend. Trade Secrets Act of 2016 (“DTSA”) provides that an individual shall not be held criminally or civilly liable under any federal or state trade secret law for the disclosure of a trade secret that (A) is made in confidence to a federal, state or local government official, either directly or indirectly, or to an attorney, and solely for the purpose of reporting or investigating a suspected violation of law; or (B) is made in a complaint or other document filed in a lawsuit or other proceeding, if such filing is made under seal. In addition, the DTSA provides that an individual who files a lawsuit for retaliation by an employer for reporting a suspected violation of law may disclose the trade secret to the attorney of the individual and use the trade secret information in the court proceeding, if the individual files any document containing the trade secret under seal and does not disclose the trade secret, except pursuant to court order.

(iii)          Executive agrees that upon separation of Executive’s employment with the Corporation, for any reason, Executive shall return to the Corporation, in good condition, all property of the Corporation, including without limitation, the originals and all copies of any documents and materials which are under his possession and contain, reflect, summarize, describe, analyze or refer or relate to any items of information listed in subparagraph 7(e)(i) of this Agreement. Notwithstanding the foregoing, Executive shall be permitted to retain or copy (A) his contacts, calendar and personal correspondence, and (B) any documents or information related to his compensation or reasonably needed for Executive’s tax purposes.

(iv)          Nothing in this Agreement prevents Executive from, providing, without prior notice to the Corporation, information to governmental authorities regarding possible legal violations or otherwise testifying or participating in any investigation or proceeding by any governmental authorities regarding possible legal violations.

(f)             Discoveries and Inventions^., Work Made for Hire.

(i)            Executive agrees that upon conception and/or development of any idea, discovery, invention, improvement, innovation, analysis, report, drawing, copyright, patent, trademark, intellectual property right, software, writing or other definite and useful idea or compilation of information of value (“Intellectual Development”) that: (A) relates to the Business, or (B) relates to the Corporation’s or any Group Company’s actual or demonstrably anticipated research or development, or (C) results from any work performed by Executive for the Corporation or any Group Company, Executive will assign to the Corporation (or a Group Company designated by the Corporation) the entire right, title and interest in and to any such Intellectual Development. Executive has no obligation to assign any Intellectual Development that Executive conceives and/or develops entirely on Executive’s own time without using the Corporation’s or any Group Company’s equipment, supplies, facilities, or trade secret information unless the Intellectual Development either: (x) relates to the business of the Business, or (y) relates to the Corporation’s or any Group Company’s actual or demonstrably anticipated research or development, or (z) results from any work performed by Executive for the Corporation or any Group Company. Executive agrees that any Intellectual Development that relates to the business of the Corporation or any Group Company or relates to the Corporation’s or any Group Company’s actual or demonstrably anticipated research or development which is conceived or suggested by Executive, either solely or jointly with others, within eighteen (18) months following separation of Executive’s employment under this Agreement or any successor agreements shall be presumed to have been so made, conceived or suggested in the course of such employment with the use of the Corporation’s or a Group Company’s equipment, supplies, facilities, and/or trade secrets.

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(ii)           In order to determine the rights of Executive and the Corporation or a Group Company in any Intellectual Development, and to insure the protection of the same, Executive agrees that during Executive’s employment, and, to the extent related to the Business, for eighteen (18) months after the separation of Executive’s employment under this Agreement or any successor agreement, Executive will disclose immediately and fully to the Corporation any Intellectual Development conceived, made or developed by Executive solely or jointly with others. The Corporation agrees to keep any such disclosures confidential. Executive also agrees during Executive’s employment, and, to the extent related to the Business, for eighteen (18) months after the separation of Executive’s employment under this Agreement or any successor agreement, to record descriptions of all work in the manner directed by the Corporation and agrees that all such records will be the exclusive property of the Corporation and the Group Companies. Executive agrees that at the request of and without charge to the Corporation, but at the Corporation’s expense, Executive will execute a written assignment of the Intellectual Development to the Corporation and will assign to the Corporation (or a Group Company designated by the Corporation) any application for letters patent or for trademark registration made thereon, and to any common-law or statutory copyright therein; and that Executive will do whatever may be necessary or desirable to enable the Corporation to secure any patent, trademark, copyright, or other property right therein in the United States and in any foreign country, and any division, renewal, continuation, or continuation in part thereof, or for any reissue of any patent issued thereon. In the event the Corporation is unable, after reasonable effort, and in any event after ten (10) business days, to secure Executive’s signature on a written assignment to the Corporation (or its designated Group Company) of any application for letters patent or to any common-law or statutory copyright or other property right therein, whether because of Executive’s physical or mental incapacity or for any other reason whatsoever, Executive irrevocably designates and appoints the General Counsel of the Corporation as Executive’s attorney-in-fact to act on Executive’s behalf to execute and file any such application and to do all other lawfully permitted acts to further the prosecution and issuance of such letters patent, copyright or trademark.

(iii)          Executive acknowledges that, to the extent permitted by law, all work papers, reports, documentation, drawings, photographs, negatives, tapes and masters therefor, prototypes and other materials (hereinafter, “items”), including without limitation, any and all such items generated and maintained on any form of electronic media, generated by Executive during Executive’s employment with the Corporation shall be considered a “work made for hire” and that ownership of any and all copyrights in any and all such items shall belong to the Corporation and the Group Companies.

(g)            Confidentiality Agreements. Executive agrees that Executive shall not disclose to the Corporation or induce the Corporation to use any secret or confidential information belonging to Executive’s former employers. Executive represents and warrants that Executive is not bound by the terms of a confidentiality agreement or other agreement with a third party that would preclude or limit Executive’s right to work for the Corporation and the Group Companies and/or to disclose to any of them any Intellectual Development that may be conceived during employment with the Corporation. Executive agrees to provide the Corporation with a copy of any and all agreements with a third party that preclude or limit Executive’s right to make disclosures or to engage in any other activities contemplated by Executive’s employment with the Corporation.

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(h)            Relief. Executive acknowledges and agrees that the remedy at law available to the Corporation for breach of any of Executive’s obligations under this Agreement would be inadequate. Executive therefore agrees that, in addition to any other rights or remedies that the Corporation may have under the Stockholders’ Agreement, at law or in equity, temporary and permanent injunctive relief may be granted in any proceeding which may be brought to enforce any provision contained in subparagraphs 7(b), 7(d), 7(e), 7(f) and 7(g) or in paragraph 9 of this Agreement, without the necessity of proof of actual damage.

(i)             Stockholders’ Agreement. Nothing in this Agreement limits the obligations of Executive under the public announcements and confidentiality provisions of the Stockholders’ Agreement.

(j)             Reasonableness. Executive acknowledges that Executive’s obligations under this paragraph 7 and paragraph 9 of this Agreement are reasonable in the context of the nature of the Business and the competitive injuries likely to be sustained by the Corporation and the Group Companies if Executive were to violate such obligations. Executive further acknowledges that this Agreement is made in consideration of, and is adequately supported by the agreement of the Corporation to perform its obligations under this Agreement and by other consideration, which Executive acknowledges constitutes good, valuable and sufficient consideration.

8.             Definitions.

(a)            “Affiliate” means any Person that directly or indirectly controls, is controlled by, or is under common control with the Corporation. In this definition, the term “control” (including with the correlative meaning, the terms “controlled by” and “under common control with”), as applied to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting or other securities, by contract, or otherwise.

(b)            “Board” means the Board of Directors of the Corporation.

(c)            “Business” means (i) the purchasing, selling, or marketing of natural gas, natural gas liquids, oil, hydrocarbons, brine, produced water or any derivative product thereof, including, without limitation, locating buyers and sellers, or negotiating purchase and sales contracts; (ii) the gathering, processing, fractionation, stabilization, and/or transporting of natural gas, natural gas liquids, oil, hydrocarbons, brine, produced water, or any derivative product thereof; (iii) any exploration for natural gas, natural gas liquids, oil, hydrocarbons, brine, produced water, or any derivative product thereof; (iv) investment in any Person that engages in any of the foregoing activities under sub-clauses (i) through (iii) above; and (v) the conduct of a business enterprise that is in an upstream oil and gas industry in North America that contributes ten percent (10%) or more to the Corporation’s gross revenue or deploys ten percent (10%) or more of the Corporation’s fixed assets.

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(d)            “Bylaws” means the Bylaws of the Corporation, as such Bylaws may be adopted and/or amended from time to time in accordance with the Stockholders’ Agreement.

(e)            “Change in Control” means, in relation to the Corporation, where a person who did not previously exercise control over the Corporation acquires, or otherwise becomes able to exercise, control, or where a person who was previously able to exercise control over the Corporation ceases to be in a position to do so. In this definition, the term “control” means (i) control of more than two-thirds of the total voting rights conferred by all the issued and outstanding stock in the Corporation which are ordinarily exercisable in a general meeting, or (ii) the power to appoint the majority of the directors on the Board.

(f)             “Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder, as such laws, rules and regulations may be amended from time to time.

(g)            “FCPA” means the Foreign Corrupt Practices Act of 1977, as amended, and the rules and regulations thereunder, as such laws, rules and regulations may be amended from time to time.

(h)            “Financial Year” means the financial year of the Corporation or the Group Companies (as applicable), which in each case (other than in the case of its first financial year) shall commence on January 1^st and end on December 31^st, provided that the first financial year of the Corporation shall be deemed to have commenced on May 1^st, 2020 and end on December 31^st, 2020.

(i)             “Permanent Disability” means that Executive, because of accident, disability, or physical or mental illness, is incapable of performing Executive’s duties to the Corporation or any Group Company, as determined by the Board. Notwithstanding the foregoing, Executive will be deemed to have become incapable of performing Executive’s duties to the Corporation or any Group Company, if Executive is incapable of so doing for (i) a continuous period of one hundred and twenty (120) days and remains so incapable at the end of such 120-day period or (ii) periods amounting in the aggregate to one hundred and eighty (180) days within any one period of 365 days and remains so incapable at the end of such aggregate period of one hundred and eighty (180) days.

(j)             “Person” means any individual, entity, or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Exchange Act).

(k)            “Restricted Territory” means: (i) the United States and Canada; and/or (ii) all of the specific customer accounts, whether within or outside of the geographic area described in (i) above, with which Executive had any contact or for which Executive had any responsibility (either direct or supervisory) at the time of the separation of Executive’s employment and at any time during the two-year period prior to such separation.

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(l)             “Separation For Cause” means the separation of Executive’s employment hereunder that is effected by the Corporation as a result of: (i) Executive’s indictment (or other criminal charge against Executive) for a felony, or Executive’s commission of fraud against the Corporation or any Group Company, (ii) misconduct by Executive that brings the Corporation or any Group Company or Affiliate of the Corporation into substantial public disgrace or disrepute, (iii) Executive’s gross negligence or gross misconduct with respect to the Corporation, any Group Company or any other subsidiary or affiliate of the Corporation, (iv) Executive’s insubordination to, or material failure to follow, the lawful directions of the Board or the Board Reserved Matters (as defined in the Stockholders’ Agreement), which, if curable, is not cured within ten (10) days after written notice thereof to Executive, (v) Executive’s material violation of paragraph 7 or 9 hereof, (vi) Executive’s material breach of any work rule or internal policy of the Corporation that is established in good faith which, if curable, is not cured within ten (10) days after written notice thereof to Executive, (vii) Executive violation of the FCPA or any state or federal anti-money laundering laws or (viii) any material breach by Executive of this Agreement (other than paragraphs 7 and 9) is not cured within thirty (30) days after written notice thereof to Executive. Notwithstanding the foregoing, no separation by the Corporation shall constitute a “Separation For Cause” unless (A) the Corporation provides Executive reasonable written notice of its intent to effect the separation of Executive by reason of a Separation For Cause, which such notice must include a statement that a majority of the Board has determined in good faith that an event described in clause (i), (ii), (iii), (iv), (v), (vi) or (vii) exists and (B) Executive is given reasonable opportunity during the thirty (30) day period after receiving the notice described in the preceding clause (A) to be heard by the Board with Executive’s legal counsel.

(m)           “Separation With Good Reason” means a separation of Executive’s employment hereunder that is effected by Executive after: (i) a material reduction in either the Base Salary or the Target Incentive Compensation Amount, other than as part of an across-the-board reduction applicable to all Corporation executives of no greater than 10%, (ii) the material diminution in Executive’s position, duties, authority, reporting or responsibilities, (iii) any material breach by the Corporation of this Agreement (including the failure of the Corporation to satisfy the last sentence of paragraph 16 or its obligations in the second to last sentence of subparagraph 3(a)), (iv) any of the events set out under Clause 19.1.1(i) to (iii) of the Stockholders Agreement occurs and Executive elects to sell all (and not less than all) of the Stocks owned by him in accordance with Clause 19 of the Stockholders’ Agreement or (v) the involuntary permanent relocation (“permanent relocation” shall be defined as requiring Executive to be in such other location for more than 90 days per Financial Year) of Executive’s principal place of employment to a location more than thirty-five (35) miles beyond Executive’s principal place of employment in Denver, Colorado as of the Effective Date. Notwithstanding the foregoing, no separation of employment by Executive shall constitute a “Separation With Good Reason” unless (A) Executive gives the Corporation notice of the existence of an event described in clause (i), (ii), (iii), (iv) or (v) above, within thirty (30) days following the occurrence thereof, (B) the Corporation does not remedy such event described in clause (i), (ii), (iii) or (v) above, as applicable, within sixty (60) days of receiving the notice described in the preceding clause (A), and (C) Executive effects such separation of employment within ninety (90) days of the end of the cure period specified in clause (B) above.

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(n)            “Separation Without Cause” means the separation of Executive’s employment hereunder that is effected by the Corporation for any reason other than a separation by reason of Executive’s death, for Permanent Disability or a Separation For Cause (it being understood that the Corporation shall use commercially reasonable efforts to avoid effecting a Separation Without Cause during the one-year period after the Effective Date).

(o)            “Stockholders’ Agreement” means the Stockholders’ Agreement dated 1 May 2020 relating to relating to BKV Corporation and its Group Companies, as such agreement may be amended from time to time.

(p)            “Voluntary Separation” means the separation of Executive’s employment hereunder that is effected by Executive for any reason, other than a Separation With Good Reason (it being understood that Executive may voluntarily resign his employment at any period after the Effective Date), by the Executive giving prior notice to the Corporation at least one hundred and eighty (180) days prior to the effective date of such separation.

9.             Non-Disparagement. Executive agrees not to disparage the Corporation, any Group Company or any of their respective businesses, assets, investments, products or practices, or any of their respective directors, officers, agents, representatives, partners, members, or Affiliates, either orally or in writing, at any time, and the Corporation shall use its commercially reasonable best efforts (and shall cause the Group Companies to use their commercially reasonable best efforts) to not disparage, and shall instruct their respective directors and executive officers not to disparage, Executive, either orally or in writing, at any time; provided, however, that Executive and the Corporation (and its directors and executive officers) may confer in confidence with their respective legal representatives and make truthful statements as required by law, or by governmental, regulatory or self-regulatory investigations or as truthful testimony in connection with any litigation involving Executive and the Corporation. During the Employment Period, this paragraph 9 shall only apply to public statements or private statements that are reasonably likely to become public as a result of communication to any person or entity that is a member of, employed or engaged by, or directly connected to any broadcast or other media.

10.           Survival. Subject to any limits on applicability contained therein, paragraph 7 and paragraph 9 hereof shall survive and continue in full force in accordance with their terms notwithstanding any ending of the Employment Period.

11.           Taxes. The Corporation may withhold from any amounts payable under this Agreement all federal, state, city or other taxes as the Corporation is required to withhold pursuant to any applicable law, regulation or ruling. Notwithstanding any other provision of this Agreement, the Corporation shall not be obligated to guarantee any particular tax result for Executive with respect to any payment provided to Executive hereunder, and Executive shall be responsible for any taxes imposed or assessed on Executive with respect to any such payment.

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12.           Notices. Any notice provided for in this Agreement shall be in writing and shall be either personally delivered, sent by reputable overnight carrier or mailed by first class mail, return receipt requested, to the recipient at the address below indicated:

Notices to Executive:

At the address contained in the Corporation’s payroll records

Notices to the Corporation:

BKV Corporation
1200 17th Street, Suite 2100
Denver, CO 80202
Attention: Board of Directors and General Counsel

or such other address or to the attention of such other person as the recipient party shall have specified by prior written notice to the sending party. Any notice under this Agreement will be deemed to have been given when so delivered.

13.           Severability. Whenever possible, each provision of this Agreement shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Agreement is held to be invalid or unenforceable in any respect under any applicable law, such invalidity or unenforceability shall not affect any other provision, but this Agreement shall be reformed, construed and enforced as if such invalid or unenforceable provision had never been contained herein.

14.           Complete Agreement. This Agreement embodies the complete agreement and understanding between the parties with respect to the subject matter hereof and supersedes and preempts any prior understandings, agreements or representations by or between the parties, written or oral which may have related to the subject matter hereof in any way; provided, however, that for the avoidance of doubt, this Agreement shall have no effect on the Executive’s or the Corporation’s respective rights or the exercise thereof as set forth in Clauses 18 and 19 of the Stockholders Agreement.

15.           Counterparts. This Agreement may be executed in separate counterparts, each of which shall be deemed to be an original and both of which taken together shall constitute one and the same agreement.

16.           Successors and Assigns. This Agreement shall bind and inure to the benefit of and be enforceable by Executive, the Corporation and their respective heirs, executors, personal representatives, successors and assigns, except that neither party may assign any rights or delegate any obligations hereunder without the prior written consent of the other party. Executive hereby consents to the assignment by the Corporation of all of its rights and obligations hereunder to any successor to the Corporation by merger or consolidation or purchase of all or substantially all of the Corporation’s assets; provided such transferee or successor assumes the liabilities of the Corporation hereunder. The Corporation shall require any successor to all or substantially all of its assets (whether direct or indirect, by purchase, merger, consolidation or otherwise) to assume expressly and agree to perform this Agreement in the same manner and to the same extent that the Corporation would be required to perform it if no such succession had taken place.

17.           Governing Law. This Agreement shall be governed by, and construed in accordance with, the internal, substantive laws of the State of New York without giving effect to any choice of law or conflict of law provision or rule (whether of the State of New York or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than the State of New York.

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18.           Dispute Resolution; Arbitration. Any dispute or controversy arising out of or relating to Executive’s employment, this Agreement (other than paragraph 7, which shall be determined by any court with competent jurisdiction), or the breach, termination or validity thereof, shall be finally determined and settled by binding, confidential arbitration conducted expeditiously in accordance with the rules for employment disputes in the Employment Arbitration Rules of the American Arbitration Association (the “AAA”) before one arbitrator of exemplary qualifications and stature, who shall be selected by mutual agreement by the parties hereto, or if the parties cannot agree on the selection of the arbitrator, who shall be selected by the AAA. The arbitrator, and not any federal, state, or local court or agency, shall have the exclusive authority to resolve any question as to the arbitrability of a dispute and/or any dispute relating to the interpretation, applicability, enforceability, or formation of this Agreement. Either Executive or the Corporation may apply to a court of competent jurisdiction for temporary or preliminary injunctive relief in connection with a dispute; provided, however, that all issues of final relief shall be decided in arbitration, and the pursuit of the temporary or preliminary injunctive relief shall not constitute a waiver of rights under this Agreement. All disputes will be arbitrated on an individual basis, and not on a class, collective, representative, or similar basis. Any such arbitration shall take place in the City of Denver, Colorado. The arbitration shall be governed by the Federal Arbitration Act and any judgment upon the award decided upon by the arbitrator may be entered by any court having jurisdiction thereof. Each party hereby acknowledges that compensatory damages include (without limitation) any benefit or right of indemnification given by another party to the other under this Agreement. The prevailing party in any such arbitration shall be entitled to recover from the other party its reasonable costs in connection therewith. To the maximum extent permitted by law, the parties, the witnesses, and the arbitrator shall treat all proceedings under this provision and any documents, filings, statements of claim, testimony, transcripts, expert reports, and the decisions of the arbitrator as confidential and shall not disclose any of the foregoing to any person or entity except in connection with proceedings conducted under this provision. The parties may disclose any information, document, or record that is governed by this provision, including any arbitration award, as may be required by applicable law or as necessary to enforce an arbitration award.

19.           Amendment and Waiver. The provisions of this Agreement may be amended or waived only with the prior written consent of the Corporation and Executive, and no course of conduct or failure or delay in enforcing the provisions of this Agreement shall affect the validity, binding effect or enforceability of this Agreement.

20.           Section 409A Compliance.

(a)            The parties intend for this Agreement to either comply with, or be exempt from, Section 409A, and all provisions of this Agreement will be interpreted and applied accordingly. If any compensation or benefits provided by this Agreement may result in the application of Section 409A, the Corporation shall, in consultation with the Executive, modify the Agreement in the least restrictive manner necessary in order to exclude such compensation from the definition of “deferral of compensation” within the meaning of such Section 409A or in order to comply with the provisions of Section 409A and without any diminution in the value of the payments or benefits to the Executive. In no event, however, shall this paragraph 20 or any other provisions of this Agreement be construed to require the Corporation to provide any gross-up for the tax consequences of any provisions of, or payments under, this Agreement and the Corporation shall have no responsibility for tax consequences to Executive (or his beneficiary) resulting from the terms or operation of this Agreement. Any payments or reimbursements of any expenses provided for under this Agreement shall be made in accordance with Treas. Reg. §1.409A-3(i)(1)(iv).

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(b)            To the extent that any payment or benefit pursuant to this Agreement constitutes a “deferral of compensation” subject to Section 409A (after taking into account to the maximum extent possible any applicable exemptions) (a “409A Payment”) treated as payable upon Separation from Service, then, if on the date of the Executive’s Separation from Service, the Executive is a Specified Employee, then to the extent required for Executive not to incur additional taxes pursuant to Section 409A, no such 409A Payment shall be made to the Executive earlier than the earlier of (i) six (6) months after the Executive’s Separation from Service or (ii) the date of his death. Should this paragraph 20 result in payments or benefits to Executive at a later time than otherwise would have been made under this Agreement, on the first day any such payments or benefits may be made without incurring additional tax pursuant to Section 409A, the Corporation shall make such payments and provide such benefits as provided for in this Agreement. For purposes of this paragraph 20, the terms “Specified Employee” and “Separation from Service” shall have the meanings ascribed to them in Section 409A.

21.           Indemnification. Executive shall be entitled to the protections (including insurance coverage) afforded in the Director and Officer Indemnification Agreement, dated as of September 26, 2018, between Executive and the Corporation.

22.           Section 280G of the Code. In the event that any payments, distributions, benefits or entitlements of any type payable to Executive, whether or not payable upon a separation of Executive’s employment (“Payments”), (i) constitute “parachute payments” within the meaning of Section 280G of the Code, and (ii) but for this paragraph 22 would be subject to the excise tax imposed by Section 4999 of the Code (the “Excise Tax”), then the Payments shall be reduced to such lesser amount (the “Reduced Amount”) that would result in no portion of the Payments being subject to the Excise Tax; provided, however, that such Payments shall not be so reduced if a nationally recognized accounting firm selected by the Corporation in good faith (the “Accountants”) determines that without such reduction Executive would be entitled to receive and retain, on a net after-tax basis (including, without limitation, any excise taxes payable under Section 4999 of the Code, federal, state and local income taxes, social security and Medicare taxes and all other applicable taxes, determined by applying the highest marginal rate under Section 1 of the Code and under state and local tax laws which applied (or is likely to apply) to Executive’s taxable income for the tax year in which the transaction which causes the application of Section 280G of the Code occurs, or such other rate(s) as the Accountants determine to be likely to apply to Executive in the relevant tax year(s) in which any of the Payments are expected to be made), an amount that is greater than the amount, on a net after-tax basis, that Executive would be entitled to retain upon receipt of the Reduced Amount. Unless the Corporation and Executive otherwise agree in writing, any determination required under this paragraph 22 shall be made in good faith by the Accountants in a timely manner and shall be binding on the parties absent manifest error. In the event of a reduction of Payments hereunder, the Payments shall be reduced in the order determined by the Accountants that results in the greatest economic benefit to Executive in a manner that would not result in subjecting Executive to additional taxation under Section 409A. For purposes of making the calculations required by this paragraph 22, the Accountants may make reasonable assumptions and approximations concerning applicable taxes and may rely on reasonable, good faith interpretations concerning the application of the Code, and other applicable legal authority. The Corporation and Executive shall furnish to the Accountants such information and documents as the Accountants may reasonably require in order to make a determination under this paragraph 22, and the Corporation shall bear the cost of all fees charged by the Accountants in connection with any calculations contemplated by this paragraph 22. To the extent requested by Executive, the Corporation shall cooperate with Executive in good faith in valuing, and the Accountants shall value, services to be provided by Executive (including Executive refraining from performing services pursuant to a covenant not to compete) before, on or after the date of the transaction which causes the application of Section 280G of the Code such that Payments in respect of such services may be considered to be “reasonable compensation” within the meaning of the regulations under Section 280G of the Code. Notwithstanding the foregoing, if the transaction which causes the application of Section 280G of the Code occurs at a time during which the Corporation qualifies under Section 2(a)(i) of Q&A-6 of Treasury Regulation Section 1.280G, upon the request of Executive, the Corporation shall use reasonable efforts to obtain the vote of equity holders described in Q&A-7 of Treasury Regulation Section 1.280G.

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

Corporation
By:	/s/ Thiti Mekavichai
Name: Thiti Mekavichai
Title: Director and President
Executive
/s/ Christopher Pungya Kalnin
Christopher Pungya Kalnin

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EXHIBIT A
RELEASE AGREEMENT

RELEASE AGREEMENT, dated as of _______________ (this “Agreement”), by and between BKV Corporation, a Delaware corporation (the “Corporation”) and Christopher Pungya Kalnin (“Executive”) (collectively, the “Parties”).

WHEREAS, Executive’s employment agreement with the Corporation, dated August 4, 2020 (as such employment agreement may be amended from time to time, the “Employment Agreement”), provides for certain post-separation payments and benefits to Executive pursuant to subparagraphs 6(b) or 6(c), as applicable, and under subparagraph 6(e), if applicable, thereof, subject to Executive executing and not revoking a release of claims against the Corporation and the Releasees (as defined below); and

WHEREAS, Executive desires, and the Corporation agrees, that the Corporation shall provide a release of claims with respect to Executive’s employment and his separation of employment pursuant to the Employment Agreement.

NOW, THEREFORE, in consideration of the mutual promises and obligations set forth in the Employment Agreement and this Agreement, and in consideration for the payments and benefits to be provided to Executive pursuant to subparagraph 6(b) or 6(c), as applicable, and under subparagraph 6(d), if applicable, of the Employment Agreement, and for other good and valuable consideration, the sufficiency of which is hereby recognized by the Parties, the Parties agree as follows:

1.             Separation of Employment. Executive acknowledges and agrees that his separation of employment with the Corporation and its subsidiaries and affiliates will occur effective _______________ (the “Separation Date”). As of the Separation Date, Executive will resign all positions he held as an officer, director or employee of the Corporation and its subsidiaries (the “Group Companies”), and will promptly execute such documents and take such actions as may be necessary or reasonably requested by the Corporation to effectuate or memorialize the resignation of such positions.

2.             Consideration. Executive and the Corporation each acknowledge that in consideration of Executive’s employment and in consideration for the payments set forth in the Employment Agreement that are subject to the release provision of subparagraph 6(i) of the Employment Agreement (the “Payments”), the following shall apply.

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3.             General Release of Claims. In exchange for the mutual promises set forth in this Agreement (including the Payments), Executive, on behalf of himself, his agents, attorneys, heirs, administrators, executors, assigns, and other representatives, and anyone acting or claiming on his or their joint or several behalf, hereby releases, waives, and forever discharges the Corporation, each Group Company, including, in each case, its past or present employees, officers, directors, trustees, board members, shareholders, agents, affiliates, parent entities, subsidiaries, successors, assigns, and other representatives, and anyone acting on their joint or several behalf (the “Releasees”), from any and all known and unknown claims, causes of action, demands, damages, costs, expenses, liabilities, or other losses that in any way arise from, grow out of, or are related to Executive’s employment with the Corporation or any of the Group Companies or his separation of employment therefrom. By way of example only and without limiting the immediately preceding sentence, Executive agrees that he is releasing, waiving, and discharging any and all claims against the Corporation and the Releasees under (a) any federal, state, or local employment law or statute, including, but not limited to Title VII of the Civil Rights Act(s) of 1964 and 1991, the Americans with Disabilities Act, the Age Discrimination in Employment Act (“ADEA”), Older Workers Benefit Protection Act (“OWBPA”), the Genetic Information Non-Discrimination Act (GINA), the Sarbanes-Oxley Act, or other applicable state civil rights law(s) or any other federal law, statute, ordinance, rule, regulation or executive order relating to employment and/or discrimination in employment, and/or any claims to attorneys’ fees or costs thereunder, (b) any claims for wrongful discharge, retaliatory discharge, negligent or intentional infliction of emotional distress, interference with contractual relations, personal, emotional or physical injury, fraud, defamation, libel, slander, misrepresentation, violation of public policy, invasion of privacy, or any other statutory or common law theory of recovery under any federal, state or municipal common law, or (c) any other federal, state or municipal law, statute, ordinance or common law doctrine affecting employment rights. Nothing herein shall be construed to prohibit Executive from filing a charge with the Equal Employment Opportunity Commission or the United States Securities and Exchange Commission Whistleblower unit or participating in investigations by those entities. However, Executive acknowledges that by signing this Agreement, Executive waives his right to seek individual remedies in any such action or accept individual remedies or monetary damages in any such action or lawsuit arising from such charges or investigations, including but not limited to, back pay, front pay, or reinstatement. Executive further agrees that if any person, organization, or other entity should bring a claim against the Releasees involving any matter covered by this Agreement, Executive will not accept any personal relief in any such action, including damages, attorneys’ fees, costs, and all other legal or equitable relief. Notwithstanding the generality of the foregoing, Executive does not release the following claims and rights: (i) claims for unemployment compensation or any state disability insurance benefits pursuant to the terms of applicable state law; (ii) claims to continued participation in certain of the Corporation’s group benefit plans pursuant to the terms and conditions of the Employment Agreement and Part 6 of Subtitle B of Title I of the Employee Retirement Income Security Act of 1974, as amended, and to any vested benefits to which he is entitled under any retirement plan of the Corporation that is intended to be qualified under Section 401(a) of the Internal Revenue Code of 1986, as amended, or under any equity-based plan or deferred compensation plan of the Corporation; (iii) Executive’s right, if any, to indemnification, advancement of expenses and the protections of any directors’ and officers’ liability policies of the Corporation, as set forth in paragraph 20 of the Employment Agreement; (iv) Executive’s rights to any payments or benefits due to him under paragraph 6 of the Employment Agreement (including under the applicable agreements referenced therein (to the extent provided in paragraph 6 of the Employment Agreement)); (v) any rights under this Agreement; and (vi) any claim that cannot lawfully be waived by private agreement.

4.             No Claims Filed. Executive affirms that, as of the date of execution of this Agreement, he has filed no lawsuit, charge, claim or complaint with any governmental agency, arbitral tribunal or arbitrator, or in any court against the Corporation or the Releasees.

5.             Employment Agreement Provisions. The provisions of paragraphs 7 (Competitive Activity; Confidentiality; Non-solicitation), 11 (Taxes), 12 (Notices), 17 (Governing Law) and 18 (Dispute Resolution; Arbitration) of the Employment Agreement are hereby expressly incorporated by reference.

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6.             Nondisclosure of Terms. Executive agrees that the existence, terms and conditions of this Agreement, and any and all underlying communications and negotiations in connection with or leading to this Agreement, are and shall remain confidential unless publicly filed. Except as specifically set forth in this paragraph 6, Executive shall not disclose the existence or terms of this Agreement in whole or in part to any individual or entity without prior written consent of the Corporation. Executive agrees that he will not disclose the existence or terms of this Agreement to any person except (a) to members of Executive’s immediate family and his professional advisors, who shall be advised of this confidentiality provision; (b) to the extent required by a final and binding court order or other compulsory process; (c) to any federal, state, or local taxing authority or to any other governmental or regulatory body if requested in an investigation; or (d) to the extent reasonably appropriate in connection with litigation over this Agreement. Upon Executive’s receipt of any order, subpoena or other compulsory process demanding production or disclosure of this Agreement, Executive agrees that, to the extent legally permitted, he will promptly notify the Corporation in writing of the requested disclosure, including the proposed date of the disclosure, the reason for the requested disclosure, and the identity of the individual or entity requesting the disclosure, at least ten (10) business days prior to the date that such disclosure is to be made or immediately upon receipt of the requested disclosure. Executive agrees not to oppose any action that the Corporation might take with respect to any such requested disclosure. Executive further agrees to instruct his counsel not to disclose to any person or entity, including potential or existing clients, the existence or terms of this Agreement. Notwithstanding the foregoing, nothing in this Agreement prevents Executive from providing, without prior notice to the Corporation, information to governmental authorities regarding possible legal violations or otherwise testifying or participating in any investigation or proceeding by any governmental authorities regarding possible legal violations, and for purpose of clarity Executive is not prohibited from providing information voluntarily to the United States Securities and Exchange Commission pursuant to Section 21F of the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder, as such law, rules and regulations may be amended from time to time.

7.             Future Cooperation. Executive agrees that, as reasonably requested for (a) the 12 months following the separation of his employment, he will (i) fully cooperate with the Corporation in effecting an orderly transition of his duties and (ii) without any additional compensation, respond to reasonable requests for information from the Corporation regarding matters that may arise in the Corporation’s business and (b) the three-year period following the separation of his employment, fully and completely cooperate with the Corporation, its advisors and its legal counsel with respect to any litigation that is pending against the Corporation and any claim or action that may be filed against the Corporation in the future. Such cooperation reflected in part (b) above shall include making himself available at reasonable times and places for interviews, reviewing documents, testifying in a deposition or a legal or administrative proceeding, and providing advice to the Corporation in preparing defenses to any pending or potential future claims against the Corporation. Any cooperation under this paragraph 7 shall be subject to Executive’s business and personal commitments and shall not require Executive to cooperate against his own legal interests or the legal interests of any future employer. The Corporation agrees to pay/reimburse Executive within thirty (30) days of receipt of an invoice for any reasonable expenses incurred as a result of his cooperation with the Corporation pursuant to this paragraph 7 including reasonable fees actually incurred by legal counsel for Executive if Executive believes separate counsel is reasonably necessary.

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8.             Assistance to Others. Executive agrees following the separation of his employment described in this Agreement, not to assist or cooperate, in any way, directly or indirectly, with any person, entity or group (other than the Equal Employment Opportunity Commission (EEOC) or other governmental agency) involved in any proceeding, inquiry or investigation of any kind or nature against or involving the Corporation or any of its Group Companies, except as required by law, subpoena or other compulsory process. Moreover, Executive agrees that to the extent he is compelled to cooperate with such third parties during the three-year period following such separation of employment, he shall disclose to the Corporation in advance that he intends to cooperate and shall disclose the manner in which he intends to cooperate. Further, Executive agrees that within three (3) days after such cooperation, he will offer to meet with representatives of the Corporation and disclose the information that he provided to the third party, to the extent permitted by law. Further, if Executive is legally required to appear or participate in any proceeding that involves or is brought against the Corporation or any of the Group Companies, within three years following such separation of employment, Executive agrees, unless prohibited by law, to disclose to the Corporation in advance what he plans to say or produce and otherwise cooperate fully with the Corporation or the Group Companies. Executive’s agreement not to provide assistance or cooperation shall not require Executive to refrain from assisting or cooperating with any future employer.

9.             ADEA/OWBPA Waiver & Acknowledgment. Insofar as this Agreement pertains to the release of Executive’s claims, if any, under the ADEA or other civil rights laws, Executive, pursuant to and in compliance with the rights afforded him under the Older Workers Benefit Protection Act: (a) is hereby advised to consult with an attorney before executing this Agreement; (b) is hereby afforded twenty-one (21) days to consider this Agreement (the “Consideration Period”); (c) may revoke this Agreement any time within the seven (7) day period following his execution of this Agreement (the “Revocation Period”) by providing written notice to the Corporation on or before 5:00 PM. Eastern Daylight Time on the seventh day after Executive signs this Agreement; (d) is hereby advised that this Agreement shall not become effective or enforceable until the seven (7) day Revocation Period has expired; and (e) is hereby advised that he is not waiving claims that may arise after the date on which he executes this Agreement. If this Agreement is revoked within the Revocation Period, the Corporation shall have no obligations under this Agreement, including the obligation to make the Payments. If this Agreement is not revoked by Executive within the Revocation Period, this Agreement will be effective and enforceable on the date immediately following the last day of the seven (7) day Revocation Period (the “Effective Date”). The offer to enter into this Agreement shall remain open for the twenty-one (21) day Consideration Period, after which time it shall be withdrawn.

10.           Severability. Whenever possible, each provision of this Agreement shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Agreement is held to be invalid or unenforceable in any respect under any applicable law, such invalidity or unenforceability shall not affect any other provision, but this Agreement shall be reformed, construed and enforced as if such invalid or unenforceable provision had never been contained herein.

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11.           Voluntary Execution. Executive acknowledges that he is executing this Agreement voluntarily and of his own free will and that he fully understands and intends to be bound by the terms of this Agreement. Further, Executive acknowledges that he received a copy of this Agreement on _______________, and has had an opportunity to carefully review this Agreement with his attorney prior to executing it or warrants that he chooses not to have an attorney review this Agreement prior to signing. Executive will be responsible for any attorneys’ fees incurred in connection with review of this Agreement by his attorneys.

12.           No Assignment of Claims. Executive hereby represents and warrants that he has not previously assigned or purported to assign or transfer to any person or entity any of the claims or causes of action herein released.

13.           Complete Agreement. This Agreement embodies the complete agreement and understanding between the Parties with respect to the subject matter hereof and supersedes and preempts any prior understandings, agreements or representations by or between the Parties, written or oral, which may have related to the subject matter hereof in any way. Any amendments, additions or other modifications to this Agreement must be done in writing and signed by both Parties.

14.           Counterparts. This Agreement may be executed in separate counterparts, each of which shall be deemed to be an original and both of which taken together shall constitute one and the same agreement.

15.           Successors and Assigns. This Agreement shall bind and inure to the benefit of and be enforceable by Executive, the Corporation and their respective heirs, executors, personal representatives, successors and assigns, except that neither Party may assign any rights or delegate any obligations hereunder without the prior written consent of the other Party. Executive hereby consents to the assignment by the Corporation of all of its rights and obligations hereunder to any successor to the Corporation by merger or consolidation or purchase of all or substantially all of the Corporation’s assets, provided such transferee or successor assumes the liabilities of the Corporation hereunder.

[SIGNATURES ON FOLLOWING PAGE]

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IN WITNESS WHEREOF, the parties hereto hereby certify that they have read this Agreement in its entirety and voluntarily executed it in the presence of competent witnesses, as of the date set forth under their respective signatures.

Corporation
By:	Date:
Name:
Title:
Executive
	Date:
Christopher Pungya Kalnin

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EX-10.20

Exhibit 10.20

BKV CORPORATION

EMPLOYMENT AGREEMENT

This Employment Agreement (the “Agreement”) is effective as of the 11th day of January, 2021 (“Effective Date”), regardless of the date the Agreement is executed, by and between BKV Corporation, a Delaware corporation (hereinafter referred to as “Employer” or “Company”), and John T. Jimenez (hereinafter referred to as “Employee” or “you”). Collectively, Employer and Employee shall be referred to as the “Parties.”

A. Employer desires to engage Employee in the position of Chief Financial Officer.

B. Employee is willing to be employed by Employer, and Employer is willing to employ Employee, on the terms and conditions set forth herein.

C. In consideration of the mutual covenants and promises of the Parties hereto, Employer and Employee agree as follows:

1.    Agreement to Employ and be Employed: Employer hereby agrees to employ Employee and Employee hereby accepts and agrees to such employment.

2.    At-Will Employment: Employee’s employment is at-will. Nothing in this Agreement guarantees Employee employment with Employer for any specific period of time. This means that, subject to the provisions of this Agreement, Employer may terminate employee at any time with no advance notice, procedure, or formality and for any lawful reason, with or without cause. Similarly, subject to the provisions of this Agreement, Employee may resign his employment at any time and for any reason. Your at-will employment relationship cannot be changed by any oral representation, written document or other conduct unless such change is specifically acknowledged in writing by an authorized executive of the Company.

3.    Description of Employee’s Duties: Employee will be employed as Chief Financial Officer. Employee’s job duties are set forth in Exhibit 1. The position is exempt from overtime under both state and federal laws and regulations. You will report to Christopher P. Kalnin and your primary office location will be at our offices in Denver, Colorado. Your start date will be April 16, 2021 (the “Start Date”). In addition, we also attach Colorado Overtime and Minimum Pay Standards Order 36.

4.    Manner of Performance of Employee’s Duties: Employee shall be a full-time employee of Employer, shall devote his best efforts and entire business time, attention, and services exclusively to the business and affairs of Employer, and shall perform his duties as set forth in Exhibit 1 with fidelity and to the best of his ability, experience, and talent. Employee shall also perform the duties of his position to the reasonable satisfaction of Employer.

Employee will not engage in the performance of services for any other business or entity during the term of this Agreement unless the performance of such services is approved by Employer in advance.

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Notwithstanding anything in this Section 4, or in any other provision of this Agreement to the contrary, Employer hereby approves Employee’s continued participation in, and service to, the business enterprise identified and described in Exhibit 2.

5.    Compensation: In consideration of the services to be provided by Employer during employment, Employer shall compensate Employee as follows:

a. During his employment, Employee shall receive the equivalent of an annual base salary of Three Hundred Fifty Thousand U.S. dollars ($350,000.00), less applicable payroll deductions and required taxes and withholdings (“Base Compensation”), with partial periods prorated. Employee’s Base Compensation shall be payable in equal periodic installments according to Employer’s customary payroll practice. The Base Compensation is based on and intended to compensate Employee for all hours worked.

b. During your employment, Employee may participate in Employer benefit plans and programs described in the attached Exhibit 3, to the extent that Employer maintains such plans or programs and in accordance with the eligibility and participation criteria applicable to each such plan or program. Employee acknowledges that the Employer has the right to change, modify, or eliminate benefits provided to its employees from time to time in Employer’s sole discretion without notice to employees. As such, Employee acknowledges and agrees that this Agreement does not create a specific entitlement to any particular benefits, and that Employee will receive benefits at the same level as other similarly situated employees of Employer.

c. During his employment, Employee may also, in Employer’s sole discretion, receive compensation each calendar year in addition to his Base Compensation. Such additional compensation will be paid, if at all, in the form of an Annual Target Bonus, which Employer intends to fall between 0 percent and 60 percent (0-60%) of the annual Base Compensation. The availability of any bonus will be determined based upon Employer’s performance and will take into account Employee’s individual effort and satisfactory achievement of established performance goals. Any such Annual Target Bonus (if any) will be paid to Employee, in full and subject to applicable tax, not later than March 15 of the calendar year following the calendar year during which Employee performed the services that gave rise to that Bonus. The bonus would be pro-rated based on your Start Date.

Nothing in this provision (c) is intended to guarantee Employee the payment of a bonus in any amount other than as described in provision (c).

d. Paid Time Off (PTO). PTO includes vacation, sick, personal time, etc. Employee is eligible to accrue up to thirty (30) days of PTO per year. Paid time off is accrued on a pro-rata basis at the rate of 9.234 hours/Bi-Weekly throughout the year. Under Employer’s policy, employees do not accrue PTO once they have earned their maximum paid time off hours per year. The accrual will resume once the amount of accrued PTO is less than the maximum possible accrual. Available PTO will automatically carry over into the new calendar year. Up to 10 days of accrued, unused paid time off will be paid out upon separation, unless otherwise required by law. Advanced but unaccrued paid time off will be deducted from an employee’s final paycheck, to the extent permitted by law and Employee hereby authorizes such deduction in accordance with applicable law and waives the right to presentment, notice and protest.

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e. Signing Bonus. The Company will pay you a signing bonus of $250,000, less lawful deductions and withholdings within thirty (30) days of your Start Date (the “Signing Bonus”).

f. Long Term Incentive. In addition, during your employment, subject to final management approval, you will also be eligible for the Company’s Long-Term Incentive Program (“LTIP”) pursuant to the terms of the LTIP and grant agreements to be provided separately to you once employed, which is estimated to equate to 618,000 share total over a four-year period with a par value of $0.01 and a current fair market value of $10.00 per share. In addition to the Signing Bonus, the availability of any bonus including any grant of LTIP, will be determined based upon the Company’s performance and will consider your individual effort and satisfactory achievement of established performance goals.

The compensation described in this Section 5 constitutes all compensation made available by Employer for the services of Employee. No other or additional compensation in any form will be considered or paid for during the period of this Agreement.

6.    Relocation: Employee shall be promptly reimbursed Employee for reasonable relocation costs incurred as described below to move residence and family, the aggregate of which is not to exceed $30,000. Covered costs include:

a. reasonable broker fees in connection with the sale of the existing family home, reasonable out-of-pocket fees and expenses, and transfer taxes, but not home sales tax;

b. packing and moving of all household goods and shipment of three automobiles based upon a competitive bid approved through the Company’s Human Resources department;

Covered expenses do not include other broker fees or mortgage financing fees in excess of two points, in connection with the purchase of a residence.

During an agreed Transition Period, Employee will be reimbursed for reasonable expenses associated with commuting, including two trips accompanied by partner/spouse for purposes of relocation-related planning, and for temporary housing and rental car expenses in accordance with the Company’s T&E Policy.

Relocation expenses must be incurred within twelve (12) months from January 1, 2021 and payment will include a full tax gross-up for taxes incurred on receipt of the reimbursements under this section.

7.    Confidentiality: Employee acknowledges that, in the course of performing and fulfilling his duties hereunder, she may have access to and be entrusted with nonpublic information belonging to, developed by, licensed by, or otherwise in the possession of, Employer or its clients. To protect such information, Employee agrees that she will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than Employer, any Confidential Information, as defined below, whether prepared by Employee or not. At the request of Employer, Employee agrees to deliver to Employer, at any time during his employment, or thereafter, all Confidential Information which she may possess or control.

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Employee shall be permitted to disclose Confidential Information if and to the extent disclosure of any part thereof is specifically required by law; provided, however, that in the event such disclosure is required by applicable law, Employee shall provide Employer with prompt written notice of such requirement, prior to making any disclosure, so that Employer may seek an appropriate protective order, and Employee only shall disclose information as necessary to comply with legal process. Moreover, in accordance with the Defend Trade Secrets Act (“DTSA”), an employee will not be held criminally or civilly liable under any federal or state trade secret law if an employee discloses a trade secret in confidence to federal, state, or local government officials, to his/her attorney solely for the purpose of reporting or investigating a suspected violation of law, or in a sealed complaint or other document filed in a lawsuit or other proceeding.  Further, an employee who files a lawsuit alleging retaliation by an employer for reporting a suspected violation of law may disclose the trade secret to his attorney and use the trade secret information in the court proceeding if the individual: (a) files the document containing the trade secret in a sealed court document and (b) does not disclose the trade secret, except pursuant to court order. The DTSA does not, however, offer protection from liability for individuals who access trade secrets by unlawful means.

Notwithstanding the foregoing, nothing in this Agreement is intended to prevent Employee from engaging in activity protected by the National Labor Relations Act, including engaging in discussion of concerns about working conditions or other concerted activities.

“Confidential Information” means any of Employer’s and its Affiliates’ confidential information including, without limitation, all provisions hereunder, any information, processes, plans, data calculations, software storage media or other compilation of information, patent, patent application, copyright, “know-how,” trade secrets, customer lists, details of client or consultant contracts, pricing policies, operational methods, marketing plans or strategies, product development techniques or plans, business acquisition plans, any portion or phase of any scientific or technical information, ideas, discoveries, designs, inventions, creative works, computer programs (including source of object codes), processes, formulae, improvements or other proprietary or intellectual property of the Employer, whether or not in written or tangible form, and whether or not registered or labeled as confidential, and including all files, records, manuals, books, catalogues, memoranda, notes, summaries, plans, reports, records, documents and other evidence thereof. The covenant in this Section 6 shall survive termination of this Agreement. “Affiliate” is defined as all parent, sister and subsidiary companies.

8.    Inventions, Ideas, and Other Intellectual Developments: In view of the purposes of Employer and the need to secure for the Employer and/or Interested Parties (defined below) their right to Intellectual Developments (defined below) related to the business of Employer and/or such Interested Party, Employee understands that Employer must be in a position to use, assign, and otherwise dispose of Intellectual Developments made by its staff members and employees. Accordingly, except for those items excluded by Section 12 below, Employee shall promptly disclose to Employer and, when requested, furnish to the Employer a complete record of every discovery, invention, improvement, innovation, design, analysis, reports, drawings, copyright, intellectual property right and other definite and useful idea or compilation of information of value (individually and collectively an “Intellectual Development”), which Employee may make or originate, individually or with others, at any time during the term of Employee’s employment by the Employer. Employee hereby assigns to the Employer or its nominee the entire rights throughout the world to such Intellectual Developments which relate to the current or potential business or activities of the Employer or any Interested Parties or which results from Employee’s work with Employer. The term “Interested Parties” means any person having a business relationship with the Company where the relationship gives rise to a claim by that person to some interest in Intellectual Developments made by employees and associates of the Employer or its Affiliates.

9.    Cooperation: Employee shall fully cooperate with Employer or its designees in securing, in the name of the Company or its designees, rights with respect to the Intellectual Developments described in Section 7 above, in all countries. Employee shall promptly execute all proper documents presented for signature and do all things reasonably required to enable Employer or its designees to accomplish the above, at any time during or after Employee’s employment.

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10.    Shop Rights and Holdover: Employee agrees that Employer or its designees shall be entitled to shop rights to any Intellectual Developments conceived or made by Employee that is not related to the Employer’s trade secrets and/or Confidential Information but conceived or made on Company time or with the use of Employer’s facilities or materials. Employee further agrees that any Intellectual Developments related to Employer’s trade secrets and/or Confidential Information described by Employee in a patent, service mark, trademark, or copyright application, disclosed by Employee in any manner to a third person, or created by Employee or Employee’s affiliates or any person with whom Employee has any business, financial or confidential relationship, within one (1) year after cessation of Employee’s employment with Employer for any reason, was conceived or made by Employee during Employee’s employment with Employer and is therefore the sole property of Employer or its designees.

11.    Information and Testimony: For a period of time up to five years from Employee’s last date of employment with Employer, Employee shall, without expense to Employee and at the cost of the Employer, give such true information and testimony at reasonable times and places, as mutually agreed upon by Employer and Employee, upon prior notice, under oath if requested, as may be requested by Employer or its designees relative to any Intellectual Development described in Section 7 above.

12.    Interest of the Employee: As to inventions, applications for patents, and copyrightable material in which Employee presently holds an interest and which are not subject to this Agreement:

Check One:

x Employee has no such property.

¨ Employee has described all such property in Section 12, below.

13.    Description of Inventions, Applications for Patents and Copyright Material Exempted in Section 11.

Employee to insert description of applicable inventions, patents and copyright material below.

By: _________________on__________________

                           ______________                       Date

14.    Restrictive Covenant: Because Employee will be provided with proprietary, confidential, and trade secret information, the Employee shall not, during his employment:

a. enter into, own, manage, operate, control, be employed with, or engage, as an employee, associate, officer, director, shareholder, partner or in any other capacity, on behalf of any association, enterprise, company, or firm that provides services or products in competition with Employer, except as otherwise provided in Exhibit 2 to this Agreement;

b. directly or indirectly solicit or attempt to solicit the business of any client or customer or active customer prospect of the Employer or any of its Affiliates for his own benefit or that of any third person or organization; and

c. directly or indirectly induce any employee or contractor of Employer or any of its Affiliates to leave his or his employment or independent contract with Employer or any of its Affiliates.

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15.    Non-Disparagement: Employee agrees that at any time during his employment with the Employer and at any time thereafter, Employee shall not, except in the good faith commission of his duties and responsibilities, make, or cause or assist any other person to make, any statement or other communication that impugns or attacks, or is otherwise critical to the reputation, business or character of the Employer or any of its officers, directors, members, managers, employees, products or services.

16.    Reasonableness of Restraints, Irreparable Harm: Employee acknowledges that: (a) the agreements and covenants contained herein are reasonably necessary to protect the goodwill, Confidential Information, Intellectual Developments, trade secrets, and other business interests of Employer; (b) any breach of the covenants contained herein will cause Employer immediate irreparable harm for which injunctive relief would be necessary; (c) the covenants contained herein are essential and material elements of this Agreement and Employer would not have entered into this Agreement or permitted Employee to obtain employment or remain employed without those covenants being included in this Agreement; (d) Employee has had the opportunity to consult with and be advised by legal counsel concerning the reasonableness and propriety of the covenants contained herein; and (e) in the event of any violation or attempted violation of the covenants contained herein, Employer shall be entitled to seek a temporary restraining order, temporary or permanent injunctions, and other injunctive relief, , in addition to any other rights or remedies which may then be available to Employer. In addition to, but not instead of, any other legal or equitable remedies available to Employer, Employee hereby agrees to reimburse Employer for reasonable attorneys’ fees and costs incurred by Employer in the event Employer is successful in showing a violation or attempted violation of this Agreement as determined by a court of competent jurisdiction.

17.    No Existing Obligations: Except for and expressly excluding the obligations, terms and conditions set forth in the employment materials, including without limitation, any employee handbook, award agreement or offer materials, of BP America Production Company, its affiliates, group companies or parent companies including, but not limited to, the language set forth on Appendix A attached hereto and the notice, if any, associated therewith, Employee represents that Employee: (a) is not subject to a confidentiality, trade secret, conflict of interest, or non-competition agreement with any former employer, contractor or third party; and (b) has no continuing obligations to any former employer, contractor or third party with respect to the ownership or assignment of any proprietary rights, including, but not limited to, inventions, ideas, copyrights, trade secrets or patents, including any such rights in information, or creations or materials Employee conceived or made, in whole or in part that will impact Employee’s services for Employer. Employee understands that any such agreement or obligation, as well as any trade secret and other property laws, may restrict Employee from using any secret or proprietary information that belongs to any former employer, contractor or third party, either for Employee’s own benefit or for anyone else’s benefit, including Employer. Employee also understands that Employee, or anyone else who uses or benefits from a third party’s proprietary information, may be liable to that third party; therefore, Employee agrees not to use any confidential, trade secret, or proprietary information that belongs to any former employer, contractor, or third party during the term of employment, either for Employee’s own benefit or to benefit Employer or any of its clients, customers, or affiliates.

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18.    Termination of Employment and Termination Payment. Notwithstanding the at-will nature of your employment, if your employment is terminated by the Company without “Cause” as defined below, in addition to the (1) payment of your Base Compensation and any bonuses earned through the termination date, (2) payment for any unused, accrued vacation days as of your termination date, and (3) reimbursement of any outstanding, reasonable business expenses incurred by you through the termination date, you will be eligible to receive a severance benefit equal to the sum of eighteen (18) months of your annual Base Compensation as of the date of termination, provided you execute a Separation Agreement and General Release provided by the Company (the “Separation Agreement”). For purposes of this letter, the term “Cause” shall mean any of the following: (i) other than as a result of a disability, your willful failure to perform your duties; (ii) your willful engagement in misconduct which is injurious to the Company, monetarily or otherwise; (iii) your conviction of a crime (including a nolo contendere plea) involving, in the good faith of the Company, fraud, dishonesty or moral turpitude; (iv) the negligent performance of your duties after receipt of written notice from Employer and a reasonable opportunity to cure; (v) your breach of any covenant set forth in the Confidential Information and Non-Solicitation Agreement; or (vi) your breach of any material Company policy. You will be considered to have been terminated for “Cause” if the Company determines in good faith that you engaged in an act constituting “Cause” even after a resignation by you.

19.    Non-Competition. In exchange for the termination payment described in Section 18 above, for a period of twelve (12) months following termination of Employee’s employment, for any reason, Employee shall not (1) enter into or engage in any business which competes with the Company or any of its subsidiaries or affiliates (“Company Group”) in the same primary business as the Company Group within the States of Pennsylvania, Colorado and Texas (“Restricted Territory”); (2) solicit any known customers, business, assets, investments or patronage (or customer, business, asset, investment or patronage prospects) for, or sell, any products or services in competition with or for any business that competes with the Company Group within the Restricted Territory; (3) divert, entice or otherwise take away any known business, assets or investments or patronage (or customer, business, asset, investment or patronage prospects) of the Company Group within the Restricted Territory; or (4) promote, manage or assist, financially or otherwise, any person, firm, association, partnership, corporation or other entity engaged in any business which competes with or is engaged in the same business as the Company Group within the Restricted Territory. For purposes of this section, Employee will be in violation of the non-compete provision set forth herein if Employee engages in any or all of the activities set forth herein directly as an individual on Employee’s own account or indirectly as a partner, joint venture, employee, agent, salesperson, consultant, officers and/or director of any firm, association, partnership, corporation or other entity or as a shareholder of any corporation (or owner of any other type of equity interest in any other entity) in which Employee or Employee’s spouse, minor child, or parent sharing the same household as Employee owns, directly or indirectly, individually or in the aggregate, more than 1% of the outstanding stock or other equity interests. If it is judicially determined or by consent of Employee that Employee has violated this Section 19 and the Company obtains an order, injunction or other equitable relief, then the period applicable to each obligation that Employee has been determined to have violated will be automatically extended by a period of time equal in length to the period during which such violation occurred.

20.    Termination Notice. Your employment may be terminated in writing either by the Company without Cause or by you upon ninety (90) days written notice to the Company. If the Company terminates your employment without Cause, 90 days’ notice is not required by the Company, provided that it offers to pay you the severance benefits described in this letter in exchange for you signing a Separation Agreement and General Release. For purposes of clarity, no prior notice is required to terminate your employment by the Company with Cause.

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21.    Internal Revenue Code Section 409A Compliance. Both you and the Company intend that all compensation or benefits paid under this letter as well as the Separation Agreement comply with Internal Revenue Code Section 409A and the regulations and guidance promulgated thereunder (collectively “Section 409A”) and, accordingly, to the maximum extent permitted, this letter shall be interpreted to be in compliance therewith. By way of example, and not limitation, with respect to payments triggered by your “termination of employment” (and similar terms) such phrase shall be construed to mean your “separation from service” with the Company (determined under Treasury Regulation Section 1.409A-1(h)). Further, notwithstanding any other provision of this letter to the contrary, if any amount to be paid to you as a result of the termination of your employment pursuant to this letter or the Separation Agreement is “deferred compensation” subject to Section 409A, and if you are a “specified employee” (as defined under Section 409A) as of the date of your termination of employment hereunder, then, to the extent necessary to avoid the imposition of excise taxes or other penalties under Section 409A, the payment of benefits, if any, scheduled to be paid by the Company to you hereunder during the first six (6) month period following the date of a termination of employment hereunder shall not be paid until the date which is the first business day following the six-month anniversary of the termination of your employment, as reviewed and approved by Employer’s CFO or tax professional, for any reason other than death. Any deferred compensation payments delayed in accordance with the terms of this paragraph shall be paid in a lump sum when paid. In addition, both you and the Company agree to cooperate fully with one another to attempt to ensure compliance with Section 409A, including, without limitation, adopting amendments to arrangements subject to Section 409A and operating such arrangements in compliance with Section 409A; provided, however, nothing in this paragraph shall require you to reduce your compensation; provided, further, however, nothing in this letter shall constitute an agreement to indemnify, gross up or otherwise make you whole for any taxes imposed under Section 409A. The Company does not make any representation as to whether any benefits, payments, or reimbursements under this letter satisfy the requirements of Section 409A or any exemption thereto.

22.    Assignment: This Agreement may be assigned by Employer to any affiliated or successor employer without the consent of Employee, and so long as the affiliate or successor accepts the assignment, this Agreement will continue to be binding upon the Employee. This Agreement may not be assigned by Employee.

23.    Severability: Each paragraph of this Agreement shall be and remain separate from and independent of, and severable from, all and any other paragraphs herein except where otherwise indicated by the context of the Agreement. To the extent any portion of this Agreement, or any portion of any provision of this Agreement is held to be invalid or unenforceable, it is the Parties’ express intent it shall be construed by severing, limiting and reducing it so as to be enforceable to the extent compatible with applicable law. All remaining provisions, and/or portions thereof, shall remain in full force and effect.

24.    Modification: Any modification of this Agreement or any additional obligation assumed by either Party in connection with this Agreement shall be in writing and signed by each Party.

25.    No Waiver: The failure of either Party to this Agreement to insist upon the performance of any terms and conditions or the waiver of any breach of any terms and conditions of this Agreement shall not be construed as thereafter waiving such terms and conditions, but the same shall continue to remain in full force and effect.

26.    Complete Agreement: This Agreement contains the complete agreement concerning the employment agreement between the Parties and supersedes any and all prior understandings and agreements between the Parties concerning the subject matter hereof. The Parties stipulate that neither has made any representation with respect to the subject matter of this Agreement except such representations as are specifically set forth in this Agreement.

27.    Interpretation of Agreement: The validity, interpretation, construction, and performance of this Agreement shall be governed by the laws of the State of Colorado, without regard to its conflict of law provisions. This Agreement shall be interpreted with all necessary changes in gender and in number as the context may require and shall inure to the benefit of and be binding upon the respective successors and assigns of the parties hereto.

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28.    Survival: The terms and provisions of Sections 6 through 14 of this Agreement shall survive the cancellation, termination, or expiration of this Agreement.

29.    Resolution of Disputes: The parties consent and agree that, except as set forth in this Section 24, any action or proceeding between them arising from this Agreement shall be exclusively referred to binding arbitration in Denver, Colorado in accordance with the rules of the Commercial Arbitration (“AAA”) Rules and Mediation Procedures before a single arbitrator selected by the Employer. The decision of the arbitrator shall be final, non-appealable and binding upon the parties and may be enforced in any court having jurisdiction thereof. The AAA Rules regarding discovery shall apply to arbitration under this Agreement. The Arbitrator selected according to this Agreement shall decide all discovery disputes. The parties shall split the administrative cost of arbitration equally and each party shall be responsible for the payment of its own respective legal fees. Claims where mandatory arbitration is prohibited by a valid non-preempted law are explicitly excluded from this Arbitration provision. CLAIMS IN ARBITRATION SHALL BE FILED AND MAINTAINED ONLY ON AN INDIVIDUAL BASIS. EMPLOYEE MAY NOT FILE OR MAINTAIN ANY CLAIM IN ARBITRATION ON BEHALF OF OTHERS, COLLECTIVELY OR OTHERWISE, OR AS A NAMED PLAINTIFF/CLAIMANT OR MEMBER IN ANY PURPORTED CLASS, COLLECTIVE, OR REPRESENTATIVE PROCEEDING. THE ARBITRATOR MAY NOT CONSOLIDATE MORE THAN ONE PARTY’S CLAIMS, AND MAY NOT OTHERWISE PRESIDE OVER ANY FORM OF A COLLECTIVE, CLASS, OR REPRESENTATIVE ARBITRATION PROCEEDING. Notwithstanding the foregoing, any claim related to Sections 6 through 14 of this Agreement shall be asserted exclusively in the state or federal courts of the State of Colorado, and Employee hereby expressly consents to the jurisdiction thereof.

30.    Notice: Notice shall be provided in writing via certified mail (return receipt requested), overnight courier or personal delivery to the address set forth below.

If to Employer:	If to Employee:
BKV Corporation
Attn: Christopher P. Kalnin	John T. Jimenez
1200 17th Street, Suite 2100	[***]
Denver, CO 80202	[***]
Email: [***]	Email: [***]

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IN WITNESS WHEREOF, the Parties have executed this Employment Agreement on the date or dates set forth below.

/s/ John T. Jimenez		/s/ Christopher P. Kalnin
John T. Jimenez		Christopher P. Kalnin, CEO
		BKV Corporation
Date:	January 8, 2021	Date:	January 8, 2021

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EXHIBIT 1

Exempt

Full-time Position

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EXHIBIT 2

Employee’s Existing Business Enterprises

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EXHIBIT 3

Summary of Benefits Currently Offered by

BKV Corporation (“Employer”)

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EX-10.21

Exhibit 10.21

KALNIN VENTURES, LLC

EMPLOYMENT AGREEMENT

This Employment Agreement (the “Agreement”) is effective as of the 18^th day of February, 2020 (“Effective Date”), regardless of the date the Agreement is executed, by and between Kalnin Ventures, LLC, a Delaware limited liability company (hereinafter referred to as “Employer”), and Eric Jacobsen, [***] (hereinafter referred to as “Employee”). Collectively, Employer and Employee shall be referred to as the “Parties.”

A. Employer desires to engage Employee in the position of Chief Operating Officer, based in Denver, Colorado, provided Employee’s work will be focused upon the Company’s assets and operations which are currently located in Pennsylvania and Texas.

B. Employee is willing to be employed by Employer, and Employer is willing to employ Employee, on the terms and conditions set forth herein.

C. In consideration of the mutual covenants and promises of the Parties hereto, Employer and Employee agree as follows:

1.     Agreement to Employ and be Employed: Employer hereby agrees to employ Employee and Employee hereby accepts and agrees to such employment.

2.     At-Will Employment: Employee’s employment is at-will. Nothing in this Agreement guarantees Employee employment with Employer for any specific period. This means that, subject to the provisions of this Agreement, Employer may terminate employee at any time with no advance notice, procedure, or formality and for any lawful reason. Similarly, subject to the provisions of this Agreement, Employee may resign his employment at any time and for any reason.

3.     Description of Employee’s Duties: Employee will be employed as Chief Operating Officer. Employee’s job duties are set forth in Exhibit 1. The position is exempt from overtime under both state and federal laws and regulations.

4.     Manner of Performance of Employee’s Duties: Employee shall be a full-time employee of Employer, shall devote his best efforts and entire business time, attention, and services exclusively to the business and affairs of Employer, and shall perform his duties as set forth in Exhibit 1 with fidelity and to the best of his ability, experience, and talent. Employee shall also perform the duties of his position to the reasonable satisfaction of Employer.

Employee will not engage in the performance of services for any other business or entity during the term of this Agreement unless the performance of such services is approved by Employer in advance.

Notwithstanding anything in this Section 4, or in any other provision of this Agreement to the contrary, Employer hereby approves Employee’s continued participation in, and service to, the business enterprise identified and described in Exhibit 2.

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5.     Compensation: In consideration of the services to be provided by Employer during employment, Employer shall compensate Employee as follows:

a. During his employment, Employee shall receive the equivalent of an annual base salary of Four Hundred Thousand U.S. Dollars ($400,000.00), less applicable payroll deductions and required taxes and withholdings (“Base Compensation”), with partial periods prorated. Employee’s Base Compensation shall be payable in equal periodic installments according to Employer’s customary payroll practice. The Base Compensation is based on and intended to compensate Employee for all hours worked.

b. During his employment, Employee may participate in Employer benefit plans and programs described in the attached Exhibit 3, to the extent that Employer maintains such plans or programs and in accordance with the eligibility and participation criteria applicable to each such plan or program. Employee acknowledges that the Employer has the right to change, modify, or eliminate benefits provided to its employees from time to time in Employer’s sole discretion without notice to employees. As such, Employee acknowledges and agrees that this Agreement does not create a specific entitlement to any benefits, and that Employee will receive benefits at the same level as similarly situated employees of Employer.

c. During his employment, Employee may also, in Employer’s sole discretion, receive compensation each calendar year in addition to his Base Compensation. Such additional compensation will be paid, if at all, in the form of an Annual Target Bonus, which Employer intends to fall between 0 percent and 40 percent (0-40%) of the annual Base Compensation. The availability of any bonus will be determined based upon Employer’s performance and will consider Employee’s individual effort and satisfactory achievement of established performance goals. Any such Annual Target Bonus (if any) will be paid to Employee, in full and subject to applicable tax, not later than March 15 of the calendar year following the calendar year during which Employee performed the services that gave rise to that Bonus. The bonus would be pro-rated based on your hire date.

Nothing in this provision (c) is intended to guarantee Employee the payment of a bonus in any amount other than as described in provision (c).

d. Paid Time Off (PTO). PTO includes vacation, sick, personal time, etc. Employee is eligible to accrue up to 25 days of PTO per year. Paid time off is accrued on a pro-rata basis at the rate of 2.08 days/Bi-Weekly throughout the year. Under Employer’s policy, employees do not accrue PTO once they have earned their maximum paid time off hours per year. The accrual will resume once the amount of accrued PTO is less than the maximum possible accrual. Available PTO will automatically carry over into the new calendar year. Up to 10 days of accrued, unused paid time off will be paid out upon separation, unless otherwise required by law. Advanced but unaccrued paid time off will be deducted from an employee’s final paycheck, to the extent permitted by law and Employee hereby authorizes such deduction in accordance with applicable law and waives the right to presentment, notice and protest.

e. Severance. In the event Employee is terminated without cause, as determined by the Company in good faith, Employee shall receive severance in an amount equal to three (3) months of Employee’s salary as stated in this Agreement (“Severance Amount”) with payment of such Severance Amount to be paid by Company to Employee within 30 days after termination of Employee’s employment with Company.

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The compensation described in this Section 5 constitutes all compensation made available by Employer for the services of Employee. No other or additional compensation in any form will be considered or paid for during the period of this Agreement.

6.     Confidentiality: Employee acknowledges that, in the course of performing and fulfilling his duties hereunder, he may have access to and be entrusted with nonpublic information belonging to, developed by, licensed by, or otherwise in the possession of, Employer or its clients. To protect such information, Employee agrees that he will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than Employer, any Confidential Information, as defined below, whether prepared by Employee or not. At the request of Employer, Employee agrees to deliver to Employer, at any time during his employment, or thereafter, all Confidential Information which he may possess or control.

Employee shall be permitted to disclose Confidential Information if and to the extent disclosure of any part thereof is specifically required by law; provided, however, that in the event such disclosure is required by applicable law, Employee shall provide Employer with prompt written notice of such requirement, prior to making any disclosure, so that Employer may seek an appropriate protective order, and Employee only shall disclose information as necessary to comply with legal process. Moreover, in accordance with the Defend Trade Secrets Act (“DTSA”), an employee will not be held criminally or civilly liable under any federal or state trade secret law if an employee discloses a trade secret in confidence to federal, state, or local government officials, to his/his attorney solely for the purpose of reporting or investigating a suspected violation of law, or in a sealed complaint or other document filed in a lawsuit or other proceeding.  Further, an employee who files a lawsuit alleging retaliation by an employer for reporting a suspected violation of law may disclose the trade secret to his attorney and use the trade secret information in the court proceeding if the individual: (a) files the document containing the trade secret in a sealed court document and (b) does not disclose the trade secret, except pursuant to court order. The DTSA does not, however, offer protection from liability for individuals who access trade secrets by unlawful means.

Notwithstanding the foregoing, nothing in this Agreement is intended to prevent Employee from engaging in activity protected by the National Labor Relations Act, including engaging in discussion of concerns about working conditions or other concerted activities.

“Confidential Information” means any of Employer’s and its Affiliates’ confidential information including, without limitation, all provisions hereunder, any information, processes, plans, data calculations, software storage media or other compilation of information, patent, patent application, copyright, “know-how,” trade secrets, customer lists, details of client or consultant contracts, pricing policies, operational methods, marketing plans or strategies, product development techniques or plans, business acquisition plans, any portion or phase of any scientific or technical information, ideas, discoveries, designs, inventions, creative works, computer programs (including source of object codes), processes, formulae, improvements or other proprietary or intellectual property of the Employer, whether or not in written or tangible form, and whether or not registered or labeled as confidential, and including all files, records, manuals, books, catalogues, memoranda, notes, summaries, plans, reports, records, documents and other evidence thereof. The covenant in this Section 6 shall survive termination of this Agreement. “Affiliate” is defined as all parent, sister and subsidiary companies.

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7.     Inventions, Ideas, and Other Intellectual Developments: In view of the purposes of Employer and the need to secure for the Employer and/or Interested Parties (defined below) their right to Intellectual Developments (defined below) related to the business of Employer and/or such Interested Party, Employee understands that Employer must be in a position to use, assign, and otherwise dispose of Intellectual Developments made by its staff members and employees. Accordingly, except for those items excluded by Section 12 below, Employee shall promptly disclose to Employer and, when requested, furnish to the Employer a complete record of every discovery, invention, improvement, innovation, design, analysis, reports, drawings, copyright, intellectual property right and other definite and useful idea or compilation of information of value (individually and collectively an “Intellectual Development”), which Employee may make or originate, individually or with others, at any time during the term of Employee’s employment by the Employer. Employee hereby assigns to the Employer or its nominee the entire rights throughout the world to such Intellectual Developments which relate to the current or potential business or activities of the Employer or any Interested Parties or which results from Employee’s work with Employer. The term “Interested Parties” means any person having a business relationship with the Company where the relationship gives rise to a claim by that person to some interest in Intellectual Developments made by employees and associates of the Employer or its Affiliates.

8.     Cooperation: Employee shall fully cooperate with Employer or its designees in securing, in the name of the Company or its designees, rights with respect to the Intellectual Developments described in Section 7 above, in all countries. Employee shall promptly execute all proper documents presented for signature and do all things reasonably required to enable Employer or its designees to accomplish the above, at any time during or after Employee’s employment.

9.     Shop Rights and Holdover: Employee agrees that Employer or its designees shall be entitled to shop rights to any Intellectual Developments conceived or made by Employee that is not related to the Employer’s trade secrets and/or Confidential Information but conceived or made on Company time or with the use of Employer’s facilities or materials. Employee further agrees that any Intellectual Developments related to Employer’s trade secrets and/or Confidential Information described by Employee in a patent, service mark, trademark, or copyright application, disclosed by Employee in any manner to a third person, or created by Employee or Employee’s affiliates or any person with whom Employee has any business, financial or confidential relationship, within one (1) year after cessation of Employee’s employment with Employer for any reason, was conceived or made by Employee during Employee’s employment with Employer and is therefore the sole property of Employer or its designees.

10.   Information and Testimony: For a period of time up to five years from Employee’s last date of employment with Employer, Employee shall, without expense to Employee, give such true information and testimony at reasonable times and places upon prior notice, under oath if requested, as may be requested by Employer or its designees relative to any Intellectual Development described in Section 7 above.

11.   Interest of the Employee: As to inventions, applications for patents, and copyrightable material in which Employee presently holds an interest and which are not subject to this Agreement:

Check One:

x Employee has no such property. 

¨ Employee has described all such property in Section 12, below.

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12.   Description of Inventions, Applications for Patents and Copyright Material Exempted in Section 11.

Employee to insert description of applicable inventions, patents and copyright material below.

By: _________________on__________________ 

______________                                  Date

13.   Restrictive Covenant: Because Employee will be provided with proprietary, confidential, and trade secret information, the Employee shall not, during his employment:

a. enter into, own, manage, operate, control, be employed with, or engage, as an employee, associate, officer, director, shareholder, partner or in any other capacity, on behalf of any association, enterprise, company, or firm that provides services or products in competition with Employer, except as otherwise provided in Exhibit 2 to this Agreement;

b. directly or indirectly solicit or attempt to solicit the business of any client or customer or active customer prospect of the Employer or any of its Affiliates for his own benefit or that of any third person or organization; and

c. directly or indirectly induce any employee or contractor of Employer or any of its Affiliates to leave his or his employment or independent contract with Employer or any of its Affiliates.

14.   Non-Disparagement: Employee agrees that at any time during his employment with the Employer and at any time thereafter, Employee shall not, except in the good faith commission of his duties and responsibilities, make, or cause or assist any other person to make, any statement or other communication that impugns or attacks, or is otherwise critical to the reputation, business or character of the Employer or any of its officers, directors, members, managers, employees, products or services.

15.   Reasonableness of Restraints, Irreparable Harm: Employee acknowledges that: (a) the agreements and covenants contained herein are reasonably necessary to protect the goodwill, Confidential Information, Intellectual Developments, trade secrets, and other business interests of Employer; (b) any breach of the covenants contained herein will cause Employer immediate irreparable harm for which injunctive relief would be necessary; (c) the covenants contained herein are essential and material elements of this Agreement and Employer would not have entered into this Agreement or permitted Employee to obtain employment or remain employed without those covenants being included in this Agreement; (d) Employee has had the opportunity to consult with and be advised by legal counsel concerning the reasonableness and propriety of the covenants contained herein; and (e) in the event of any violation or attempted violation of the covenants contained herein, Employer shall be entitled to a temporary restraining order, temporary or permanent injunctions, and other injunctive relief, without any showing of irreparable harm or damage or any need to post a bond, in addition to any other rights or remedies which may then be available to Employer. In addition to, but not instead of, any other legal or equitable remedies available to Employer, Employee hereby agrees to reimburse Employer for reasonable attorneys’ fees and costs incurred by Employer in the event Employer is successful in showing a violation or attempted violation of this Agreement as determined by a court of competent jurisdiction.

16.   No Existing Obligations: Employee represents that Employee: (a) is not subject to a confidentiality, trade secret, conflict of interest, or non-competition agreement with any former employer, contractor or third party, except for the Separation and General Release Agreement in Exhibit 4; and (b) has no continuing obligations to any former employer, contractor or third party with respect to the ownership or assignment of any proprietary rights, including, but not limited to, inventions, ideas, copyrights, trade secrets or patents, including any such rights in information, or creations or materials Employee conceived or made, in whole or in part that will impact Employee’s services for Employer. Employee understands that any such agreement or obligation, as well as any trade secret and other property laws, may restrict Employee from using any secret or proprietary information that belongs to any former employer, contractor or third party, either for Employee’s own benefit or for anyone else’s benefit, including Employer. Employee also understands that Employee, or anyone else who uses or benefits from a third party’s proprietary information, may be liable to that third party; therefore, Employee agrees not to use any confidential, trade secret, or proprietary information that belongs to any former employer, contractor, or third party during the term of employment, either for Employee’s own benefit or to benefit Employer or any of its clients, customers, or affiliates.

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17.   Assignment: This Agreement may be assigned by Employer to any affiliated or successor employer without the consent of Employee, and so long as the affiliate or successor accepts the assignment, this Agreement will continue to be binding upon the Employee. This Agreement may not be assigned by Employee.

18.  Severability: Each paragraph of this Agreement shall be and remain separate from and independent of, and severable from, all and any other paragraphs herein except where otherwise indicated by the context of the Agreement. To the extent any portion of this Agreement, or any portion of any provision of this Agreement is held to be invalid or unenforceable, it is the Parties’ express intent it shall be construed by severing, limiting and reducing it so as to be enforceable to the extent compatible with applicable law. All remaining provisions, and/or portions thereof, shall remain in full force and effect.

19.   Modification: Any modification of this Agreement or any additional obligation assumed by either Party in connection with this Agreement shall be in writing and signed by each Party.

20.   No Waiver: The failure of either Party to this Agreement to insist upon the performance of any terms and conditions or the waiver of any breach of any terms and conditions of this Agreement shall not be construed as thereafter waiving such terms and conditions, but the same shall continue to remain in full force and effect.

21.   Complete Agreement: This Agreement contains the complete agreement concerning the employment agreement between the Parties and supersedes any and all prior understandings and agreements between the Parties concerning the subject matter hereof. The Parties stipulate that neither has made any representation with respect to the subject matter of this Agreement except such representations as are specifically set forth in this Agreement.

22.   Interpretation of Agreement: The validity, interpretation, construction, and performance of this Agreement shall be governed by the laws of the State of Colorado, without regard to its conflict of law provisions. This Agreement shall be interpreted with all necessary changes in gender and in number as the context may require and shall inure to the benefit of and be binding upon the respective successors and assigns of the parties hereto.

23.   Survival: The terms and provisions of Sections 6 through 14 of this Agreement shall survive the cancellation, termination, or expiration of this Agreement.

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24.   Resolution of Disputes: The parties consent and agree that, except as set forth in this Section 24, any action or proceeding between them arising from this Agreement shall be exclusively referred to binding arbitration in Denver, Colorado in accordance with the rules of the Commercial Arbitration (“AAA”) Rules and Mediation Procedures before a single arbitrator selected by the Employer. The decision of the arbitrator shall be final, non-appealable and binding upon the parties and may be enforced in any court having jurisdiction thereof. The AAA Rules regarding discovery shall apply to arbitration under this Agreement. The Arbitrator selected according to this Agreement shall decide all discovery disputes. The parties shall split the administrative cost of arbitration equally and each party shall be responsible for the payment of its own respective legal fees. Claims whise mandatory arbitration is prohibited by a valid non-preempted law are explicitly excluded from this Arbitration provision. CLAIMS IN ARBITRATION SHALL BE FILED AND MAINTAINED ONLY ON AN INDIVIDUAL BASIS. EMPLOYEE MAY NOT FILE OR MAINTAIN ANY CLAIM IN ARBITRATION ON BEHALF OF OTHISS, COLLECTIVELY OR OTHISWISE, OR AS A NAMED PLAINTIFF/CLAIMANT OR MEMBER IN ANY PURPORTED CLASS, COLLECTIVE, OR REPRESENTATIVE PROCEEDING. THE ARBITRATOR MAY NOT CONSOLIDATE MORE THAN ONE PARTY’S CLAIMS, AND MAY NOT OTHISWISE PRESIDE OVER ANY FORM OF A COLLECTIVE, CLASS, OR REPRESENTATIVE ARBITRATION PROCEEDING. Notwithstanding the foregoing, any claim related to Sections 6 through 14 of this Agreement shall be asserted exclusively in the state or federal courts of the State of Colorado, and Employee hereby expressly consents to the jurisdiction thereof.

25.   Notice: Notice shall be provided in writing via certified mail (return receipt requested), overnight courier or personal delivery to the address set forth below.

If to Employer:	If to Employee:
Kalnin Ventures, LLC
Attn: Christopher P. Kalnin	Eric Jacobsen
1200 17th Street, Suite 2100	[***]
Denver, CO 80202	[***]
Email: [***]	Email: [***]

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IN WITNESS WHEREOF, the Parties have executed this Employment Agreement on the date or dates set forth below.

/s/ Christopher P. Kalnin	/s/ Eric Jacobsen
Christopher P. Kalnin, CEO	Eric Jacobsen
Kalnin Ventures, LLC

Date: February 11, 2020 Date: February 10, 2020

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EXHIBIT 1

Exempt 

Full-time Position

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EXHIBIT 2

Employee’s Existing Business Enterprises

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EXHIBIT 3

Summary of Benefits Currently Offered by 

Kalnin Ventures, LLC (“Employer”)

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EX-10.22

Exhibit 10.22

BKV CORPORATION

EMPLOYMENT AGREEMENT

This Employment Agreement (the “Agreement”) is effective as of the 15^th day of January, 2021 (“Effective Date”), regardless of the date the Agreement is executed, by and between BKV Corporation, a Delaware corporation (hereinafter referred to as “Employer” or “Company”), and Brid Kealey (hereinafter referred to as “Employee” or “you”). Collectively, Employer and Employee shall be referred to as the “Parties.”

A. Employer desires to engage Employee in the position of Chief Human Resources Officer (CHRO).

B. Employee is willing to be employed by Employer, and Employer is willing to employ Employee, on the terms and conditions set forth herein.

C. In consideration of the mutual covenants and promises of the Parties hereto, Employer and Employee agree as follows:

1.     Agreement to Employ and be Employed: Employer hereby agrees to employ Employee and Employee hereby accepts and agrees to such employment.

2.     At-Will Employment: Employee’s employment is at-will. Nothing in this Agreement guarantees Employee employment with Employer for any specific period of time. This means that, subject to the provisions of this Agreement, Employer may terminate employee at any time with no advance notice, procedure, or formality and for any lawful reason, with or without cause. Similarly, subject to the provisions of this Agreement, Employee may resign his employment at any time and for any reason. Your at-will employment relationship cannot be changed by any oral representation, written document or other conduct unless such change is specifically acknowledged in writing by an authorized executive of the Company.

3.     Description of Employee’s Duties: Employee will be employed as Chief Human Resources Officer. Employee’s job duties are set forth in Exhibit 1. The position is exempt from overtime under both state and federal laws and regulations. You will report to Christopher P. Kalnin and your primary office location will be at our offices in Denver, Colorado. Your start date will be approximately February 1, 2021 (the “Start Date”). In addition, we also attach Colorado Overtime and Minimum Pay Standards Order 36.

4.     Manner of Performance of Employee’s Duties: Employee shall be a full-time employee of Employer, shall devote his best efforts and entire business time, attention, and services exclusively to the business and affairs of Employer, and shall perform his duties as set forth in Exhibit 1 with fidelity and to the best of his ability, experience, and talent. Employee shall also perform the duties of his position to the reasonable satisfaction of Employer.

Employee will not engage in the performance of services for any other business or entity during the term of this Agreement unless the performance of such services is approved by Employer in advance.

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Notwithstanding anything in this Section 4, or in any other provision of this Agreement to the contrary, Employer hereby approves Employee’s continued participation in, and service to, the business enterprise identified and described in Exhibit 2.

5.     Compensation: In consideration of the services to be provided by Employer during employment, Employer shall compensate Employee as follows:

a. During his employment, Employee shall receive the equivalent of an annual base salary of Two Hundred Ninety-Five Thousand U.S. dollars ($295,000.00), less applicable payroll deductions and required taxes and withholdings (“Base Compensation”), with partial periods prorated. Employee’s Base Compensation shall be payable in equal periodic installments according to Employer’s customary payroll practice. The Base Compensation is based on and intended to compensate Employee for all hours worked.

b. During your employment, Employee may participate in Employer benefit plans and programs described in the attached Exhibit 3, to the extent that Employer maintains such plans or programs and in accordance with the eligibility and participation criteria applicable to each such plan or program. Employee acknowledges that the Employer has the right to change, modify, or eliminate benefits provided to its employees from time to time in Employer’s sole discretion without notice to employees. As such, Employee acknowledges and agrees that this Agreement does not create a specific entitlement to any particular benefits, and that Employee will receive benefits at the same level as other similarly situated employees of Employer.

c. During his employment, Employee may also, in Employer’s sole discretion, receive compensation each calendar year in addition to his Base Compensation. Such additional compensation will be paid, if at all, in the form of an Annual Target Bonus, which Employer intends to fall between 0 percent and 40 percent (0-40%) of the annual Base Compensation. The availability of any bonus will be determined based upon Employer’s performance and will take into account Employee’s individual effort and satisfactory achievement of established performance goals. Any such Annual Target Bonus (if any) will be paid to Employee, in full and subject to applicable tax, not later than March 15 of the calendar year following the calendar year during which Employee performed the services that gave rise to that Bonus. The bonus would be pro-rated based on your Start Date.

Nothing in this provision (c) is intended to guarantee Employee the payment of a bonus in any amount other than as described in provision (c).

d. Paid Time Off (PTO). PTO includes vacation, sick, personal time, etc. Employee is eligible to accrue up to 30 days of PTO per year. Paid time off is accrued on a pro-rata basis at the rate of 1.15 days/Bi-Weekly throughout the year. Under Employer’s policy, employees do not accrue PTO once they have earned their maximum paid time off hours per year. The accrual will resume once the amount of accrued PTO is less than the maximum possible accrual. Available PTO will automatically carry over into the new calendar year. Up to 10 days of accrued, unused paid time off will be paid out upon separation, unless otherwise required by law. Advanced but unaccrued paid time off will be deducted from an employee’s final paycheck, to the extent permitted by law and Employee hereby authorizes such deduction in accordance with applicable law and waives the right to presentment, notice and protest.

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e. Signing Bonus. The Company will pay you a signing bonus of $100,000, less lawful deductions and withholdings within thirty (30) days of your Start Date (the “Signing Bonus”).

f. Long Term Incentive. In addition, during your employment, subject to final management approval, you will also be eligible for the Company’s Long-Term Incentive Program (“LTIP”) pursuant to the terms of the LTIP and grant agreements to be provided separately to you once employed, which is estimated to equate to 100,000 shares. Employee shall also, during your employment, be eligible to receive between 0-300,000 shares pursuant to the terms of the LTIP and grant agreements to be provided separately to you, on January 1, 2023 subject to management approval and satisfactory achievement of performance goals by Employee. Finally, in addition to the Signing Bonus, the availability of any bonus including any grant of LTIP, will be determined based upon the Company’s performance and will consider your individual effort and satisfactory achievement of established performance goals.

The compensation described in this Section 5 constitutes all compensation made available by Employer for the services of Employee. No other or additional compensation in any form will be considered or paid for during the period of this Agreement.

6.     Relocation: Employee shall be promptly reimbursed Employee for reasonable relocation costs incurred as described below to move residence and family, the aggregate of which is not to exceed $30,000. Covered costs include:

a. reasonable broker fees in connection with the sale of the existing family home, reasonable out-of-pocket fees and expenses, and transfer taxes, but not home sales tax;

b. packing and moving of all household goods and shipment of three automobiles based upon a competitive bid approved through the Company’s Human Resources department;

Covered expenses do not include other broker fees or mortgage financing fees in excess of two points, in connection with the purchase of a residence.

During an agreed Transition Period, Employee will be reimbursed for reasonable expenses associated with commuting, including two trips accompanied by partner/spouse for purposes of relocation-related planning, and for temporary housing and rental car expenses in accordance with the Company’s T&E Policy.

Relocation expenses must be incurred within twelve (12) months from January 1, 2021 and payment will include a full tax gross-up for taxes incurred on receipt of the reimbursements under this section.

7.     Confidentiality: Employee acknowledges that, in the course of performing and fulfilling his duties hereunder, she may have access to and be entrusted with nonpublic information belonging to, developed by, licensed by, or otherwise in the possession of, Employer or its clients. To protect such information, Employee agrees that she will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than Employer, any Confidential Information, as defined below, whether prepared by Employee or not. At the request of Employer, Employee agrees to deliver to Employer, at any time during his employment, or thereafter, all Confidential Information which she may possess or control.

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Employee shall be permitted to disclose Confidential Information if and to the extent disclosure of any part thereof is specifically required by law; provided, however, that in the event such disclosure is required by applicable law, Employee shall provide Employer with prompt written notice of such requirement, prior to making any disclosure, so that Employer may seek an appropriate protective order, and Employee only shall disclose information as necessary to comply with legal process. Moreover, in accordance with the Defend Trade Secrets Act (“DTSA”), an employee will not be held criminally or civilly liable under any federal or state trade secret law if an employee discloses a trade secret in confidence to federal, state, or local government officials, to his/her attorney solely for the purpose of reporting or investigating a suspected violation of law, or in a sealed complaint or other document filed in a lawsuit or other proceeding.  Further, an employee who files a lawsuit alleging retaliation by an employer for reporting a suspected violation of law may disclose the trade secret to his attorney and use the trade secret information in the court proceeding if the individual: (a) files the document containing the trade secret in a sealed court document and (b) does not disclose the trade secret, except pursuant to court order. The DTSA does not, however, offer protection from liability for individuals who access trade secrets by unlawful means.

Notwithstanding the foregoing, nothing in this Agreement is intended to prevent Employee from engaging in activity protected by the National Labor Relations Act, including engaging in discussion of concerns about working conditions or other concerted activities.

“Confidential Information” means any of Employer’s and its Affiliates’ confidential information including, without limitation, all provisions hereunder, any information, processes, plans, data calculations, software storage media or other compilation of information, patent, patent application, copyright, “know-how,” trade secrets, customer lists, details of client or consultant contracts, pricing policies, operational methods, marketing plans or strategies, product development techniques or plans, business acquisition plans, any portion or phase of any scientific or technical information, ideas, discoveries, designs, inventions, creative works, computer programs (including source of object codes), processes, formulae, improvements or other proprietary or intellectual property of the Employer, whether or not in written or tangible form, and whether or not registered or labeled as confidential, and including all files, records, manuals, books, catalogues, memoranda, notes, summaries, plans, reports, records, documents and other evidence thereof. The covenant in this Section 7 shall survive termination of this Agreement. “Affiliate” is defined as all parent, sister and subsidiary companies.

8.     Inventions, Ideas, and Other Intellectual Developments: In view of the purposes of Employer and the need to secure for the Employer and/or Interested Parties (defined below) their right to Intellectual Developments (defined below) related to the business of Employer and/or such Interested Party, Employee understands that Employer must be in a position to use, assign, and otherwise dispose of Intellectual Developments made by its staff members and employees. Accordingly, except for those items excluded by Section 12 below, Employee shall promptly disclose to Employer and, when requested, furnish to the Employer a complete record of every discovery, invention, improvement, innovation, design, analysis, reports, drawings, copyright, intellectual property right and other definite and useful idea or compilation of information of value (individually and collectively an “Intellectual Development”), which Employee may make or originate, individually or with others, at any time during the term of Employee’s employment by the Employer. Employee hereby assigns to the Employer or its nominee the entire rights throughout the world to such Intellectual Developments which relate to the current or potential business or activities of the Employer or any Interested Parties or which results from Employee’s work with Employer. The term “Interested Parties” means any person having a business relationship with the Company where the relationship gives rise to a claim by that person to some interest in Intellectual Developments made by employees and associates of the Employer or its Affiliates.

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9.     Cooperation: Employee shall fully cooperate with Employer or its designees in securing, in the name of the Company or its designees, rights with respect to the Intellectual Developments described in Section 8 above, in all countries. Employee shall promptly execute all proper documents presented for signature and do all things reasonably required to enable Employer or its designees to accomplish the above, at any time during or after Employee’s employment.

10.   Shop Rights and Holdover: Employee agrees that Employer or its designees shall be entitled to shop rights to any Intellectual Developments conceived or made by Employee that is not related to the Employer’s trade secrets and/or Confidential Information but conceived or made on Company time or with the use of Employer’s facilities or materials. Employee further agrees that any Intellectual Developments related to Employer’s trade secrets and/or Confidential Information described by Employee in a patent, service mark, trademark, or copyright application, disclosed by Employee in any manner to a third person, or created by Employee or Employee’s affiliates or any person with whom Employee has any business, financial or confidential relationship, within one (1) year after cessation of Employee’s employment with Employer for any reason, was conceived or made by Employee during Employee’s employment with Employer and is therefore the sole property of Employer or its designees.

11.   Information and Testimony: For a period of time up to five years from Employee’s last date of employment with Employer, Employee shall, without expense to Employee, give such true information and testimony at reasonable times and places upon prior notice, under oath if requested, as may be requested by Employer or its designees relative to any Intellectual Development described in Section 8 above.

12.   Interest of the Employee: As to inventions, applications for patents, and copyrightable material in which Employee presently holds an interest and which are not subject to this Agreement:

Check One:

¨ Employee has no such property.

¨ Employee has described all such property in Section 13 below.

13.   Description of Inventions, Applications for Patents and Copyright Material Exempted in Section 12.

Employee to insert description of applicable inventions, patents and copyright material below.

By: _________________on__________________

       ______________            Date

14.   Restrictive Covenant: Because Employee will be provided with proprietary, confidential, and trade secret information, the Employee shall not, during his employment:

a. enter into, own, manage, operate, control, be employed with, or engage, as an employee, associate, officer, director, shareholder, partner or in any other capacity, on behalf of any association, enterprise, company, or firm that provides services or products in competition with Employer, except as otherwise provided in Exhibit 2 to this Agreement;

b. directly or indirectly solicit or attempt to solicit the business of any client or customer or active customer prospect of the Employer or any of its Affiliates for his own benefit or that of any third person or organization; and

c. directly or indirectly induce any employee or contractor of Employer or any of its Affiliates to leave his or his employment or independent contract with Employer or any of its Affiliates.

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15.   Non-Disparagement: Employee agrees that at any time during his employment with the Employer and at any time thereafter, Employee shall not, except in the good faith commission of his duties and responsibilities, make, or cause or assist any other person to make, any statement or other communication that impugns or attacks, or is otherwise critical to the reputation, business or character of the Employer or any of its officers, directors, members, managers, employees, products or services.

16.   Reasonableness of Restraints, Irreparable Harm: Employee acknowledges that: (a) the agreements and covenants contained herein are reasonably necessary to protect the goodwill, Confidential Information, Intellectual Developments, trade secrets, and other business interests of Employer; (b) any breach of the covenants contained herein will cause Employer immediate irreparable harm for which injunctive relief would be necessary; (c) the covenants contained herein are essential and material elements of this Agreement and Employer would not have entered into this Agreement or permitted Employee to obtain employment or remain employed without those covenants being included in this Agreement; (d) Employee has had the opportunity to consult with and be advised by legal counsel concerning the reasonableness and propriety of the covenants contained herein; and (e) in the event of any violation or attempted violation of the covenants contained herein, Employer shall be entitled to a temporary restraining order, temporary or permanent injunctions, and other injunctive relief, without any showing of irreparable harm or damage or any need to post a bond, in addition to any other rights or remedies which may then be available to Employer. In addition to, but not instead of, any other legal or equitable remedies available to Employer, Employee hereby agrees to reimburse Employer for reasonable attorneys’ fees and costs incurred by Employer in the event Employer is successful in showing a violation or attempted violation of this Agreement as determined by a court of competent jurisdiction.

17.   No Existing Obligations: Employee represents that Employee: (a) is not subject to a confidentiality, trade secret, conflict of interest, or non-competition agreement with any former employer, contractor or third party; and (b) has no continuing obligations to any former employer, contractor or third party with respect to the ownership or assignment of any proprietary rights, including, but not limited to, inventions, ideas, copyrights, trade secrets or patents, including any such rights in information, or creations or materials Employee conceived or made, in whole or in part that will impact Employee’s services for Employer. Employee understands that any such agreement or obligation, as well as any trade secret and other property laws, may restrict Employee from using any secret or proprietary information that belongs to any former employer, contractor or third party, either for Employee’s own benefit or for anyone else’s benefit, including Employer. Employee also understands that Employee, or anyone else who uses or benefits from a third party’s proprietary information, may be liable to that third party; therefore, Employee agrees not to use any confidential, trade secret, or proprietary information that belongs to any former employer, contractor, or third party during the term of employment, either for Employee’s own benefit or to benefit Employer or any of its clients, customers, or affiliates.

18.   Termination of Employment and Termination Payment. Notwithstanding the at-will nature of your employment, if your employment is terminated by the Company without “Cause” as defined below, in addition to the (1) payment of your Base Compensation and any bonuses earned through the termination date, (2) payment for any unused, accrued vacation days as of your termination date, and (3) reimbursement of any outstanding, reasonable business expenses incurred by you through the termination date, you will be eligible to receive a severance benefit equal to the sum of six (6) months of your annual Base Compensation as of the date of termination, provided you execute a Separation Agreement and General Release provided by the Company (the “Separation Agreement”). For purposes of this letter, the term “Cause” shall mean any of the following: (i) other than as a result of a disability, your willful failure to perform your duties; (ii) your willful engagement in misconduct which is injurious to the Company, monetarily or otherwise; (iii) your conviction of a crime (including a nolo contendere plea) involving, in the good faith of the Company, fraud, dishonesty or moral turpitude; (iv) the negligent performance of your duties; (v) your breach of any covenant set forth in the Confidential Information and Non-Solicitation Agreement; or (vi) your breach of any material Company policy. You will be considered to have been terminated for “Cause” if the Company determines in good faith that you engaged in an act constituting “Cause” even after a resignation by you.

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19.   Non-Competition. In exchange for the termination payment described in Section 18 above, for a period of five (5) months following termination of Employee’s employment, for any reason, Employee shall not (1) enter into or engage in any business which competes with the Company or any of its subsidiaries or affiliates (“Company Group”) within the States of Pennsylvania, Colorado and Texas (“Restricted Territory”); (2) solicit any known customers, business, assets, investments or patronage (or customer, business, asset, investment or patronage prospects) for, or sell, any products or services in competition with or for any business that competes with the Company Group within the Restricted Territory; (3) divert, entice or otherwise take away any known business, assets or investments or patronage (or customer, business, asset, investment or patronage prospects) of the Company Group within the Restricted Territory; or (4) promote, manage or assist, financially or otherwise, any person, firm, association, partnership, corporation or other entity engaged in any business which competes with or is engaged in the same business as the Company Group within the Restricted Territory. For purposes of this section, Employee will be in violation of the non-compete provision set forth herein if Employee engages in any or all of the activities set forth herein directly as an individual on Employee’s own account or indirectly as a partner, joint venture, employee, agent, salesperson, consultant, officers and/or director of any firm, association, partnership, corporation or other entity or as a shareholder of any corporation (or owner of any other type of equity interest in any other entity) in which Employee or Employee’s spouse, minor child, or parent sharing the same household as Employee owns, directly or indirectly, individually or in the aggregate, more than 1% of the outstanding stock or other equity interests. If it is judicially determined or by consent of Employee that Employee has violated this Section 19 and the Company obtains an order, injunction or other equitable relief, then the period applicable to each obligation that Employee has been determined to have violated will be automatically extended by a period of time equal in length to the period during which such violation occurred.

20.   Termination Notice. Your employment may be terminated in writing either by the Company without Cause or by you upon ninety (90) days written notice to the Company. If the Company terminates your employment without Cause, 90 days’ notice is not required by the Company, provided that it offers to pay you the severance benefits described in this letter in exchange for you signing a Separation Agreement and General Release. For purposes of clarity, no prior notice is required to terminate your employment by the Company with Cause.

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21.   Internal Revenue Code Section 409A Compliance. Both you and the Company intend that all compensation or benefits paid under this letter as well as the Separation Agreement comply with Internal Revenue Code Section 409A and the regulations and guidance promulgated thereunder (collectively “Section 409A”) and, accordingly, to the maximum extent permitted, this letter shall be interpreted to be in compliance therewith. By way of example, and not limitation, with respect to payments triggered by your “termination of employment” (and similar terms) such phrase shall be construed to mean your “separation from service” with the Company (determined under Treasury Regulation Section 1.409A-1(h)). Further, notwithstanding any other provision of this letter to the contrary, if any amount to be paid to you as a result of the termination of your employment pursuant to this letter or the Separation Agreement is “deferred compensation” subject to Section 409A, and if you are a “specified employee” (as defined under Section 409A) as of the date of your termination of employment hereunder, then, to the extent necessary to avoid the imposition of excise taxes or other penalties under Section 409A, the payment of benefits, if any, scheduled to be paid by the Company to you hereunder during the first six (6) month period following the date of a termination of employment hereunder shall not be paid until the date which is the first business day following the six-month anniversary of the termination of your employment for any reason other than death. Any deferred compensation payments delayed in accordance with the terms of this paragraph shall be paid in a lump sum when paid. In addition, both you and the Company agree to cooperate fully with one another to attempt to ensure compliance with Section 409A, including, without limitation, adopting amendments to arrangements subject to Section 409A and operating such arrangements in compliance with Section 409A; provided, however, nothing in this paragraph shall require you to reduce your compensation; provided, further, however, nothing in this letter shall constitute an agreement to indemnify, gross up or otherwise make you whole for any taxes imposed under Section 409A. The Company does not make any representation as to whether any benefits, payments, or reimbursements under this letter satisfy the requirements of Section 409A or any exemption thereto.

22.   Assignment: This Agreement may be assigned by Employer to any affiliated or successor employer without the consent of Employee, and so long as the affiliate or successor accepts the assignment, this Agreement will continue to be binding upon the Employee. This Agreement may not be assigned by Employee.

23.   Severability: Each paragraph of this Agreement shall be and remain separate from and independent of, and severable from, all and any other paragraphs herein except where otherwise indicated by the context of the Agreement. To the extent any portion of this Agreement, or any portion of any provision of this Agreement is held to be invalid or unenforceable, it is the Parties’ express intent it shall be construed by severing, limiting and reducing it so as to be enforceable to the extent compatible with applicable law. All remaining provisions, and/or portions thereof, shall remain in full force and effect.

24.   Modification: Any modification of this Agreement or any additional obligation assumed by either Party in connection with this Agreement shall be in writing and signed by each Party.

25.   No Waiver: The failure of either Party to this Agreement to insist upon the performance of any terms and conditions or the waiver of any breach of any terms and conditions of this Agreement shall not be construed as thereafter waiving such terms and conditions, but the same shall continue to remain in full force and effect.

26.   Complete Agreement: This Agreement contains the complete agreement concerning the employment agreement between the Parties and supersedes any and all prior understandings and agreements between the Parties concerning the subject matter hereof. The Parties stipulate that neither has made any representation with respect to the subject matter of this Agreement except such representations as are specifically set forth in this Agreement.

27.   Interpretation of Agreement: The validity, interpretation, construction, and performance of this Agreement shall be governed by the laws of the State of Colorado, without regard to its conflict of law provisions. This Agreement shall be interpreted with all necessary changes in gender and in number as the context may require and shall inure to the benefit of and be binding upon the respective successors and assigns of the parties hereto.

28.   Survival: The terms and provisions of Sections 7 through 15 of this Agreement shall survive the cancellation, termination, or expiration of this Agreement.

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29.   Resolution of Disputes: The parties consent and agree that, except as set forth in this Section 29, any action or proceeding between them arising from this Agreement shall be exclusively referred to binding arbitration in Denver, Colorado in accordance with the rules of the Commercial Arbitration (“AAA”) Rules and Mediation Procedures before a single arbitrator selected by the Employer. The decision of the arbitrator shall be final, non-appealable and binding upon the parties and may be enforced in any court having jurisdiction thereof. The AAA Rules regarding discovery shall apply to arbitration under this Agreement. The Arbitrator selected according to this Agreement shall decide all discovery disputes. The parties shall split the administrative cost of arbitration equally and each party shall be responsible for the payment of its own respective legal fees. Claims where mandatory arbitration is prohibited by a valid non-preempted law are explicitly excluded from this Arbitration provision. CLAIMS IN ARBITRATION SHALL BE FILED AND MAINTAINED ONLY ON AN INDIVIDUAL BASIS. EMPLOYEE MAY NOT FILE OR MAINTAIN ANY CLAIM IN ARBITRATION ON BEHALF OF OTHERS, COLLECTIVELY OR OTHERWISE, OR AS A NAMED PLAINTIFF/CLAIMANT OR MEMBER IN ANY PURPORTED CLASS, COLLECTIVE, OR REPRESENTATIVE PROCEEDING. THE ARBITRATOR MAY NOT CONSOLIDATE MORE THAN ONE PARTY’S CLAIMS, AND MAY NOT OTHERWISE PRESIDE OVER ANY FORM OF A COLLECTIVE, CLASS, OR REPRESENTATIVE ARBITRATION PROCEEDING. Notwithstanding the foregoing, any claim related to Sections 7 through 15 of this Agreement shall be asserted exclusively in the state or federal courts of the State of Colorado, and Employee hereby expressly consents to the jurisdiction thereof.

30.   Notice: Notice shall be provided in writing via certified mail (return receipt requested), overnight courier or personal delivery to the address set forth below.

If to Employer:	If to Employee:
BKV Corporation
Attn: Christopher P. Kalnin
1200 17th Street, Suite 2100
Denver, CO 80202
Email: [***]

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IN WITNESS WHEREOF, the Parties have executed this Employment Agreement on the date or dates set forth below.

/s/ Brid Kealey		/s/ Christopher P. Kalnin
Brid Kealey		Christopher P. Kalnin, CEO
		BKV Corporation
Date:	January 19, 2021	Date:	January 19, 2021

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EXHIBIT 1

Exempt

Full-time Position

11

EXHIBIT 2

Employee’s Existing Business Enterprises

12

EXHIBIT 3

Summary of Benefits Currently Offered by

BKV Corporation (“Employer”)

13

EX-10.23

Exhibit 10.23

KALNIN VENTURES, LLC

EMPLOYMENT AGREEMENT

This Employment Agreement (the “Agreement”) is effective as of the 15th day of October 2018 (“Effective Date”), regardless of the date the Agreement is executed, by and between Kalnin Ventures LLC, a Colorado limited liability company (hereinafter referred to as “Employer”), and Lindsay B. Larrick (hereinafter referred to as “Employee”). Collectively, Employer and Employee shall be referred to as the “Parties.”

A. Employer desires to engage Employee in the position of Vice President and General Counsel.

B. Employee is willing to be employed by Employer, and Employer is willing to employ Employee, on the terms and conditions set forth herein.

C. In consideration of the mutual covenants and promises of the Parties hereto, Employer and Employee agree as follows:

1. Agreement to Employ and be Employed: Employer hereby agrees to employ Employee and Employee hereby accepts and agrees to such employment.

2. Duration of Employment: Employee’s employment is at will. Nothing in this Agreement guarantees Employee employment with Employer for any specific period of time. This means that, subject to the provisions of this Agreement, Employer may terminate employee at any time with no advance notice, procedure, or formality and for any lawful reason. Similarly, subject to the provisions of this Agreement, Employee may resign their employment at any time and for any reason. The time that Employee is employed by Employer shall be referenced as the “Term of Employment.”

3. Description of Employee’s Duties: Employee will be employed as Vice President and General Counsel. Employee’s job duties are set forth in Exhibit 1. The Vice President and General Counsel position is exempt from overtime under both state and federal laws and regulations.

4. Manner of Performance of Employee’s Duties: Employee shall be a full-time employee of Employer, shall devote their best efforts and entire business time, attention, and services exclusively to the business and affairs of Employer, and shall perform their duties as set forth in Exhibit 1 with fidelity and to the best of their ability, experience, and talent. Employee shall also perform the duties of their position to the reasonable satisfaction of Employer.

Employee will not engage in the performance of services for any other business or entity during the term of this Agreement unless the performance of such services is approved by Employer in advance.

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Notwithstanding anything in this Section 4, or in any other provision of this Agreement to the contrary, Employer hereby approves Employee’s continued participation in, and service to, the business enterprise identified and described in Exhibit 2.

5. Compensation: In consideration of the services to be provided by Employer during the Term of Employment, Employer shall compensate Employee as follows:

a. During the Term of Employment, the Employee shall receive the base gross compensation of three hundred thousand U.S. dollars ($300,000.00) annually, less approved payroll deductions and required taxes and withholdings (“Base Compensation”), with partial periods prorated. Employee’s Base Compensation shall be payable in equal periodic installments according to the Employer’s customary payroll practice. The Base Compensation is based on, and intended to compensate Employee for, Employee’s full-time work schedule.

b. As additional consideration in exchange for the Employee’s execution of and compliance with the terms of this Agreement, the Employee shall receive a one-time additional payment of three hundred thousand U.S. dollars ($300,000.00), less approved payroll deductions and required taxes and withholdings (“Additional Compensation”). The Additional Compensation shall be payable on the Effective Date.

c. During the Term of Employment, Employee may participate in the Employer benefit plans and programs described in the attached Exhibit 3 (and includes additional documentation to be provided by the Employer), to the extent that Employer maintains such plans or programs and in accordance with the eligibility and participation criteria applicable to each such plan or program. Employee acknowledges that the Employer has the right to change, modify, or eliminate benefits provided to its employees from time to time in Employer’s sole discretion. As such, Employee acknowledges and agrees that this Agreement does not create a specific entitlement to any particular benefits, and that Employee will receive benefits at the same level as other similarly situated employees of Employer.

d. During the Term of Employment, Employee may also, in Employer’s sole discretion, receive compensation each calendar year in addition to their Base Compensation. Such additional compensation will be paid, if at all, in the form of an Annual Target Bonus, which Employer intends to fall between 0 percent and 40 percent of the annual Base Compensation. The availability of this bonus will be determined based upon Employer’s performance and will take into account Employee’s individual effort and satisfactory achievement of established performance goals. Any such Annual Target Bonus (if any) will be paid to Employee, in full and subject to applicable tax, not later than March 15 of the calendar year following the calendar year during which Employee performed the services that gave rise to that Bonus.

Nothing in this provision (d) is intended to guarantee Employee the payment of a bonus in any amount.

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The compensation described in this Section 5 constitutes the entire payment by the Employer for the services of the Employee. No other or additional compensation in any form will be considered or paid for during the period of this Agreement.

6. Confidentiality. The Employee acknowledges that, in the course of performing and fulfilling their duties hereunder, they may have access to and be entrusted with nonpublic information belonging to, developed by, licensed by, or otherwise in the possession of, Employer or its clients. To protect such information, Employee agrees that they will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than Employer, any Confidential Information, as defined below, whether prepared by Employee or not. At the request of Employer, Employee agrees to deliver to Employer, at any time during the Term of Employment, or thereafter, all Confidential Information which they may possess or control. Employee agrees that all Confidential Information (whether now or hereafter existing) conceived, discovered or made by him during the Term of Employment constitutes a work-for-hire and exclusively belongs to Employer, and not to Employee.

Employee shall have no obligation hereunder to keep confidential any Confidential Information if and to the extent disclosure of any part thereof is specifically required by law; provided, however, that in the event such disclosure is required by applicable law, Employee shall provide Employer with prompt notice of such requirement, prior to making any disclosure, so that Employer may seek an appropriate protective order. Moreover, the Employee will not be held criminally or civilly liable under any federal or state trade secret law for disclosing a trade secret if disclosure is made: I) in confidence to a government official (directly or indirectly) or an attorney; and 2) solely for the purpose of reporting or investigating a suspected violation of law. Further, the Employee will not be held criminally or civilly liable under any federal or state trade secret law for disclosing a trade secret if disclosure is made in a complaint or other document filed in a lawsuit or other proceeding, provided that the filing is done under seal. If the Employee files a lawsuit for retaliation by the Employer for reporting a suspected violation of law, the Employee may disclose the trade secret to their attorney and use the trade secret information in the court proceeding, provided that any document containing the trade secret is filed under seal and the Employee does not disclose the trade secret except as provided by court order.

Notwithstanding the foregoing, nothing in this Agreement is intended to prevent the Employee from engaging in activity protected by the National Labor Relations Act, including engaging in discussion of concerns about working conditions or other concerted activities.

“Confidential Information” means any of the Employer’s confidential information including, without limitation, all provisions hereunder, any information, processes, plans, data calculations, software storage media or other compilation of information, patent, patent application, copyright, “know-how,” trade secrets, customer lists, details of client or consultant contracts, pricing policies, operational methods, marketing plans or strategies, product development techniques or plans, business acquisition plans, any portion or phase of any scientific or technical information, ideas, discoveries, designs, inventions, creative works, computer programs (including source of object codes), processes, formulae, improvements or other proprietary or intellectual property of the Employer, whether or not in written or tangible form, and whether or not registered or labeled as confidential, and including all files, records, manuals, books, catalogues, memoranda, notes, summaries, plans, reports, records, documents and other evidence thereof. The covenant in this Section 6 shall survive termination of this Agreement.

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7. Intellectual Property: The Employee recognizes and agrees that all copyrights, trademarks, or other intellectual property rights to created works arising in any way from, or related to, the Employee’s employment by the Employer are the sole and exclusive property of the Employer. Employee further agrees not to assert any rights to those works against the Employer or any third-parties and agrees to assist the Employer in any reasonable way requested to procure or protect the Employer’s rights to those works. This Section 7 shall survive termination of this Agreement.

8. Restrictive Covenant: Because Employee will be provided with proprietary, confidential, and trade secret information, the Employee shall, during their Term of Employment, refrain from:

1) undertaking employment or any compensated duties on behalf of any association, enterprise, company, or firm that provides services or products in competition with Employer, except as otherwise provided in Exhibit 2 to this Agreement;

2) directly or indirectly soliciting or attempting to solicit the business of any client or customer of the Employer for their own benefit or that of any third person or organization; and

3) directly or indirectly inducing any employee or contractor of Employer to leave their or their employment or independent contract with Employer.

9. No Existing Obligations: Employee represents that Employee: I) is not subject to a confidentiality, trade secret, conflict of interest, or non-competition agreement with any former employer, contractor or third party; and 2) has no continuing obligations to any former employer, contractor or third party with respect to the ownership or assignment of any proprietary rights, including, but not limited to, inventions, ideas, copyrights, trade secrets or patents, including any such rights in information, or creations or materials the Employee conceived or made, in whole or in part. Employee understands that any such agreement or obligation, as well as any trade secret and other property laws, may restrict the Employee from using any secret or proprietary information that belongs to any former employer, contractor or third party, either for Employee’s own benefit or for anyone else’s benefit, including Employer. Employee also understands that Employee, or anyone else who uses or benefits from a third party’s proprietary information, may be liable to that third party; therefore, Employee agrees not to use any confidential, trade secret, or proprietary information that belongs to any former employer, contractor, or third party during the Term of Employment, either for Employee’s own benefit or to benefit Employer or any of its clients, customers, or affiliates.

10. Assignment: This Agreement may be assigned by the Employer to any affiliated or successor employer without the consent of the Employee, and so long as the affiliate or successor accepts the assignment, this Agreement will continue to be binding upon the Employee. This Agreement may not be assigned by the Employee.

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11. Severability: Each paragraph of this Agreement shall be and remain separate from and independent of, and severable from, all and any other paragraphs herein except where otherwise indicated by the context of the Agreement. The decision or declaration that one or more of the paragraphs are null and void shall have no effect on the remaining paragraphs of this Agreement.

12. Modification: Any modification of this Agreement or any additional obligation assumed by either Party in connection with this Agreement shall be in writing and signed by each Party.

13. No Waiver: The failure of either Party to this Agreement to insist upon the performance of any terms and conditions or the waiver of any breach of any terms and conditions of this Agreement shall not be construed as thereafter waiving such terms and conditions, but the same shall continue to remain in full force and effect.

14. Complete Agreement: This Agreement contains the complete agreement concerning the employment agreement between the Parties. The Parties stipulate that neither has made any representation with respect to the subject matter of this Agreement except such representations as are specifically set forth in this Agreement.

15. Interpretation of Agreement: The validity, interpretation, construction, and performance of this Agreement shall be governed by the laws of the State of Colorado. This Agreement shall be interpreted with all necessary changes in gender and in number as the context may require and shall inure to the benefit of and be binding upon the respective successors and assigns of the parties hereto.

16. Survival: The terms and provisions of Sections 6 and 7 of this Agreement shall survive the cancellation, termination, or expiration of this Agreement.

17. Resolution of Disputes: Any controversy or claim arising out of or relating to this Agreement, or the breach thereof, shall be resolved by binding arbitration conducted by the Judicial Arbiter Group, Inc., or its successor, in Denver, Colorado (“JAG”). Judgment on the award rendered by JAG may be entered in any court having jurisdiction thereof. Demand for arbitration shall be submitted only to the persons listed below. After a demand is submitted, the Parties shall have ten (10) days to mutually agree upon an arbitrator then providing such services through JAG or its successor. If the Parties cannot so mutually agree, then they hereby stipulate to the appointment of an arbitrator chosen by JAG. In addition to any relief, order, or award that enters as determined by the arbitrator or court, the Parties agree that the prevailing party, if any, shall be entitled to an award of reasonable attorneys’ fees and costs incurred.

Notice shall be provided as follows:

If to Employer:	If to Employee:
Christopher P. Kalnin	Lindsay Larrick
1200 17th Street, Suite 1850	[***]
Denver, CO 80202	[***]

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IN WITNESS WHEREOF, the Parties have executed this Employment Agreement on the date or dates set forth below.

/s/ Lindsay B. Larrick	/s/ Christopher P. Kalnin
Lindsay B. Larrick	Christopher P. Kalnin, Managing Director
	Kalnin Ventures LLC
July 6, 2018	August 14, 2018
Date	Date

[Signature Page to Employment Agreement]

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EXHIBIT 1

Exempt from Overtime
Full-time Position

7

EXHIBIT 2

Employee’s Existing Business Enterprises

8

EXHIBIT 3

Summary of Benefits Currently Offered by Kalnin Ventures LLC (“Employer”)

9

EX-10.24

Exhibit 10.24

KALNIN VENTURES, LLC

EMPLOYMENT AGREEMENT

This Employment Agreement (the “Agreement”) is amended as of the 1^st day of April 2018 by and between Kalnin Ventures LLC, a Colorado limited liability company (hereinafter referred to as “Employer”), and An Sao (Ethan) Ngo (hereinafter referred to as “Employee”). Collectively, Employer and Employee shall be referred to as the “Parties.”

A. Employer desires to engage Employee to identify, source, evaluate, underwrite, acquire, manage, and ultimately exit oil and gas investments.

B. Employee is willing to be employed by Employer, and Employer is willing to employ Employee, on the terms and conditions set forth herein. For the reasons set forth above and in consideration of the mutual covenants and promises of the Parties hereto, Employer and Employee agree as follows:

1. Agreement to Employ and be Employed: Employer hereby agrees to employ Employee and Employee hereby accepts and agrees to such employment.

2. Duration of Employment: Employee’s employment with Employer is at will, and not of any particular duration. Nothing in this Agreement guarantees Employee employment with Employer for any specific period of time. This means that, subject to the provisions of this Agreement, Employer may terminate employee at any time with no advance notice, procedure, or formality and for any lawful reason. Similarly, subject to the provisions of this Agreement, Employee may resign his employment at any time and for any reason. The time that Employee is employed by Employer shall be referenced as the “Term of Employment.”

3. Description of Employee’s Duties: Employee will be employed as a Senior Vice President of Engineering. Employee’s job duties are set forth in Exhibit 1. The Reservoir Engineer position is exempt from overtime under both state and federal laws and regulations.

4. Manner of Performance of Employee’s Duties: Employee shall be a full-time employee of Employer, shall devote his best efforts and entire business time, attention, and services exclusively to the business and affairs of Employer, and shall perform his duties as set forth in Exhibit 1 with fidelity and to the best of his ability, experience, and talent. Employee shall perform the duties of his position to the reasonable satisfaction of Employer.

Employee will not engage in the performance of services for any other business or entity during the term of this Agreement unless the performance of such services is approved by Employer in advance.

Notwithstanding anything in this Section 4, or in any other provision of this Agreement to the contrary, Employer hereby approves Employee’s continued participation in, and service to, the business enterprise identified and described in Exhibit 2.

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5. Compensation: In consideration of the services to be provided by Employer during the Term of Employment, Employer shall compensate Employee as follows:

a. During the Term of Employment, the Employee shall receive the base gross compensation of two hundred forty-four thousand, seven hundred twenty-one dollars ($244,721.00) annually, less approved payroll deductions and required taxes and withholdings (“Base Compensation”), with partial periods prorated. Employee’s Base Compensation shall be payable in equal periodic installments according to the Employer’s customary payroll practice. The Base Compensation is based on, and intended to compensate Employee for, Employee's full-time work schedule.

b. During the Term of Employment, Employee may participate in the Employer benefit plans and programs described in the attached Exhibit 2, to the extent that Employer maintains such plans or programs. Employee acknowledges that the Employer has the right to change, modify, or eliminate benefits provided to its employees from time to time in Employer’s sole discretion. As such, Employee acknowledges and agrees that this Agreement does not create a specific entitlement to any particular benefits, and that Employee will receive benefits at the same level as other similarly situated employees of Employer.

c. During the Term of Employment, Employee may also, in Employer’s sole discretion, receive compensation each calendar year in addition to his Base Compensation. Such additional compensation will be paid, if at all, in the form of an Annual Target Bonus, which Employer intends to fall between 20 percent and 40 percent of the annual Base Compensation. The availability of this bonus will be determined based upon Employer’s performance, and will take into account Employee’s individual effort and satisfactory achievement of established performance goals. Any such Annual Target Bonus will be paid to Employee, in full, not later than March 15 of the calendar year following the calendar year during which Employee performed the services that gave rise to that Bonus.

Nothing in this provision (c) is intended to guarantee Employee the payment of a bonus in any amount.

d. In the event that BKV Oil & Gas Capital Partners, L.P is successfully formed on or before March 1, 2016, with Kalnin Capital Partners, L.P. as its general partner, with Kalnin Ventures LLC as its initial limited partner, and with Banpu North America Corporation as its limited partner, Employee shall be granted a 10 percent partnership interest in Kalnin Capital Partners, L.P. Under no circumstances, however, shall Employee be entitled to all or any portion of such partnership interest after March 15, 2016. This provision is expressly intended to comply with the short-term deferral rule applicable to Section 409A of the Internal Revenue Code.

The compensation described in this Section 5 constitutes the entire payment by the Employer for the services of the Employee. No other or additional compensation in any form will be considered or paid for during the period of this Agreement, except as otherwise provided in Section 6, below.

6. Signing Bonus: As additional consideration in exchange for the Employee’s execution of and compliance with the terms of this Agreement, Employer agrees to pay the Employee a one-time signing bonus (the “Signing Bonus”) in the total, gross amount of thirty thousand dollars ($30,000.00), subject to all applicable payroll withholding taxes and any other deductions approved by the Employee. Payment will be made on the first regular payday following commencement of Employee’s employment.

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7. Confidentiality. The Employee acknowledges that, in the course of performing and fulfilling his duties hereunder, he may have access to and be entrusted with nonpublic information belonging to, developed by, licensed by, or otherwise in the possession of, Employer or its clients. To protect such information, Employee agrees that he will not, directly or indirectly, in one or a series of transactions, disclose to any person, or use or otherwise exploit for Employee’s own benefit or for the benefit of anyone other than Employer, any Confidential Information, as defined below, whether prepared by Employee or not. Employee shall have no obligation hereunder to keep confidential any Confidential Information if and to the extent disclosure of any part thereof is specifically required by law; provided, however, that in the event such disclosure is required by applicable law, Employee shall provide Employer with prompt notice of such requirement, prior to making any disclosure, so that Employer may seek an appropriate protective order. At the request of Employer, Employee agrees to deliver to Employer, at any time during the Term of Employment, or thereafter, all Confidential Information which he may possess or control. Employee agrees that all Confidential Information of Organization (whether now or hereafter existing) conceived, discovered or made by him during the Term of Employment constitutes a work-for-hire and exclusively belongs to Employer, and not to Employee.

“Confidential Information” means any of the Employer’s confidential information including, without limitation, any information, processes, plans, data calculations, software storage media or other compilation of information, patent, patent application, copyright, “know-how,” trade secrets, customer lists, details of client or consultant contracts, pricing policies, operational methods, marketing plans or strategies, product development techniques or plans, business acquisition plans, any portion or phase of any scientific or technical information, ideas, discoveries, designs, inventions, creative works, computer programs (including source of object codes), processes, formulae, improvements or other proprietary or intellectual property of the Employer, whether or not in written or tangible form, and whether or not registered or labeled as confidential, and including all files, records, manuals, books, catalogues, memoranda, notes, summaries, plans, reports, records, documents and other evidence thereof. The covenant in this Section 7 shall survive termination of this Agreement.

8. Intellectual Property: The Employee recognizes and agrees that all copyrights, trademarks, or other intellectual property rights to created works arising in any way from, or related to, the Employee’s employment by the Employer are the sole and exclusive property of the Employer. Employee further agrees not to assert any rights to those works against the Employer or any third-parties, and agrees to assist the Employer in any reasonable way requested to procure or protect the Employer’s rights to those works.

9. Restrictive Covenant: Because Employee will be provided with proprietary, confidential, and trade secret information, the Employee shall, during his Term of Employment, refrain from:

1) undertaking employment or any compensated duties on behalf of any association, enterprise, company, or firm that provides services or products in competition with Employer;

2) directly or indirectly soliciting or attempting to solicit the business of any client or customer of the Employer for his own benefit or that of any third person or organization; and

3) directly or indirectly inducing any employee or contractor of Employer to leave her or his employment or independent contract with Employer.

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10. No Existing Obligations: Employee represents that Employee: 1) is not subject to a confidentiality, trade secret, conflict of interest, or non-competition agreement with any former employer, contractor or third party; and 2) has no continuing obligations to any former employer, contractor or third party with respect to the ownership or assignment of any proprietary rights, including, but not limited to, inventions, ideas, copyrights, trade secrets or patents, including any such rights in information, or creations or materials the Employee conceived or made, in whole or in part. Employee understands that any such agreement or obligation, as well as any trade secret and other property laws, may restrict the Employee from using any secret or proprietary information that belongs to any former employer, contractor or third party, either for Employee’s own benefit or for anyone else’s benefit, including Employer. Employee also understands that Employee, or anyone else who uses or benefits from a third party’s proprietary information, may be liable to that third party. Therefore, Employee agrees not to use any confidential, trade secret, or proprietary information that belongs to any former employer, contractor, or third party during the Term of Employment, either for Employee’s own benefit or to benefit Employer or any of its clients, customers, or affiliates.

11. Assignment: This Agreement may be assigned by the Employer to any affiliated or successor employer without the consent of the Employee, and so long as the affiliate or successor accepts the assignment, this Agreement will continue to be binding upon the Employee. This Agreement may not be assigned by the Employee.

12. Severability: Each paragraph of this Agreement shall be and remain separate from and independent of, and severable from, all and any other paragraphs herein except where otherwise indicated by the context of the Agreement. The decision or declaration that one or more of the paragraphs are null and void shall have no effect on the remaining paragraphs of this Agreement.

13. Modification: Any modification of this Agreement or any additional obligation assumed by either Party in connection with this Agreement shall be in writing and signed by each Party.

14. No Waiver: The failure of either Party to this Agreement to insist upon the performance of any terms and conditions or the waiver of any breach of any terms and conditions of this Agreement shall not be construed as thereafter waiving such terms and conditions, but the same shall continue to remain in full force and effect.

15. Complete Agreement: This Agreement contains the complete agreement concerning the employment agreement between the Parties. The Parties stipulate that neither has made any representation with respect to the subject matter of this Agreement except such representations as are specifically set forth in this Agreement.

16. Interpretation of Agreement: The validity, interpretation, construction, and performance of this Agreement shall be governed by the laws of the State of Colorado. This Agreement shall be interpreted with all necessary changes in gender and in number as the context may require and shall inure to the benefit of and be binding upon the respective successors and assigns of the parties hereto.

17. Survival: The terms and provisions of Section 7 of this Agreement shall survive the cancellation, termination, or expiration of this Agreement.

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18. Resolution of Disputes: Any controversy or claim arising out of or relating to this Agreement, or the breach thereof, shall be resolved by binding arbitration conducted by the Judicial Arbiter Group, Inc., or its successor, in Denver, Colorado (“JAG”). Judgment on the award rendered by JAG may be entered in any court having jurisdiction thereof. Demand for arbitration shall be submitted only to the persons listed below. After a demand is submitted, the Parties shall have ten (10) days to mutually agree upon an arbitrator then providing such services through JAG or its successor. If the Parties cannot so mutually agree, then they hereby stipulate to the appointment of an arbitrator chosen by JAG. In addition to any relief, order, or award that enters as determined by the arbitrator or court, the Parties agree that the prevailing party, if any, shall be entitled to an award of reasonable attorneys’ fees and costs incurred.

Notice shall be provided as follows:

If to Employer:	If to Employee:
[***]	[***]
[***]	[***]
[***]	[***]

19. Review by Banpu North America Corporation: Employee acknowledges and agrees that this Agreement is subject to review by Banpu North America Corporation (“BNAC”), and that material terms of this Agreement may be unilaterally amended by Employer after Employee has executed it to address objections raised by BNAC.

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IN WITNESS WHEREOF, the Parties have executed this Employment Agreement on the date or dates set forth below.

/s/ An Sao (Ethan) Ngo	/s/ Christopher P. Kalnin
An Sao (Ethan) Ngo	Christopher P. Kalnin, Managing Director
	Kalnin Ventures LLC
July 2, 2018	July 2, 2018
Date	Date

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EXHIBIT 1

Reservoir Engineer Job Duties

Exempt from Overtime

Full-time Position

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EXHIBIT 2

Employee’s Existing Business Enterprises

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EXHIBIT 3

Summary of Benefits Currently Offered by Kalnin Ventures LLC (“Employer”)

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EX-10.25

Exhibit 10.25

FINAL EXECUTION VERSION

BKV-BPP POWER, LLC

(A DELAWARE LIMITED LIABILITY COMPANY)

LIMITED LIABILITY COMPANY AGREEMENT

Dated as of
October 29, 2021

Table of Contents

		Page
Article 1. RECITALS AND DEFINITIONS		1
1.1	Definitions	2
Article 2. FORMATION OF VENTURE		5
2.1	Organization	5
2.2	Purposes and Powers	5
2.3	Principal Business Office, and Registered Agent	5
2.4	Qualification in Other Jurisdictions	5
2.5	Powers	5
2.6	Venturers	5
2.7	Representations and Warranties	5
2.8	Title to Company Assets	5
2.9	No State Law Partnership	6
Article 3. CAPITALIZATION		6
3.1	Initial Capital Contributions	6
3.2	Additional Capital Contributions	6
3.3	Form of Capital Contributions	6
3.4	No Right to Interest or Return of Capita	6
Article 4. BOOKS; ACCOUNTING; TAX ELECTIONS; REPORTS		6
4.1	Books and Records	6
4.2	Financial Statements; Reports	7
4.3	Insurance Program	7
4.4	Approval of Budgets and Business Plans	7
4.5	Filing of Returns	7
4.6	Partnership Representative	7
4.7	Fiscal and Taxable Year	8
4.8	Administrative Services Agreement	8
Article 5. CAPITAL ACCOUNTS; ALLOCATION OF INCOME AND LOSS		9
5.1	Capital Accounts	9
5.2	Allocation of Income and Loss	9
5.3	Loss Limitation	9
5.4	Minimum Gain Chargebacks and Nonrecourse Deductions	9
5.5	Qualified Income Offset	10
5.6	Curative Allocations	10
5.7	Tax Allocations	11
5.8	Other Tax and Allocation Provisions	11
Article 6. DISTRIBUTIONS		11
6.1	Reserves	11
6.2	Distributions	11
6.3	No Deficit Restoration by Venturers	11
6.4	Withholding	12

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Article 7. RIGHTS AND OBLIGATIONS OF VENTURERS		12
7.1	Limited Liability	12
7.2	Authority	12
Article 8. MANAGEMENT AND CONTROL		12
8.1	Powers and Duties of the Board of Managers	12
8.2	Appointment of Board Members	12
8.3	Removal of Board Members	13
8.4	Chairman	13
8.5	Board Member Remuneration	13
8.6	Board Meetings	14
8.7	Quorum	14
8.8	Voting	15
8.9	Unanimous Written Consent	15
8.10	GM	15
8.11	Authority and Accountability of GM	15
8.12	Authority to Delegate	16
8.13	Remuneration	16
8.14	Board Reserved Matters	16
Article 9. TRANSFERS OF VENTURE INTERESTS		20
9.1	Transfers	20
9.2	Public Offering	20
Article 10. DEFAULTS; TERMINATION		20
10.1	Default	20
10.2	Remedies	21
10.3	Dissolution	21
10.4	Application of Assets	21
Article 11. MISCELLANEOUS		21
11.1	Notices	21
11.2	Successors and Assigns	22
11.3	Applicable Law	22
11.4	Severability	22
11.5	Entire Agreement	22
11.6	Titles	22
11.7	Further Assurances	23
11.8	Consent to Jurisdiction	23
11.9	Amendments	23
11.10	Waiver of Jury Trial	23
11.11	Prevailing Party	23
11.12	Confidentiality	23
11.13	Counterparts	24
11.14	Independent Legal Advice	24
11.15	Equitable Relief	24
11.16	Creditors	24

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SCHEDULES AND EXHIBITS

Schedule 2.6	Venturers
Schedule 2.7	Representations and Warranties
Schedule 4.2	Reporting Requirements
Schedule 4.4	Approved Annual Budgets 2021-2022

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BKV-BPP POWER, LLC

LIMITED LIABILITY COMPANY AGREEMENT

Article 1. RECITALS AND DEFINITIONS

This Limited Liability Company Agreement (this “Agreement”) is entered into as of October 29, 2021 (the “Effective Date”) by and between BKV Corporation, a Delaware corporation (“BKV”), with a business address of 1200 17^th Street, Suite 2100, Denver, CO 80202, and Banpu Power US Corporation, a Delaware corporation (“BPPUS”), with a business address of c/o Corporation Service Company, 251 Little Falls Drive, in the City of Wilmington, County of New Castle, Delaware 19808. BKV and BPPUS are hereinafter each individually referred to as a “Venturer” and, collectively as the “Venturers.”

1.             Recitals. The Venture has been formed to acquire Temple Generation Intermediate Holdings II, LLC (the “Company”), and is being formed to own the limited liability interests of Company, and to manage the Business in accordance with terms and conditions contained herein. The Company is the direct owner of all equity interests in Temple Generation I, LLC, a Delaware limited liability company (the “Project Company”). The Project Company is the owner of (i) the Temple 1 Project and (ii) 50% of the equity interests in Temple Generation SF LLC, a Delaware limited liability company (the “SPE”);

BKV and BPPUS view the Company as a first step in a long-term partnership to grow and develop a power business in the United States. The Venturers desire and intend for the Company to create value and long-term success for the Venturers. The Venturers further desire to work together in good faith to establish a framework for cooperation and development of the Company going forward so that both Venturers feel they are being heard and all opinions and thoughts are valued and respected. This framework will be developed jointly by the Board (as hereinafter defined) through this Agreement;

To the extent practical, the Company will be structured in accordance with the applicable customary practices and procedures in the United States for Delaware limited liability companies engaging in the power sector. According to the terms of this Agreement, the Board will be vested with the authority to govern the Company and the Board in turn will seek to delegate appropriate authority to the general manager (“GM”), as applicable, in line with U.S. market practice for companies in the power sector. Pursuant to the terms of this Agreement and as the Board may determine, the GM may make any decision for day-to-day management of, and administration services to, the Company that is not designated as a Board Reserved Matter in this Agreement, as long as and to the extent permitted allowed by applicable law and the short-term and long-term Business Plan and the Annual Budget to be designated and approved by the Board from time to time in accordance with this Agreement. The GM shall be subject to the overall authority, supervision and direction of the Board; and

The Venturers recognize the overarching goal of maintaining a successful working relationship and partnership for the long term with the objective of developing the existing and future power assets of the Company as one team and therefore agree that all Venturers should be afforded fair and equitable treatment (except for the additional treatment required to achieve the purpose of financial accounting objective set out below).

1.1           Definitions. Capitalized terms used in this Agreement shall have the meanings set forth or referred to below.

“Act” means, the Limited Liability Company Act of the State of Delaware.

“Administrative Services Agreement” – See Section 4.8.

“Adjusted Capital Account” – See Section 5.3.

“Affiliate” means, with respect to any Person, any other Person directly or indirectly Controlling or Controlled by, or under direct or indirect common Control with, such Person.

“Agreement” – See preamble.

“Annual Budget” – See Section 1.

“Approved Budget” – See Section 4.4.

“BKV” – See preamble.

“BNAC” – See Section 3.1.

“Board” – See Section 8.2.

“Board Reserved Matters” – See Section 8.14.

“BPPUS” – See preamble.

“Business” means the direct or indirect ownership, operation, maintenance, financing, administration and improvement of the Temple 1 Project, including the generation and sale or purchase of electricity, capacity, ancillary services, steam, fuel, or water with respect to the Temple 1 Project and the conduct of other activities related or incidental to the foregoing, including the ownership interest in the SPE.

“Business Day” means any day except a Saturday, Sunday or any other day on which commercial banks in Fort Worth, Texas are authorized or required by law to close. If a date set for any action hereunder is not a Business Day then such date for action shall be the next succeeding day that is a Business Day.

“Business Plan” – See Section 4.4.

“Capital Account” – See Section 5.1.

“Capital Contributions” means, for each Venturer, the sum of (i) such Venturer’s Initial Capital Contribution under Section 3.1 and (ii) such Venturer’s additional capital contributions under Section 3.2.

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“Certificate” – See Section 2.1.

“Chairman of the Board” – See Section 8.4.

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

“Company” – See Section 1.

“Confidential Information” – See Section 11.12.

“Designated Individual” – See Section 4.6.

“Effective Date” – See preamble.

“Emergency” means any situation or event, as determined in good faith by the requesting Venturer, which resulting in a state that calls for immediate action that without such action may result in disruption to the operation of the Temple I Project, significant loss of or damage to property, loss of life or significant injury to any person or party and/or adversely impact a third party, accidental pollution, or threaten the Venture or its affiliates’ reputation.

“Event of Default” – See Section 10.1.

“Fiscal Year” – See Section 4.7.

“GM” – See Section 1.

“Governmental Authority” means any governmental or quasi-governmental authority or official, including, without limitation, any federal, state, territorial, county, district, municipal or other governmental or quasi-governmental agency, board, branch, bureau, commission, court, department, other instrumentality, political unit, subdivision or official, whether domestic or foreign.

“IRS” means the United States Internal Revenue Service.

“Majority” means more than 50% of the votes cast.

“Material Contract” means the following agreements without any threshold: (a) power purchase agreement, (b) gas transportation agreement, (c) gas supply and storage agreement, ((d) long-term services agreement, and e) energy management agreement, (f) asset management agreement,

and the following agreements provided they are in excess of $1,500,000 per contract individually or $5,000,000 per year in aggregate: (a) any agreement for indebtedness, (b) treasury and accounting agreement; and (c) operation and maintenance agreement.

“Net Capital Proceeds” means proceeds from any sale, refinancing, insurance recovery, eminent domain award or other similar capital event, in excess of amounts used to pay debt then due, transaction costs, amounts applied to restore or improve the Temple 1 Project and reserves reasonably required by the Venturers to fund contingent or unmatured liabilities of the Venture.

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“Net Income” means sales less the total cost of goods sold, selling, general, and administrative expenses, operating expenses, depreciation, interest, taxes, and other expenses.

“Notices” – See Section 11.1.

“Operating Cash Flow” means, for a given period, all cash receipts of the Venture (other than proceeds from a capital event) during such period in excess of the following items attributable to such period (except to the extent any of the following are funded out of reserves or proceeds from capital events): operating expenses, debt service, expenditures on capital improvements and reserves reasonably required by the Venturers to fund contingent or unmatured liabilities of the Venture.

“Ownership Percentages” has the meaning set forth in Schedule 2.6.

“Qualified Income Offset” – See Section 5.5.

“Partnership Representative” has the meaning set forth in Section 4.6.

“Person” means any individual, corporation, partnership, joint venture, limited liability company, limited liability partnership, association, joint stock company, trust, unincorporated organization, or other organization, whether or not a legal entity, and any Governmental Authority.

“Project Company” – See Section 1.

“Regulatory Allocations” – See Section 5.6.

“Report Requirements” – See Schedule 4.2.

“SPE” – See Section 1.

“Taxable Year” – See Section 4.7.

“Temple 1 Project” means the Temple I combined cycle gas turbine facility in Temple, Texas, together with all auxiliary equipment, ancillary and associated facilities and equipment, electrical transformers, cooling and waste water management facilities and electrical interconnection and metering facilities (whether owned or leased) used for the receipt of fuel and water and the delivery of the electrical output of such plant, and all other improvements and other assets related to the ownership, operation and maintenance of such plant and associated equipment.

“Treasury Regulations” means the regulations promulgated under the Code, as such regulations may be amended from time to time (including corresponding provisions of succeeding regulations).

“Venture” – See Section 2.1.

“Venture Minimum Gain” – See Section 5.4.

“Venturer” – See preamble.

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“Venturer Loan Agreement” – See Section 3.1.

“Venturer Nonrecourse Debt Minimum Gain” – See Section 5.4.

Article 2. FORMATION OF VENTURE

2.1           Organization. With the consent of the Board, BKV-BPP Power, LLC (the “Venture”) has been formed by the filing of its Certificate of Formation with the Delaware Secretary of State pursuant to the Act. The Certificate of Formation may be restated as provided in the Act or amended to change the address of the office of the Venture in Delaware and the name and address of its resident agent in Delaware or to make corrections required by the Act. The Certificate of Formation, as so amended from time to time, is referred to herein as the “Certificate.” BKV shall deliver a copy of the Certificate and any amendment thereto to any Venturer who so requests. Each of BKV and BPPUS are hereby admitted as a member of the Venture.

2.2           Purposes and Powers. The principal business activity and purposes of the Venture shall be to manage the assets and property of the Venture and to engage in all actions necessary, convenient or incidental thereto. The Venture shall not engage in any other business or activity.

2.3           Principal Business Office, and Registered Agent. The principal business office of the Venture shall be located at 1200 17th Street, Suite 2100, Denver, CO 80202. The principal business office of the Venture may be changed from time to time by consent of the Board. The agent for service of process on the Venture shall be Corporation Service Company.

2.4           Qualification in Other Jurisdictions. BKV shall cause if necessary, the Venture, to be qualified or registered in any other jurisdiction in which the Venture transacts business.

2.5           Powers. In furtherance of its purposes, but subject to all of the provisions of this Agreement, the Venture shall have and exercise all of the powers and rights which can be conferred upon limited liability companies formed pursuant to the Act.

2.6           Venturers. The Venturers of the Venture, their addresses, and their Ownership Percentages shall be listed on Schedule 2.6 and said Schedule 2.6 shall be amended from time to time by the Board, to reflect the withdrawal of Venturers or the admission of additional Venturers pursuant to this Agreement.

2.7           Representations and Warranties. As an inducement for the Venturers to enter into this Agreement, the Venturers, as applicable, make the representations and warranties set forth on Schedule 2.7.

2.8           Title to Company Assets. Title to the Venture’s assets, whether real, personal or mixed and whether tangible or intangible, shall be vested in the Venture as an entity, and no Venturer shall have any ownership interest in the Venture’s assets or any portion thereof. Each Venturer hereby waives any right such Venturer may at any time have to cause the Venture’s assets to be partitioned among the Venturers or to file any complaint or to institute any proceeding at or in equity seeking to have any one or all of the Venture’s assets partitioned. The Venture currently owns 100% of the equity interests in the Company, which owns 100% of the equity interests in the Project Company, which owns the Temple 1 Project.

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2.9           No State Law Partnership. The Venturers shall be “members” of a limited liability company for all purposes under applicable state law. The Venturers do not intend for the Venture to be a partnership (including a limited partnership) or joint venture under applicable state law, and no Venturer shall be a partner or joint venturer of any other Venturer by reason of this Agreement for any purpose other than federal and, if applicable, state income tax purposes, and this Agreement shall not be interpreted to provide otherwise. The Venturers intend that the Venture will be treated as a partnership for federal and, if applicable, state income tax purposes, and each Venturer and the Venture will file all tax returns and will otherwise take all tax and financial reporting positions in a manner consistent with such treatment. The Venture will not make any election to be treated as a corporation for federal and, if applicable, state income tax purposes, except with the approval of the Board.

Article 3. CAPITALIZATION

3.1           Initial Capital Contributions. Upon execution and delivery of this Agreement, (i) BPPUS shall make a capital contribution to the Venture in the amount of $89,000,000 United States Dollars inform of equity contribution (“BPPUS’s Initial Capital Contribution”) and (ii) BKV shall make a capital contribution to the Venture in the amount of $89,000,000 United States Dollars in form of equity contribution (“BKV’s Initial Capital Contribution”). In addition, BPPUS agrees to lend to the Venture in amount of $141,000,000 while Banpu North America Corporation (“BNAC”) agrees to lend to the Venture in amount of $141,000,000. Such loans are further described in the Venturer Loan Agreement dated as of October 14, 2021 by and among BPPUS, the Venture and BNAC and the Venture (“Venturer Loan Agreement”).

3.2           Additional Capital Contributions. Either BPPUS or BKV, upon thirty Business Days prior written notice, may request that additional cash Capital Contributions be made and the Venturers shall make such Capital Contributions, provided such additional cash Capital Contributions shall be expended on items included in the annual Approved Budget, items in response to an Emergency if the Venture does not have sufficient cash reserves to fund such Emergency, or any other matter approved by the Board. No Venturer will be obligated to make such additional cash Capital Contributions not otherwise required under this Agreement without its consent.

3.3           Form of Capital Contributions. Except as specifically provided for herein, all amounts to be contributed or paid by a Venturer under this Article 3 shall be paid in cash in US dollars.

3.4           No Right to Interest or Return of Capital. Except as specifically provided for herein, no Venturer shall be entitled to any return of, or interest on, Capital Contributions to the Venture or any other amounts funded pursuant to this Article 3.

Article 4. BOOKS; ACCOUNTING; TAX ELECTIONS; REPORTS

4.1           Books and Records. BKV shall keep complete and accurate books and records of the Venture. The books of the Venture shall be kept in accordance with the accounting method utilized by the Venture for federal income tax purposes. The books of the Venture shall at all times be maintained or made available at the principal business office of the Venture.

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4.2           Financial Statements; Reports. BKV shall prepare, or have prepared, and shall furnish to the Venturers the reports listed in Schedule 4.2 (the “Reporting Requirements”) within the time periods set forth on Schedule 4.2. BKV shall cooperate and respond, using commercially reasonable efforts, to requests by the Venturers to reasonably expand or modify the format and content of the Reporting Requirements.

4.3           Insurance Program. BKV shall coordinate and implement an insurance program for the Venture that has been approved by the Board.

4.4           Approval of Budgets and Business Plans.

(a)           The Board shall prepare, or have prepared, an annual Approved Budget and a Business Plan for Fiscal Year 2023 and each Fiscal Year thereafter no later than September 15th of each current Fiscal Year. The Venture shall implement in each Fiscal Year the Approved Budget and Business Plan. Provided, the GM is hereby authorized to make expenditures of up to $5,000,000 outside of the Approved Budget, per occurrence, and to take all other reasonable measures to protect the Venture and the Business in case of Emergencies. In the event the GM expends funds pursuant to the provisions of this Section 4.4, the GM shall notify the Board of such expenditures commencing as soon as possible following the first expenditure of such funds and keep the Board appraised of all follow up expenditures. If an expenditure over $5,000,000 is required to respond to an Emergency, either Venturer may call an emergency meeting of the Board to review and approve such expenditure. The Approved Budget for 2021 and 2022 agreed by the Venturers are attached hereto as Schedule 4.4.

(b)           Except as otherwise contemplated in Section 4.4(a) above, any amendment to the Approved Budget and Business Plan shall require approval by the Board.

4.5           Filing of Returns. BKV shall prepare, or have prepared, all information and materials necessary to enable the tax return preparer to cause the preparation of all tax returns for the Venture. The Venture’s income tax returns are subject to the Venturers’ approval prior to filing. The final tax returns shall be provided to the Venturers promptly after approval of the draft tax returns and in any event, within ninety (90) days after the end of each Fiscal Year.

4.6           Partnership Representative.

(a)           BKV shall be or designate the “Partnership Representative” of the Venture within the meaning of Section 6223 of the Code, or any corresponding or similar provisions under state, local or non-U.S. law and any successor Partnership Representative.  The Partnership Representative shall serve as such at the expense of the Venture with all powers granted to a partnership representative under the Code (or any corresponding or similar provision of state, local or non-U.S. tax law). BKV shall have sole authority to designate any “Designated Individual” as described in Treasury Regulations Section 301.6223-1 (and any similar provisions of state and local law) and any successor Designated Individual.

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(b)           The Partnership Representative shall represent the Venture in any disputes, controversies, or proceedings with the IRS or with any state, local, or non-U.S. taxing authority.  Except as otherwise provided in this Section 4.6, the Partnership Representative shall be entitled to take such actions on behalf of the Venture in any and all proceedings with the IRS and any other such taxing authority as it reasonably determines to be appropriate and any decision made by the Partnership Representative shall be binding on all Venturers, provided, the Partnership Representative receives approval of the Board with respect to its duties.  The Venturers agree to cooperate in good faith to timely provide information reasonably requested by the Partnership Representative. Any cost or expense incurred by the Partnership Representative in connection with its duties as such, including the preparation for or pursuance of administrative or judicial proceedings, shall be paid by the Venture. Without limiting the foregoing, the Partnership Representative shall apply the provisions of subchapter C of charter 63 of the Code, or similar provisions of state, local or non-U.S. tax law, with respect to any audit imputed underpayment, other adjustment, or any such decision or action by the IRS (or other tax authority) with respect to the Venture or the Venturers for such taxable years, as determined by the Partnership Representative. No Venturer shall have any claim against the Venture, Partnership Representative, or the Board for any form of damages or liability as a result of actions taken or remedies pursued by or on behalf of the Venture in order to comply with the rules under subchapter C of charter 63 of the Code, or similar provisions of state, local or non-U.S. law.

(c)           The Partnership Representative and/or the designated individual shall have no personal liability arising out of his, her or its good faith performance of his, her or its duties as the Partnership Representative and/or designated individual hereunder. Except with the permission of the Partnership Representative, no Venturer shall take a position on any tax return or other filing with any tax authority (or court) with respect to an item of income, gain, loss, deduction or credit attributable to the Venture that is inconsistent with the Venture’s treatment of such item on its tax return or request an administrative adjustment under Section 6222(c) of the Code.

4.7           Fiscal and Taxable Year. The “Fiscal Year” of the Venture shall be the same as the taxable year and the taxable year of the Venture shall be the same as the taxable year of BKV, which taxable year currently ends on December 31.

4.8           Administrative Services Agreement. The Venturers will work in good faith to negotiate a mutually acceptable Administrative Services Agreement between the Venture and BKV or other administrative service providers, which shall be executed no later than forty-five (45) days following the date hereof and the consummation of the acquisition of the Company. The execution or termination of the Administrative Services Agreement or any other agreement between the Venture and BKV or other administrative service providers (as the case may be), or any material amendment of or waiver of material rights thereunder shall be acknowledged by the Board and approved by BPPUS in its sole and absolute discretion.

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Article 5. CAPITAL ACCOUNTS; ALLOCATION OF INCOME AND LOSS

5.1           Capital Accounts. A separate capital account (each, a “Capital Account”) shall be maintained for each Venturer in accordance with the rules of Treasury Regulations Section 1.704-1(b)(2)(iv), and this Section 5.1, and shall be interpreted and applied in a manner consistent therewith. Whenever the Venture would be permitted to adjust the Capital Accounts of the Venturers pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(f) to reflect revaluations of Venture property, the Venture shall so adjust the Capital Accounts of the Venturers. In the event that the Capital Accounts of the Venturers are adjusted pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(f) to reflect revaluations of Venture property, (i) the Capital Accounts of the Venturers shall be adjusted in accordance with Treasury Regulations Section 1.704-1(b)(2)(iv)(g) for allocations of depreciation, depletion, amortization and gain or loss, as computed for book purposes, with respect to such property, (ii) the Venturers’ distributive shares of depreciation, depletion, amortization and gain or loss, as computed for tax purposes, with respect to such property shall be determined so as to take account of the variation between the adjusted tax basis and book value of such property in the same manner as under Code Section 704(c) and (iii) the amount of upward and/or downward adjustments to the book value of the Venture property shall be treated as income, gain, deduction and/or loss for purposes of applying the allocation provisions of Section 5.2. In the event that Code Section 704(c) applies to Venture property, the Capital Accounts of the Venturers shall be adjusted in accordance with Treasury Regulations Section 1.704-1(b)(2)(iv)(g) for allocations of depreciation, depletion, amortization and gain and loss, as computed for book purposes, with respect to such property in the manner contemplated by Section 5.7.

5.2           Allocation of Income and Loss. After application of Section 5.3 and Section 5.4, and subject to the other provisions of this Article 5, all remaining items of Venture income, gain, loss and deduction as determined for book purposes for the taxable year shall be allocated among the Capital Accounts of the Venturers in such a manner as shall cause the Capital Accounts of the Venturers (as adjusted through the end of such Fiscal Year or other period) to equal, as nearly as possible, in the same proportionate amounts as (a) the amount such Venturers would receive if all assets of the Venture on hand at the end of such Fiscal Year or other period were sold for cash equal to their book values, all liabilities of the Venture were satisfied in cash in accordance with their terms (limited in the case of non-recourse liabilities to the book value of the property securing such liabilities), and all remaining or resulting cash was distributed to the Venturers under Section 6.2 minus (b) such Venturer’s share of Venture Minimum Gain (as defined below) and Venturer Nonrecourse Debt Minimum Gain (as defined below), computed immediately prior to the hypothetical sale of assets. Notwithstanding the foregoing, the Board may adjust the allocations made pursuant to this Agreement as long as such adjusted allocations are intended to be in accordance with the interests of the Venturers in the Venture and in accordance with section 704(c) of the Code and the Treasury Regulations thereunder.

5.3           Loss Limitation. Net loss allocated pursuant to Section 5.2 shall not exceed the maximum amount of net loss that can be allocated without causing or increasing a deficit balance in a Venturer’s Adjusted Capital Account after application of the Qualified Income Offset described in Section 5.5. A Venturer’s “Adjusted Capital Account” balance shall mean such Venturer’s Capital Account balance increased by such Venturer’s obligation to restore a deficit balance in its Capital Account, including any deemed obligation pursuant to the penultimate sentences of Treasury Regulations Sections 1.704-2(g)(1) and 1.704-2(i)(5), and decreased by the amounts described in Treasury Regulations Section 1.704-1(b)(2)(ii)(d)(4), (5) or (6).

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5.4           Minimum Gain Chargebacks and Nonrecourse Deductions. Notwithstanding any other provision of this Agreement:

(a)           Venture Minimum Gain Chargeback. In the event there is a net decrease in Venture Minimum Gain during a Fiscal Year (or if there was a net decrease in Venture Minimum Gain for a prior Fiscal Year and the Venture did not have sufficient amounts of income and gain during prior Fiscal Years to allocate among the Venturers under this Section 5.4(a)), the Venturers shall be allocated items of income and gain in accordance with Treasury Regulations Section 1.704-2(f). For purposes of this Agreement, the term “Venture Minimum Gain” shall have the meaning for partnership minimum gain set forth in Treasury Regulations Section 1.704-2(b)(2), and any Venturer’s share of Venture Minimum Gain shall be determined in accordance with Treasury Regulations Section 1.704-2(g)(1). This Section 5.4(a) is intended to comply with the minimum gain chargeback requirement of Treasury Regulations Section 1.704-2(f) and shall be interpreted and applied in a manner consistent therewith.

(b)           Nonrecourse Deductions. Nonrecourse Deductions shall be allocated to the Venturers pro rata in accordance with their Ownership Percentages. For purposes of this Agreement, the term “Nonrecourse Deductions” shall have the meaning set forth in Treasury Regulations Section 1.704-2(b)(1). This Section 5.4(b) is intended to comply with Treasury Regulations Section 1.704-2(e) and shall be interpreted and applied in a manner consistent therewith.

(c)           Venturer Nonrecourse Debt. To the extent required by Treasury Regulations Section 1.704-2(i), any items of income, gain, loss or deduction of the Venture that are attributable to a nonrecourse debt of the Venture that constitutes Venturer Nonrecourse Debt (including chargebacks of Venturer Nonrecourse Debt Minimum Gain) shall be allocated in accordance with the provisions of Treasury Regulations Section 1.704-2(i). For purposes of this Agreement, the term “Venturer Nonrecourse Debt” shall have the meaning for partner nonrecourse debt set forth in Treasury Regulations Section 1.704-2(b)(4), and the term “Venturer Nonrecourse Debt Minimum Gain” shall have the meaning for partner nonrecourse debt minimum gain set forth in Treasury Regulations Section 1.704-2(i)(2). This Section 5.4(c) is intended to satisfy the requirements of Treasury Regulations Section 1.704-2(i)(4) (including the partner nonrecourse debt minimum gain chargeback requirement) and shall be interpreted and applied in a manner consistent therewith.

5.5           Qualified Income Offset. Any Venturer who unexpectedly receives an adjustment, allocation or distribution described in Treasury Regulations Section 1.704-1(b)(2)(ii)(d)(4), (5) or (6) that causes or increases a deficit balance in its Capital Account in excess of any obligation to restore a deficit balance in its Capital Account (including any deemed deficit restoration obligation pursuant to the penultimate sentences of Treasury Regulations Sections 1.704-2(g)(1) and (i)(5), and adjusted as provided in Treasury Regulations Section 1.704-1(b)(2)(ii)(d)) shall be allocated items of income and gain (consisting of a pro rata portion of each item of income, including gross income, and gain for the Fiscal Year) in an amount and a manner sufficient to eliminate, to the extent required by the Treasury Regulations, such deficit balance as quickly as possible. This Section 5.5 is intended to constitute a qualified income offset under Treasury Regulations Section 1.704-1(b)(2)(ii)(d) and shall be interpreted and applied in a manner consistent therewith.

5.6           Curative Allocations. The allocations set forth in Section 5.4 and Section 5.5 (the “Regulatory Allocations”) are intended to comply with the requirements of Treasury Regulations Sections 1.704-1(b) and 1.704-2. Notwithstanding any other provisions of this Article 5 (other than the Regulatory Allocations), the Regulatory Allocations shall be taken into account as provided for in the following sentence. Income, gain, loss and deduction shall be reallocated to the extent that such reallocation causes the net aggregate amount of allocations of income, gain, deduction and loss to each Venturer to be equal to or more closely approximate the net aggregate amount of such items that would have been allocated to each such Venturer if the Regulatory Allocations had not occurred.

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5.7           Tax Allocations. Allocations pursuant to this Section 5.7 are solely for purposes of federal, state, and local taxes and shall not affect, or in any way be taken not account in computing, any Venturer’s Capital Account or share of income, gain, deduction or loss or other items or distributions pursuant to any provision of this Agreement. Except as otherwise required by the Code and Treasury Regulations, items of income, gain, deduction, loss or credit, as determined for tax purposes, shall be allocated to and among the Venturers in the same manner that the corresponding book items were allocated to the Venturers’ Capital Accounts in accordance with this Article 5. In the event the book value of any asset of the Venture is adjusted pursuant to the other provisions of this Agreement (not including herein the initial booking of any asset contributed to the Venture), subsequent allocations of taxable income, gain, loss and deduction, as determined for tax purposes, with respect to such asset of the Venture shall be determined and allocated among the Venturers so as to account for any book-tax disparity arising from such adjustment in the same manner as would occur as to an asset contributed to the Venture under Code Section 704(c) and the Treasury Regulations thereunder.  The Board shall determine the method of allocation from among the reasonable methods allowable by Code Section 704(c) and the Treasury Regulations thereunder.

5.8           Other Tax and Allocation Provisions. In the event it becomes necessary to make any elections or decisions relating to the allocations of Venture items of income, gain, loss, deduction or credit and/or with respect to any tax matters, BKV shall bring such elections or other decisions to the attention of the Board, and such elections or other decisions shall be made as directed by the Board in any manner that reasonably reflects the purpose and intention of this Agreement. Further, the Venture may, if the Board reasonably so elects, make an election pursuant to Code Section 754 and the Treasury Regulations thereunder (and a corresponding election under the applicable sections of state and local law).

Article 6. DISTRIBUTIONS

6.1           Reserves. The Venture shall maintain such reserves at the Venture level as the Board shall reasonably require in light of potential obligations of the Venture. This obligation shall be reflected in the Annual Budget.

6.2           Distributions. The Board shall determine the amount and timing of distributions of Operating Cash Flow, which shall be no less frequently than quarterly, if available, and Net Capital Proceeds, which shall be distributed to the Venturers within three (3) Business Days after the same become available for distribution. All distributions pursuant to this Section 6.2 shall be made on a pro-rata basis to the Venturers based on their respective Ownership Percentages.

6.3           No Deficit Restoration by Venturers. No Venturer shall be required to contribute capital to the Venture to restore a deficit balance in its Capital Account upon liquidation or otherwise, except as specifically required by law.

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6.4           Withholding. If the Venture incurs a withholding tax obligation with respect to the share of income allocated to any Venturer or with respect to any other payments to a Venturer or their Affiliates with respect to any foreign, federal, state, or local tax or withholding liability arising as a result of such Venturer’s interest in the Venture, the Venture shall be entitled to withhold such amount and (a) any amount which is (i) actually withheld from a distribution or payment that would otherwise have been made to such Venturer or its Affiliates and (ii) paid over in satisfaction of such withholding tax obligation to any government authority shall be treated for all purposes under this Agreement as if such amount had been distributed or paid to such Venturer as of the date of such withholding, and (b) any amount which is so paid over by the Venture, but which exceeds the amount, if any, actually withheld from a distribution or other payment which would otherwise have been made to such Venturer or its Affiliates, shall be treated as an interest-free advance to such Venturer (including with respect to amounts paid to any of its Affiliates). Amounts treated as advanced to any Venturer pursuant to this Section 6.4 shall be repaid by such Venturer to the Venture within 30 days after BKV gives notice to such Venturer making demand therefore.

Article 7. RIGHTS AND OBLIGATIONS OF VENTURERS

7.1           Limited Liability. Except as otherwise provided in the Act, no Venturer shall be obligated for any debt, obligation or liability of the Venture or of any other Venturer, whether arising in contract, tort or otherwise, solely by reason of being a Venturer.

7.2           Authority. Unless specifically authorized by the written approval of the Board, no Venturer shall be an agent of the Venture or have any right, power or authority to act for or to bind the Venture or to undertake or assume any obligation or responsibility of the Venture.

Article 8. MANAGEMENT AND CONTROL

8.1           Powers and Duties of the Board of Managers.

(a)           The Board of Managers (“Board”) shall be responsible for, and have the authority to control and operate, the business and affairs of the Venture and the interests of the Venturers collectively so as to maximize the Venture’s equity value, without regard to the individual interests of any Venturer.

(b)           Except for the Board Reserved Matters, the Board delegates certain authority to manage and administer the Business and affairs of the Venture to the GM in accordance with Sections 8.10 – 8.12.

8.2           Appointment of Board Members.

(a)           The total number of the Board members shall be eight (8), or such other number as may be determined from time to time by the majority vote of the Board members present and entitled to vote at a duly convened meeting of the Board.

(b)           For so long as BPPUS holds equity interests in the Venture, four (4) individuals nominated by BPPUS shall be elected as Board members.

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(c)           For so long as BKV holds equity interests in the Venture, four (4) individuals nominated by BKV shall be elected as Board members.

(d)           The initial Board shall consist of the following members:

(i)            As nominees of BPPUS: Mr. Voravudhi Linananda, Dr. Kirana Limpaphayom, Dr. Paul Didsayabutra, Mr. Dechapong Yuwaprecha

(ii)           As nominees of BKV: Mr. Anon Sirisaengtaksin, Mr. Thiti Mekavichai, Mr. Christopher Kalnin and Mr. Daniel Androphy

(e)           Each member of the Board shall serve a term of up to three (3) years as determined by the Board. A member whose term has expired may be nominated for re-election in accordance with this Section 8.2.

8.3           Removal of Board Members.

(a)           A Board member may be removed by notice in writing to the Venture by the Venturer who nominated him/her.

(b)           A Board member may be removed where such a Board member is formally charged by a Governmental Authority or regulatory body to have acted in material breach of the law or to have committed any serious criminal offense, or determined by the Board to have committed a breach of any fiduciary duty or material breach of other duty in relation to the Venture, by notice in writing to the Venture from any Venturers, and, in either such event, the Venturer that nominated such Board member shall promptly nominate another Board member in his/her place in accordance with Section 8.2.

8.4           Chairman.

(a)           The Majority of the Board shall designate the Chairman of the Board, who shall serve a term of three (3) years.

(b)           The Chairman shall chair all meetings of the Board at which he/she is present. The Chairman shall ensure that all relevant papers for any Board meeting are properly circulated in advance and that all such Board meetings are quorate.

(c)           If the Chairman is not present at any Board meeting, the Board members present may select any member to act as Chairman for the purpose of such meeting.

(d)           If the Chairman ceases to hold office as a Board member during his/her term, the Board shall nominate another of its nominated Board members to be elected as the Chairman for the remainder of the term of the Chairman who ceased to hold office.

8.5           Board Member Remuneration.

(a)           The Venture shall cause each Board member promptly to be reimbursed for all reasonable and documented out-of-pocket costs and expenses incurred by him or her in connection with attending meetings of the Board and other meetings and events attended on behalf of the Venture as a member of the Board.

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(b)           The Board members will not receive remuneration for their services on the Board.

8.6           Board Meetings

(a)           The Board shall decide how often Board meetings shall take place, provided that:

(i)             they are held monthly on the third (3^rd) week of each month, unless at least a simple majority of the Board agrees otherwise; and

(ii)            any Board member may propose to convene a Board meeting at any time.

(b)           Participation.

(i)           Any Board member shall be entitled to participate in a meeting of the Board of which he or she is a member, at which he or she is not physically present, using any technology, including telephone or video conference or similar electronic means. A meeting called and/or held by means of a telephone conference or a video conference or any similar communication equipment is deemed to be held at the place agreed upon by the Board members attending the meeting.

(c)           Notice/Agenda.

(i)            At least five (5) Business Days’ prior written notice, by hand, email, courier or registered mail, shall be given to each of the Board members of all Board meetings, except where a Board meeting is adjourned under Section 8.7 or a shorter notice period has been agreed in writing by all of the Board members; provided, however, that attendance by a Board member at a Board meeting without receiving any notice shall constitute waiver by him or her of the notice required for such Board meeting under this Section 8.6(c)(i). Such notice shall contain a reasonably detailed agenda and shall be accompanied by any relevant papers.

(ii)           Any Venturer or any Board member may propose an item for inclusion in the agenda together with a related resolution to be proposed at such Board meeting.

8.7           Quorum.

(a)           Subject to the following provisions of this Section 8.7, the quorum at a Board meeting shall be at least a simple majority of the Board.

(b)           If a quorum is not present within half an hour of the time appointed for the meeting or if a quorum ceases to be present during the course of the meeting, the Board members present shall adjourn the Board meeting to a specified place and time not less than three (3) Business Days after the date of such Board meeting where the same quorum shall be required.

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(c)           If such quorum set forth in Section 8.7(b) is still not present within half an hour of the time appointed for such adjourned Board meeting or if such quorum ceases to be present during the course of such adjourned Board meeting, the Board members present shall again adjourn the Board meeting to a specified place and time not less than three (3) Business Days after the date of such adjourned Board meeting, where the quorum shall be at least any simple majority of the Board.

(d)           Notice of any adjourned Board meeting shall be given to all of the Board members.

8.8           Voting. Subject to only Section 8.9 and the Board Reserve Matters, at any Board meeting each Board member shall have one (1) vote and, except where unanimity is otherwise required, all decisions at Board meetings shall be taken by at least simple majority of the votes of the Board members present and entitled to vote. In case of a deadlock among the Board, two BKV directors and two BPPUS directors shall meet and attempt to reach agreement on the deadlock issue. In the event such directors are unable to reach unanimous agreement within fifteen (15) days after the first meeting then such deadlock matter shall go back to the Board and shall be determined by a majority vote of the Board. Provided, however, that if such deadlock could not be solved by the Board, the issue shall be referred to the Venturers for a final decision.

8.9           Unanimous Written Consent. Any decision or other action to be taken by the Board at any Board meeting may, in lieu of a Board meeting, be taken with the unanimous written consent of all Board members with the same effect as if such decision or action was taken at a duly convened meeting of the Board.

8.10         GM.

(a)           The GM may be an employee or officer of BKV or BPPUS.

(b)           The Board shall endeavor to appoint a GM, with the approval of BPPUS, on or before twelve (12) months from the date of this Agreement. The Board, with the approval of BPPUS, may remove and replace the GM. The Board has designated Christopher Kalnin and Paul Didsayabutra as Managers of the Venture, each authorized to sign documents and exercise the duties of the GM in accordance with Sections 8.10 – 8.12 until a permanent GM is appointed by the Board.

8.11         Authority and Accountability of GM.

(a)           Subject to the Board Reserved Matters and this Agreement, the GM shall have the power to manage and administer the business and affairs of the Venture in accordance with the Business Plan and Approved Budget, expenditures under the thresholds in the Board Reserved Matters, and as permitted pursuant to Section 4.4 regarding Emergencies.

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(b)           The GM shall be the focal point for, and shall be accountable to, the Board. Subject to Section 8.11(a), the GM shall have full authority to decide, agree, consent to, approve, perform, enter into, delegate or otherwise undertake any activity that does not violate applicable Law for and on behalf the Venture which does not fall within the scope of the Board Reserved Matters, unless it is legally required that such activity requires the prior approval of the Board.

(c)           The taking of any action or decision by the GM that is a Board Reserve Matter without the prior approval of the Board will be considered a material breach under this Agreement.

8.12         Authority to Delegate.

(a)           The GM shall have the right to execute an Administrative Service Agreement, which has been approved by BPPUS and acknowledged by the Board, to facilitate his duties under this Agreement.

(b)           The GM shall have the right to engage, appoint, remove or dismiss consultants or advisors provided the remuneration for such parties is included in the Approved Budget.

8.13         Remuneration. The GM will not be remunerated for his services under this Agreement unless otherwise approved in the Approved Budget.

8.14         Board Reserved Matters. The following items will be Board Reserved Matters and require the unanimous consent of the Board, except as may be delegated by the Board with unanimous consent from time to time:

(a)           Any merger, consolidation, amalgamation, conversion of the Venture or any subsidiary of the Venture into another form or entity or other business combination of any nature.

(b)           Any winding up, dissolution or liquidation or any commencement of or any filing or petition for a voluntary bankruptcy, reorganization, debt arrangement or other case or proceeding involving the Venture or any subsidiary of the Venture under, or obtaining relief under, any federal or state bankruptcy or insolvency law or making a general assignment for the benefit of creditors of the Venture or any subsidiary of the Venture.

(c)           Any plan to or initial sale of the Venture or other equity interests to the public pursuant to a registration under the Securities Act.

(d)           Any amendment, restatement, or revocation of the certificate of incorporation, bylaws, operating agreements, limited liability agreement, management agreements, or other constitutional or organizational documents of the Venture or any subsidiary of the Venture.

(e)           Any change to the Venture’s or any subsidiary of the Venture’s name, logo or trademark.

(f)           Any material amendment or modification to existing technical review process.

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(g)           Any entering into any new business or expanding the business into a new country, or changing the Venture’s business.

(h)           Setting up a joint venture or a business entity, making an investment in any new subsidiary, or changing the ownership structure of the Venture.

(i)            Unless specified otherwise in this Agreement, any transaction or contract with any Venturer, member of the Board or any entity, directly or indirectly, owned or controlled by any Venturer or any affiliate of such Venturer or by any member of the Board’s family.

(j)            Issuing any units or equity, or any increase or decrease of units or equity in the Venture or any subsidiary of the Venture.

(k)           Investment in any new entity (including, without limitation, through any entities or vehicles formed in connection with the making of investment in view of the legal, tax, regulatory, business).

(l)            Any acquisition or disposal by the Venture or any subsidiary of the Venture of any undertaking, business, company, or stocks or securities of a company.

(m)          Any acquisition or disposal by the Venture or any subsidiary of the Venture of any non-operational assets in excess of $1,500,000 on an individual basis.

(n)           (i) Any approval of the Business Plan and the Approved Budget (including operating, general and administrative and capital budgets), a long-term strategic direction and an overall management strategy, (ii) any amendments thereto, and (iii) any approval or ratification of any departure from the same; provided that BPPUS’s approval shall also be required for any increase in any Approved Budget in any Fiscal Year over 5% of the Approved Budget in the immediately prior Fiscal Year.

(o)           Conducting negotiations, supervising documentation or executing all agreements, instruments, documents and matters associated with, and any entry by the Venture or any subsidiary of the Venture into, any operational project which (i) exceed 3-year term, (ii) exceeds value of $2,000,000 per operational project, (iii) exceeds value of $10,000,000 in aggregate per Fiscal Year or (iv) accumulative exceeds the Approved Budget and Business Plan unless required for an Emergency.

(p)           Any lease or disposal by the Venture of any operational assets or property not being undertaken in the ordinary course of business that exceeds the amount of $5,000,000 individually or $10,000,000 in aggregate per Fiscal Year.

(q)           Procuring technology, big data and automation, which exceeds $200,000 individually or $500,000 in aggregate per Fiscal Year.

(r)            Execution, amendment or termination of any Material Contract.

(s)           Any creation, incurrence or assumption of any encumbrance over any assets or property of the Venture or any subsidiary of the Venture, outside the ordinary course of business, and any guarantee by the Venture or by any subsidiary of the Venture of any obligations of any person or provision of any credit support to the obligations of any person.

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(t)            Any suspension, cessation or abandonment of any day to day operational or non-material activity of the Venture or any subsidiary of the Venture, exceeding $500,000 individually or $1,000,000 in aggregate per Fiscal Year unless required for an Emergency as determined in good faith by the GM.

(u)           The incurring of any capital expenditure and operating expenditure (including obligations under hire-purchase and leasing arrangements) of any item or project which is not provided for in an Approved Budget and/or an approved Business Plan, and exceeding $500,000 individually or $1,000,000 in aggregate in Fiscal Year unless required for an Emergency.

(v)           Approval of the Venture’s initial corporate organization structure, work rules and internal policies and regulations in relation to human resources management and any change from current practice or any change above market practice, except any change in compliance with the applicable laws.

(w)          Any approval or modification of the compensation package of the GM, any approval or material modification of the compensation packages of the asset management, and any approval or material modification of the broad parameters of the framework for compensation for the Board and other employees.

(x)           Any approval of budget for annual compensation increase of all employees.

(y)           Any entry into, termination, amendment or otherwise of any arrangement or contract with the GM and the asset management, including as to remuneration or other benefits under such arrangement or contract shall be presented to the Board for acknowledgment, however BPPUS shall have ultimate approval over the entry, amendment and termination of any contract with the GM.

(z)           Any adoption for all employees of any equity compensation plan, any bonus or profit-sharing scheme, incentive scheme, or any stocks, warrants or other convertible securities by the Venture, and any modification thereof.

(aa)         Approval of the GM’s work plan and the key performance indicators (KPIs) for the GM and the management, and appraisal of the GM and the management against the KPIs.

(bb)        The making of any loan or advance to facilitate any hiring of or to incentivize or provide assistance to any employee.

(cc)         Establishing or amending any sub-committee of the Board, including the audit committee and the compensation committee.

(dd)        Any appointment or removal of the auditors.

(ee)         Any adoption or material change to the accounting principles and/or the financial reporting standards.

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(ff)          Any change of the Fiscal Year.

(gg)        Making any tax distribution, or any determination with respect to tax withholding matters or any tax filing, except for as required in accordance with applicable laws, exceeds $2,000,000 individually or $10,000,000 in aggregate per Fiscal Year.

(hh)        Debt write-off in accordance with accounting standards (e.g. bad debt from counter parties due to bankruptcy in normal course of business).

(ii)           Provision of impairment of assets (project in progress, fixed asset, other assets).

(jj)           Provision of impairment of doubtful account.

(kk)         The decision that additional funding from the Venturers shall be required, including the determination of the forms of funding required unless required for an Emergency.

(ll)           The making of any loan or advance by the Venture or to any subsidiary of the Venture which exceeds value of $1,000,000 total outstanding during any Fiscal Year; or not in the ordinary course of business; or to be secured by any collateral of the Venture, any subsidiary of the Venture.

(mm)       Any change or the creation or issue or the repurchase of any Units or of any other security of the Venture, or the grant of any option or rights to subscribe for or to convert any instrument into such securities.

(nn)        Any declaration or payment of any dividend or distribution to the Venturers in any Fiscal Year.

(oo)        Any amendment to or deviation from the dividend policy of the Venture or any subsidiary of the Venture.

(pp)        Resolving any disputes, controversies or proceedings in relation to any tax matters with the IRS or entering into any binding agreement or settlement with the IRS on any material item in dispute with respect to any of the Venture’s or any subsidiary of the Venture’s federal income tax return.

(qq)        Entering into by the Venture of any compromise or settlement in connection with any action, litigation, suit, arbitration or other proceedings, or any application by the Venture for an interim injunction or other application or action (including interim defense) in excess of $1,500,000.

(rr)          Approval of policy, plan and target, and product program related to hedging.

(ss)         Approval of any insurance program for the Venture or its subsidiaries.

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Article 9. TRANSFERS OF VENTURE INTERESTS

9.1           Transfers. Subject to the provisions of Section 9.2, each Venturer shall be permitted to transfer or encumber such Venturer’s interest in the Venture without the prior written approval of the other Venturer or the Board; provided, however, that no Venturer shall transfer all or any of its Ownership Percentage in the Venture (A) if such transfer would subject the Venture to the reporting requirements under the U.S. federal securities laws, (B) if such transfer would cause the Venture to lose its status as a partnership for federal income tax purposes or cause the Venture to be classified as a “publicly traded partnership” within the meaning of Code Section 7704, (C) if such transfer would violate, give rise to a default under or cause any payment to become due under, any credit agreement, guaranty, or similar credit document or any other material contract to which the Venture or any Affiliate is bound, or (D) at any time prior to the repayment by the Venture of all loans and other amounts outstanding under the Venturer Loan Agreement and the termination of the Venturer Loan Agreement.

9.2           Public Offering. Notwithstanding any provision of this Article 9, any Venturer may undertake a public offer of such Venturer without the approval of the Board or of the other Venturer, and such offering shall be free of any and all rights of the Board or of any other Venturers including, without limitation, any tag along rights.

Article 10. DEFAULTS; TERMINATION

10.1         Default. The occurrence of any of the events set forth below shall constitute an “Event of Default” on the part of BKV or BPPUS, as applicable.

(a)           violation by or on behalf of BKV or BPPUS, as applicable, of the transfer restrictions set forth in Article 9;

(b)           initiation by BKV or BPPUS, as applicable, of proceedings of any nature under the United States Bankruptcy Code, or any similar state or federal law for the relief of debtors;

(c)           a general assignment by BKV or BPPUS, as applicable, for the benefit of creditors;

(d)           the initiation against BKV or BPPUS, as applicable, of a proceeding under any section or chapter of the federal Bankruptcy Code, or any similar federal or state law for the relief of debtors, which proceeding is not dismissed or discharged within a period of sixty (60) days after the filing thereof;

(e)           admission by BKV or BPPUS, as applicable, in writing of its inability to pay its debts as they mature or to perform its obligations under this Agreement;

(f)            attachment or execution or other judicial seizure of all or any substantial part of BKV’s or BPPUS’s, as applicable, interest in the Venture, or any part thereof, which remains undismissed or undischarged for a period of sixty (60) days after levy thereof.

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10.2           Remedies.

(a)           Upon the occurrence and during the continuance of any Event of Default, the non-defaulting Venturer shall be entitled to (i) sell the assets of the Venture and dissolve the Venture on reasonable terms deemed acceptable to the Board (ii) obtain specific performance of the non-defaulting Venturer’s obligations under this Agreement and/or (iii) exercise any other right or remedy provided in law or in equity.

10.3         Dissolution. The Venture shall be dissolved upon the occurrence of any of the following events:

(a)           election by the Board to dissolve the Venture following the occurrence of an Event of Default; or

(b)           unanimous written consent by the Venturers to dissolve the Venture.

Dissolution of the Venture shall be effective on the day on which the event occurs giving rise to the dissolution, but the Venture shall not terminate until the assets of the Venture have been distributed as provided herein and a certificate of cancellation of the Venture has been filed with the Secretary of State of Delaware.

10.4         Application of Assets. In the event of dissolution, the Venture shall conduct only such activities as are necessary to wind up its affairs, including a sale of the assets of the Venture in an orderly manner, and the assets of the Venture shall be applied in the manner and in the priority set forth in Section 6.2.

Article 11. MISCELLANEOUS

11.1         Notices. Any and all notices, consents, approvals and other communications required or permitted under this Agreement shall be deemed adequately given only if in writing. Any and all notices, demands, consents, approvals, offers, elections and other communications required or permitted under this Agreement (collectively, “Notices”) shall be deemed to have been properly given (i) upon delivery, if delivered in hand, (ii) one (1) Business Day after having been deposited for overnight delivery with any reputable overnight courier service with all freight charges prepaid, (iii) three (3) Business Days after having been deposited in any post office or mail depository regularly maintained by the U.S. Postal Service and sent by registered or certified mail, postage prepaid, return receipt requested or (iv) the date sent by electronic mail (with confirmation of transmission) if sent during normal business hours of the recipient, and on the next Business Day if sent after normal business hours of the recipient; provided, however, any notice of breach or default hereunder, or offer or acceptance with respect to the purchase or sale of the Property, may not be given by electronic mail and a copy of any notice delivered by electronic mail must simultaneously be sent by one of the delivery methods set forth in clauses (i), (ii) or (iii) above. Whenever under this Agreement a Notice is either received on a day which is not a Business Day or is required to be delivered on or before a specific day which is not a Business Day, the day of receipt or required delivery shall automatically be extended to the next Business Day. All such notices and other communications shall be addressed to the Venturers at their respective addresses set forth below or at such other addresses as any of them may from time to time designate by notice to the other Venturers.

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Notices to BPPUS shall be addressed to:

Banpu Power US Corporation

1200 17^th Street, Suite 2100

Denver, CO 80202

Attention: Mr. Pual Didsayabutra
Email: [***]

With copies via email to:

Attention: Mr, Dechaphong Yuwaprecha and Mr. Issara Niropas
Email: [***], [***]

Notices to BKV shall be addressed to:

BKV Corporation

1200 17th Street, Suite 2100

Denver, CO 80202

Attention: Mr. Chris Kalnin
Email: [***]

With copies to:

BKV Corporation

1200 17th Street, Suite 2100

Denver, CO 80202

Attention: Ms. Lindsay Larrick
Email: [***]

11.2         Successors and Assigns. The agreements contained herein shall be binding upon and inure to the benefit of the permitted successors and assigns of the respective parties hereto.

11.3         Applicable Law. This Agreement shall be construed and enforced in accordance with the laws of the State of Delaware. In the event of any conflict between any provision of this Agreement and any non-mandatory provision of the Act, the provision of this Agreement shall control.

11.4         Severability. If for any reason any provision of this Agreement is determined to be invalid, or unenforceable in any circumstance, such invalidity or unenforceability shall not impair the effectiveness of the other provisions in this Agreement or, to the extent permissible, the effectiveness of such provision in other circumstances.

11.5         Entire Agreement. This Agreement, and the schedules and exhibits attached thereto constitute the entire agreement between the parties hereto with respect to the subject matter hereof and supersede all prior understandings, agreements or representations between the parties pertaining to the subject matter hereof, whether oral or written.

11.6         Titles. Titles of provisions of this Agreement are for descriptive purposes only and shall not control or alter the meanings of this Agreement as set forth in the text.

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11.7         Further Assurances. The Venturers shall execute and deliver such further instruments and do such further acts and things as may be required to carry out the intent and purposes of this Agreement.

11.8         Consent to Jurisdiction. The Venturers hereby consent to the personal jurisdiction of the federal and state courts of the State of Delaware and agree that service of process may be (but need not be) made upon them by certified mail, return receipt requested, or by any manner permitted by law. The Venturers agree not to assert in any action brought in any such court that such action is brought in an inconvenient forum, or otherwise make any objection to venue or jurisdiction.

11.9         Amendments. Except as otherwise provided in this Agreement, no amendment or modification of this Agreement shall be effective unless reflected in a document executed and delivered by all of the Venturers.

11.10       Waiver of Jury Trial. Each of the parties hereto waives trial by jury in any litigation, suit or proceeding between them in any court with respect to, in connection with or arising out of this Agreement, or the validity, interpretation or enforcement thereof, or dealings with each other as Venturers of the Venture.

11.11       Prevailing Party. In any action or proceeding arising in connection with this Agreement, the costs and reasonable attorneys’ fees of the prevailing party shall be paid by the other party.

11.12       Confidentiality. No party hereto shall issue any press release or otherwise make any public announcement naming the other party or any of its direct or indirect beneficial owners, advisors or other agents, or indicating any of their involvement with the Venture, without the consent of the other party. Each party hereto agrees to maintain the confidentiality of the terms and conditions of this Agreement and to maintain the confidentiality of (i) any information provided by one party to the other, and (ii) all financial information, Budgets, Business Plans, information contained in any books, records, computer discs and similar materials containing Venture information, invoices and other documents received or maintained by the Venture pursuant to this Agreement, other than information that is available from public sources (collectively, the “Confidential Information”). Notwithstanding the foregoing, each party shall be entitled to share such Confidential Information (a) to current and potential lenders and direct and indirect beneficial owners of the Venture, (b) if required by law (it being specifically understood and agreed that anything set forth in a registration statement or any other document filed pursuant to law will be deemed required by law), and (c) to its investors, attorneys and advisors who agree to maintain a similar confidence. Notwithstanding anything else in this Agreement and any other agreements among the parties, any party to this Agreement (and each employee, representative, or other agent of any party to this Agreement) may disclose to any and all persons, without limitation of any kind, the tax treatment and tax structure of the Venture and any other transactions contemplated by this Agreement and any other agreements between the parties and all materials of any kind (including opinions or other tax analyses) that are provided to it relating to such tax treatment and tax structure.

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11.13       Counterparts. This Agreement may be executed in any number of counterparts, including by electronic transmission, with the same effect as if all signing parties had signed the same document. All counterparts shall be construed together and constitute the same instrument.

11.14       Independent Legal Advice. Each of the Venturers acknowledge that it has read and understands this Agreement, has consulted with legal counsel with respect to the terms and conditions hereof, is fully aware of its legal effect, has not acted in reliance upon any representations or promises made by the Company other than those contained in writing herein, and has entered into this Agreement freely based on its own judgment with the advice of legal counsel and other advisers as it has deemed necessary or advisable.

11.15       Equitable Relief. Each Venturer acknowledges and agrees that any breach of this Agreement by such Venturer or the Venture or any transferee or any legal representative thereof may cause irreparable injury to the Venture or the other Venturers for which monetary damages (or other remedy at law) are inadequate in view of (a) the complexities and uncertainties in measuring the actual damages that would be sustained by reason of the failure of a Venturer or the Venture to comply with such provisions and (b) the uniqueness of the Venture, the Venture’s and each other Venturer’s business. Each Venturer and the Venture consents to the issuance of an injunction or other enforcement of other equitable remedies against such Venturer or the Venture at the suit of an aggrieved party without the posting of any bond or other security, to compel specific performance of all the terms of this Agreement, and waives any defenses thereto, including the defenses of: (i) failure of consideration, (ii) breach of any other provision of this Agreement and (iii) availability of relief in damages.

11.16       Creditors. Notwithstanding anything to the contrary, none of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Venture (including any lender under the Venturer Loan Agreement, in its capacity as such) or its subsidiaries or any creditor of any Venturer, and for the avoidance of doubt, no Venturer, Board member or Affiliates Representatives shall be deemed to have any duties of any nature whatsoever to any such creditor by virtue of this Agreement or any interest it may have in ownership interests of the Venture or its subsidiaries.

[Signatures appear on following page.]

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IN WITNESS WHEREOF the parties have executed this Agreement as of the date first set forth above.

BANPU POWER US CORPORATION,
a Delaware corporation
By:	/s/ Kirana Limpaphayom
Name: Kirana Limpaphayom
Title: Director
BKV CORPORATION,
a Delaware corporation
By:	/s/ Christopher P. Kalnin
Name: Christopher P. Kalnin
Title: CEO

Schedule 2.6

Venturers

	Ownership Percentage
BKV Corporation		50	%
1200 17th Street, Suite 2100, Denver, CO 80202
Banpu Power US Corporation		50	%
c/o Corporation Service Company,
251 Little Falls Drive, in the City of Wilmington,
County of New Castle, Delaware 19808

Schedule 2.6 

Schedule 2.7

1.             Organization and Ownership. BKV is a corporation validly existing and in good standing under the laws of the State of Delaware, with full power and authority and legal right to enter into and perform its obligations under this Agreement and to carry on its business in the manner and in the locations in which such business has been and is now being conducted by it. BPPUS is a corporation validly existing and in good standing under the laws of the State of Delaware, with full power and authority and legal right to enter into and perform its obligation under this Agreement and to carry on its business in the manner and in the locations in which such business has been and is now being conducted by BPPUS.

2.             Due Authorization and Execution. No consent, approval or waiver of any other third party is required for the execution and delivery by BKV and BPPUS of this Agreement. This Agreement is the legal, valid and binding obligation of the BKV and BPPUS, is enforceable against BKV and BPPUS in accordance with its terms, does not violate or conflict with and will not constitute a default under any provision of any agreement, organizational document, law or judicial or other governmental order to which the BKV or BPPUS are a party.

Schedule 2.7 

Schedule 4.2

Reporting Requirements

1. Fiscal Year and FINANCIAL STATEMENT PREPARAtion basis

1.1 Unless and until the Board shall otherwise determine in accordance with this Agreement, the following particulars shall remain unchanged:

1.1.1 the Venture’s Fiscal Year shall end on 31 December in each year; and

1.1.2 the Venture’s shall prepare and make available the International Financial Reporting Standard (“IFRS”) consolidated balance sheets and profit and loss accounts on a consistent basis for the purpose of consolidation of the Venture and its subsidiaries at the Banpu Power group level and audited by appointed external auditor.

1.1.3 the Venture’s shall prepare and make available the U.S. GAAP standards (“GAAP”) consolidated balance sheets and profit and loss accounts on a consistent basis for the purpose of consolidation of the Venture and its subsidiaries at the BKV group level and audited by appointed external auditor.

2. Finance for the Venture

The Venturers agree that the finance for the Business of the Venture and its subsidiaries (including the funding of approved Business Plan and Approved Budgets) shall be provided by equity contributions from the Venturers, Venturers’ loans and/or loans and other credit facilities from licensed banks, financial institutions and other parties on such terms as the Board may agree in accordance with this Agreement.

3. Dividend Policy

Subject to any applicable laws and regulations, the Venturers hereby agree that the Venture shall declare and pay dividend amounting to at least 50% from its Net Income of the Venture for the six months ended June (“interim dividend”) and for the year ended December. The payment of interim dividend shall be made within September, while the payment of the annual dividend shall be made within May of the following year following the date the dividend is declared.

No dividend shall be payable except out of profits and shall not carry interest as against the Venture.

All dividends shall be dispatched simultaneously to the Venturers entitled to the dividend. Any dividend payable may be paid by check sent through the mail or electronic funds transfer to an account with a bank nominated by the Venturer.

Except as otherwise provided by statute, all dividends unclaimed for one year after having been declared may be invested or otherwise made use of for the benefits of the Venture until claimed.

Schedule 4.2 

4. the International Financial Reporting Standard (“IFRS”) REPORTING SCHEDULE

4.1 For so long as this Agreement is in effect, the Venture shall, and the Venturers shall exercise their rights as members in relation to the Venture (including but not limited to directing their respective nominees, if any, on the Board) so as to ensure that the Venture will, deliver to each of the Venturers:

4.1.1 on or before 15 September in each Fiscal Year, a detailed first draft of the Approved Budget and Business Plan for the Venture and its subsidiaries (including the Financial Projection and estimated major items of revenue and capital expenditure) for the following Fiscal Year, broken down on a monthly basis, and an accompanying cash-flow forecast together with a balance sheet showing the projected position of the Venture and its subsidiaries as at the end of the following Fiscal Year;

4.1.2 on or before 15 October in each Fiscal Year, a detailed final draft of the Approved Budget and Business Plan for the Venture and its subsidiaries (including the Financial Projection and estimated major items of revenue and capital expenditure) for the following Fiscal Year, broken down on a monthly basis, and an accompanying cash-flow forecast together with a balance sheet showing the projected position of the Venture and its subsidiaries as at the end of the following Fiscal Year;

4.1.3 following twelve (12) months after execution of this Agreement, within 10 days after the end of each calendar month in a Fiscal Year, unaudited management accounts in accordance with IFRS. Such accounts shall include a detailed profit and loss account, balance sheet, cash flow analysis, an analysis of profit and loss account against the corresponding budget, a trend analysis, financial outlook for the remaining months of the year, and an analysis of accounts receivable aging;

4.1.4 within twenty (25) days after the end of each of the fiscal quarters in a Fiscal Year (or when furnished to the Board, if earlier), the final version (after external auditor review with adjustment transaction) of consolidated balance sheet of the Venture and its subsidiaries as at the end of each such period and the related consolidated statements of income and cash flows of the Venture and its subsidiaries for such quarterly period and for the elapsed period in such Fiscal Year, all in reasonable detail and stating in comparative form the figures as at the end of and for the comparable periods of the preceding Fiscal Year. All such financial statements shall be in accordance with the agreed upon audit plan for the Venture.

4.1.5 statutory or audit report (signed by external audit) as available, within 90 days after the end of each Fiscal Year (or when furnished to the Board, if earlier) a copy of the consolidated balance sheet of the Venture and its subsidiaries as at the end of each Fiscal Year and the related consolidated statements of income, members’ equity and cash flows of the Venture and its subsidiaries for each Fiscal Year, all in reasonable detail and stating in comparative form the figures as at the end of and for the previous Fiscal Year accompanied by an audit opinion.

Schedule 4.2 

Schedule 4.4

Approved Budget for year 2021 and 2022

Schedule 4.4 

EX-10.26

Exhibit 10.26

BKV CORPORATION 

NON-EMPLOYEE DIRECTOR COMPENSATION PROGRAM

Non-employee members of the board of directors (the “Board”) of BKV Corporation (the “Company”) shall receive compensation as set forth in this Director Compensation Program (this “Program”). The compensation described in this Program shall be paid or be made, as applicable, automatically and without further action of the Board to each member of the Board who is not an employee of the Company (each, a “Non-Employee Director”). Each Non-Employee Director may waive all or a portion of the compensation described in this Program and such waiver may be subsequently rescinded in writing; provided, however, that following any rescindment, no compensation shall be paid in respect of the period during which such Non-Employee Directors’s compensation was waived. Each member of the Board who is also an employee of the Company shall not receive additional compensation for service as a member of the Board and shall not be eligible to participate in this Program.

This Program shall become effective on September 1, 2022 (the “Effective Date”) and will remain in effect until it is revised or rescinded by further action of the Board. This Program may be amended, modified or terminated by the Board at any time, without advance notice, in its sole discretion.

1.            Cash Compensation.

a.            Board Member Annual Retainers. Each Non-Employee Director will receive an annual retainer of $75,000 (the “Director Retainer”). If a Non-Employee Director is also serving as the Chair of the Board as contemplated by the Company’s Certificate of Incorporation, such Non-Employee Director will receive an additional annual retainer of $62,500 (which, together with the Director Retainer would be an aggregate annual retainer of $137,500) as compensation for the additional responsibilities associated with serving as the Chair of the Board (together with the Director Retainer, the “Board Member Retainers”).

b.            Committee Member Annual Retainers. Each Non-Employee Director who serves in one of the following roles will be paid the additional cash retainer set forth below (together with the Board Member Retainers, the “Retainers”).

Committee Role	Amount
Chair of Audit Committee	$	20,000
Chair of Compensation Committee	$	15,000
Chair of Governance Committee	$	15,000
Member of Audit Committee (other than the Chair)	$	10,000
Member of Compensation Committee (other than the Chair)	$	5,000
Member of Governance Committee Member (other than the Chair)	$	5,000

c.            Payment of Retainers. The Retainers shall be earned on a quarterly basis based on a calendar quarter and shall be paid in cash by the Company in arrears not later than the fifteenth (15^th) day following the end of the calendar quarter. In the event a Non-Employee Director does not serve as a Non-Employee Director, Chair of the Board or such other position set forth in Section 1b, for an entire calendar quarter, the Retainer paid to such Non-Employee Director will be prorated for the portion of the calendar quarter actually served as a Non-Employee Director, Chair of the Board, or such other position set forth in Section 1b.

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2.            Equity Compensation.

a.            General. Non-Employee Directors will be granted awards of Restricted Stock Units (as defined in the Company’s 2022 Equity and Incentive Compensation Plan or any other applicable Company equity incentive plan then-maintained by the Company, in each case, which is approved, adopted and becomes effective after the date this Program becomes effective (the “Equity Plan”)) described below (each, a “Restricted Stock Unit Award”), subject to the approval, adoption and effectiveness of the Equity Plan. The Restricted Stock Unit Awards will be granted under and subject to the terms of the Equity Plan and award agreements in substantially the form approved by the Board. All applicable terms of the Equity Plan apply to this Program as if fully set forth herein, and all Restricted Stock Unit Awards under this Program are subject in all respects to the terms of the Equity Plan and the award agreement pursuant to which it was granted.

b.            Annual Awards. Non-Employee Directors who are re-elected to serve, or will continue to serve, as a Non-Employee Director immediately following any annual meeting of the Company’s stockholders will, subject to the approval, adoption and effectiveness of the Equity Plan, automatically be granted, on the date of the Company’s annual stockholder meeting, that number of Restricted Stock Units calculated by dividing (i)(y) $140,000 for Non-Employee Directors other than the Chair of the Board or (z) $202,500 for each Non-Employee Director who is the Chair of the Board, by (ii) the closing price of a share of the Company’s common stock as of the date of such annual meeting of the Company’s stockholders and rounding down to the nearest whole number (the “Annual RSUs”). The Annual RSUs will vest in accordance with and subject to the terms of the Equity Plan and the award agreement pursuant to which it was granted. If an Equity Plan is not effective as of an annual stockholder meeting occurring after the Effective Date, the dollar value that factors into the Annual RSUs that would have otherwise been granted at such annual meeting shall, instead, be considered part of the Retainers and shall be payable to the Non-Employee Directors together with the Retainers, as set forth in Section 1c.

3.            Expense Reimbursements. The Company will reimburse each Non-Employee Director for all reasonable, documented, out-of-pocket travel and other business expenses incurred by such Non-Employee Director in the performance of his or her duties to the Company in accordance with the Company’s applicable expense reimbursement policies and procedures as in effect from time to time.

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EX-10.27

Exhibit 10.27

Execution Version

PRIVATE AND CONFIDENTIAL

Our Ref:	[        ]
Date:	December 22, 2021

To:	BKV Corporation 1200 17th Street, Suite 2100 Denver, Colorado 80202
Attn:	Christopher Kalnin

Re: Uncommitted Specific Advance Facility

Ladies and Gentlemen:

We, Oversea-Chinese Banking Corporation Limited, Los Angeles Agency (together with our successors and assigns, “we” or the “Bank”) are pleased to make available the uncommitted Specific Advance Facility as set out below (the “Facility”) to BKV Corporation, a Delaware corporation (the “Borrower”) subject to the following terms and conditions of: (i) this Facility Letter and each other Facility Document (as defined herein), (ii) the specific terms and conditions of each Notice of Drawing (as defined herein) or each Letter of Credit Request (as defined herein), as applicable, and (iii) the Bank’s Standard Terms and Conditions Governing Banking Facilities (the “Standard Terms”), attached hereto and made a part hereof as Exhibit B. The Facility will be guaranteed by the subsidiaries of the Borrower as more particularly described herein, including, without limitation BKV Barnett LLC, BKV Operating, LLC, and BKV Chelsea, LLC, each, a Delaware limited liability company (each, a “Guarantor”, and each Guarantor, together with the Borrower, a “Credit Party”). Certain terms used in this Facility Letter that are not defined elsewhere in this Facility Letter are defined in the Standard Terms. In the event of any inconsistency or conflict between the terms of this Facility Letter and the Standard Terms, the terms of this Facility Letter shall govern and control.

The Facility is made available hereunder on an uncommitted, discretionary, recallable on demand basis. The Bank has no obligation to issue, grant, continue, extend, or renew any Advance, letter of credit, or any other Utilization of the Facility. Each request by Borrower for a Utilization shall be reviewed by the Bank on a case by case basis and the decision to grant or continue any such Utilization shall be made by the Bank in its absolute and sole discretion and irrespective of whether or not the Credit Parties are in compliance with any of the terms of this Facility Letter or the other Facility Documents. The Bank also reserves the right to summarily refuse any request for a Utilization without any review as contemplated by the preceding sentence. As a “demand” facility, the Bank may demand repayment (or cash collateralization, as applicable, in form, substance and amount satisfactory to the Bank) of any outstanding Obligations at any time. By their execution and delivery hereof, the Credit Parties acknowledge and understand the foregoing.

1

Our Ref:
BKV Corporation SAF	PRIVATE AND CONFIDENTIAL

1.             FACILITY LIMIT

Notwithstanding the respective Facility limit set out in this Facility Letter, the Bank may, at its sole discretion, in consideration of a request of the Borrower from time to time, increase the Facility limit for a specified period of time subject to such conditions as the Bank may stipulate. Any such increase in the limits, and the entire Facility, may be cancelled immediately upon notice to Borrower by the Bank. The Bank may also, in its sole discretion, impose, decrease or cancel any Facility or sublimit or incorporate additional sublimits.

FACILITY	Limit
Specific Advance Facility (“SAF”)	Up to $55 million

The maximum aggregate principal sum outstanding together with the aggregate stated amount of any letters of credit issued under this Facility at any one time shall not exceed $55,000,000 (FIFTY FIVE MILLION DOLLARS) (the “Maximum Amount”).

The Bank, in its discretion, may agree to issue standby letters of credit (each, an “SBLC”) from time to time for the account of the Borrower. The aggregate stated amount of all outstanding letters of credit issued under the Facility shall not exceed $25,000,000 (TWENTY FIVE MILLION DOLLARS) (the “SBLC Sublimit”) unless otherwise agreed by the Bank in its sole discretion. Each issuance of an SBLC under the Facility shall reduce the aggregate amount available for Advances, other SBLCs, and any other available Utilizations on a dollar for dollar basis.

All Advances and SBLCs shall be in United States Dollars and shall be repaid in United States Dollars. SBLCs shall also be subject to the terms of a Letter of Credit Reimbursement Agreement between the Borrower and the Bank, dated as of the date hereof (as it may be amended, restated, supplement, modified or replaced, the “Letter of Credit Reimbursement Agreement”), a letter of credit application, and any other agreements, documents, or instruments required by the Bank as a condition to the issuance of such SBLC, or as a condition to any amendment, extension, or renewal of any SBLC. All references to “$” or “DOLLARS” hereunder shall refer to United States Dollars.

2.             PURPOSE

The proceeds of Advances and any drawings of SBLCs shall be used to finance Borrower’s working capital requirements in the ordinary course of its business as presently conducted. Notwithstanding anything to the contrary in the Standard Terms, Utilizations shall only consist of Advances and SBLCs.

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Our Ref:
BKV Corporation SAF	PRIVATE AND CONFIDENTIAL

3.             PRICING

Each Advance shall bear interest for each day during each Interest Period with respect thereto at a rate per annum equal to the Applicable Rate determined for such Interest Period, as set forth in Section 5.3(d) and the Standard Terms.

Each SBLC shall be subject to the LC Fee as described in Section 5.3(g) and the Standard Terms, and any other fees, charges and expenses set forth in the Letter of Credit Reimbursement Agreement.

Please refer to the Standard Terms, particularly Sections 2 and 3 thereof. As more particularly provided therein, the Bank reserves the right to change the Applicable Rate and the LC Fee in its sole discretion to any other interest rate plus applicable margin (or, for SBLCs, any other fee) it elects, including a rate or fee based on its Cost of Funds and you shall be required to make future interest and fee payments (and any other Obligations calculated according to the Applicable Rate) in accordance with the new Applicable Rate or new SBLC fee. With respect to any Utilizations where the Applicable Rate is calculated according to the LIBO Rate, the Standard Terms provide for such Applicable Rate to transition to a SOFR based rate under the circumstances described therein. Such provisions shall not, however, limit, waive, or restrict the Bank’s overall discretion to change any Applicable Rate, which discretion the Bank reserves notwithstanding Sections 2 and 3 of the Standard Terms. The Bank may give prior written notice to the Borrower of any change in the Applicable Rate, but the failure of the Bank to give any such prior written notice shall not relieve the Borrower of its obligation to pay the amount due and owing to the Bank on account of any change in such Applicable Rate or otherwise prejudice, waive, or limit the Bank’s rights or remedies in any respect.

4.             FACILITY DOCUMENTS

4.1 The Facility, all Utilizations, and all other Obligations of the Credit Parties arising hereunder will be subject to the terms of the following documents in form and substance satisfactory to the Bank (each such document, a “Facility Document” and collectively, the “Facility Documents”):

(i)	This Facility Letter;
(ii)	Demand Promissory Note;
(iii)	Letter of Credit Reimbursement Agreement;
(iv)	Guaranty in favor of the Bank from the Guarantors;
(v)	Each Notice of Drawing for each Advance or a Notice of Letter of Credit Request, each in the form of Exhibit A-1 or Exhibit A-2, as applicable; and
(vi)	Such other documentation as the Bank may request from time to time.

Above documentation and any other documentation, including any amendments, modifications, or restatements of the same, requested by the Bank from time to time shall be in form and substance satisfactory to the Bank and any Utilizations shall be subject to the terms of such documentation.

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Our Ref:
BKV Corporation SAF	PRIVATE AND CONFIDENTIAL

5.             SAF AVAILABILITY/DRAWDOWN

5.1 Subject to the availability of funds to the Bank, Advances under the SAF will be available for drawdown by the Borrower, and the issuance of SBLCs will be available, from time to time on a revolving basis provided always that at any one time the aggregate outstanding principal amount of the Advances together with the undrawn aggregate stated amount of any SBLCs shall not exceed the Maximum Amount.

5.2 Each Advance shall be repaid in full on the earlier of sixty days after the date of such Advance or the Bank’s written demand. Draws on SBLCs shall be payable in full on the earlier of Bank’s written demand or as required under the Letter of Credit Reimbursement Agreement. Please be further advised that the Facility is subject to an annual renewal by the Bank on June 30 of each year (or if such day is not a Business Day, then on the next Business Day thereafter).  In the event the Facility is not renewed as of such date (the “Renewal Determination Date”), the Bank shall terminate the Facility and demand repayment of all Obligations (and cash collateralization of any outstanding SBLCs in form, substance and amount satisfactory to the Bank) on the next Business Day following the Bank’s decision not to renew the Facility. Failure of Bank to delay its annual renewal decision to any date after the Renewal Determination Date of any year, or to fail to deliver notice of termination and a demand for repayment and/or cash collateralization on the day immediately following any determination not to renew the Facility shall not prejudice or waive any rights or remedies of the Bank to terminate the Facility, demand repayment or cash collateral, or exercise any right or remedy. The Bank may elect not to renew or continue the Facility for any or no reason, in its sole discretion, whether or not an Event of Default has occurred or continues.

5.3 Subject to the Bank’s absolute discretion to otherwise permit:

(a) Each Advance shall be of an amount of not less than $1,000,000 and in integral multiples of $1,000,000.

(b) The stated amount of each SBLC shall be an amount of not less than $1,000,000 and in integral multiples of $1,000,000. The aggregate outstanding undrawn stated amount of all SBLCs shall not exceed the SBLC Sublimit at any time. In the event that the aggregate outstanding undrawn stated amount, at any time, exceeds the SBLC Sublimit, the Bank may require the Borrower to cash collateralize the SBLCs, in form, substance and amount satisfactory to the Bank. If the Borrower does not timely comply with any cash collateral request, the Bank may, in its discretion, cause an Advance to be made under the Facility and the Bank may keep the proceeds of such Advance as cash collateral. Each SBLC issued (including any that are amended, extended, renewed or increased) after the date hereof shall terminate no later than 12 months after the date of issuance; provided, however, that if the letter of credit issued by the Bank in favor of Enterprise Texas Pipeline, LLC in the original stated amount of $20,640,000, is ever (in the sole discretion of the Bank and subject to the terms and conditions of the Facility Documents), deemed issued under this Facility or replaced by an SBLC issued under this Facility, the maximum tenor of such letter of credit or replacement allow for an expiry date of 31 August 2024.

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Our Ref:
BKV Corporation SAF	PRIVATE AND CONFIDENTIAL

(c) Each Interest Period shall be 1 or 2 months, subject to the availability of such Interest Period, as notified to the Bank in the Borrower’s Notice of Drawing relating thereto or any continuation notice sent pursuant to Section 5.3(f) hereof. The Borrower shall select such Interest Periods as which shall enable the Borrower to comply with the Borrower’s obligations under the Facility Documents. If the Borrower fails to select an Interest Period in the Notice of Drawing for an Advance, and the Bank elects to accept such Notice of Drawing in its sole discretion, the Interest Period for such Advance shall be one month.

(d) In order to request an Advance, Borrower shall send a Notice of Drawing, substantially in the form attached hereto as Exhibit A-1 to the Bank not later than 11:00 a.m., Los Angeles time, on the fifth Business Day prior to the intended date of Advance, and the other conditions precedent set forth in Section 8 hereof shall be satisfied as determined by the Bank in its sole discretion. The intended date of an Advance must be a Business Day. Each Notice of Drawing shall be irrevocable and binding on Borrower.

(e) In order to request the issuance, amendment, renewal or extension of an SBLC, Borrower shall send an SBLC Issuance Request, substantially in the form attached hereto as Exhibit A-2 to the Bank not later than 11:00 a.m., Los Angeles time, on the fifth Business Day prior to the intended date of such SBLC issuance, amendment, or extension, and the other conditions precedent set forth in Section 8 hereof shall be satisfied as determined by the Bank in its sole discretion. The intended issuance, amendment or extension date of an SBLC must be a Business Day. Each SBLC Issuance Request shall be irrevocable and binding on Borrower.

(f) The Borrower shall pay all accrued interest on each Advance at the Applicable Rate on the applicable Interest Payment Date for such Advance. The Applicable Rate shall be the LIBO Rate plus a margin of 2.00%, subject to the Bank’s right to change the Applicable Rate pursuant to Section 2(a) of the Standard Terms. “Interest Payment Date” means (i) the last day of each Interest Period, (ii) any other date on which the Bank demands repayment of outstanding, accrued interest, and (iii) the Renewal Determination Date (if the Bank elects not to renew the Facility).

(g) Borrower shall pay a fee with respect to each SBLC equal to 1.50% per annum of the outstanding stated amount of such SBLC (the “LC Fee”). Each LC Fee will be payable (i) at issuance of such SBLC based on the stated amount of the SBLC on the day of issuance for the calendar quarter in which such SBLC is issued, and (ii) thereafter, on the first Business Day of each calendar quarter, in advance, based on the stated amount of the SBLC on the first Business Day of such quarter. If the stated amount of SBLC is increased, the Borrower shall pay a supplemental LC Fee on the date of such increase equal to the pro rata amount of the LC Fee as applied to such increased amount.

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Our Ref:
BKV Corporation SAF	PRIVATE AND CONFIDENTIAL

(h) The Borrower shall not voluntarily repay or prepay any Advance, in whole or in part, on any day other than the last day of the applicable Interest Period for such Advance and upon giving the Bank at least three (3) Business Days’ prior written notice. In the event the Borrower does repay any Advance prior to the applicable Interest Period in a manner not permitted by the preceding sentence, the Borrower shall be liable for any breakage costs and other fees and expenses incurred by the Bank in connection with such repayment, as further provided in the Standard Terms. Any such voluntary prepayment shall be in a minimum amount of $1,000,000, and in integral multiples of $1,000,000 (unless the outstanding Advances and accrued interest are being prepaid in full).

(i) The Borrower may elect to continue any Advance upon the expiration of the then current Interest Period with respect thereto by giving irrevocable notice to, and in form and substance satisfactory to, the Bank, in accordance with the applicable provisions in the definition of the term "Interest Period," of the length of the next Interest Period to be applicable to such Advance; provided that, no Advance may be continued as such at the end of the applicable Interest Period (i) when any Event of Default has occurred and is continuing, (ii) if the Advance has been outstanding for sixty days, or (iii) after the date that is one month prior to the next Renewal Determination Date; and provided, further, that if the Borrower shall fail to give any required notice as described above in this paragraph or if such continuation is not permitted pursuant to the preceding proviso, such Advance shall be converted automatically to an Applicable Rate as selected by Bank in its discretion pursuant to Section 2(a) of the Standard Terms on the last day of such then expiring Interest Period.

6.             FINANCIAL COVENANTS; FINANCIAL REPORTING; OTHER COVENANTS

6.1 Financial Covenants. The Borrower shall comply with the following financial covenants based on the Borrower’s consolidated financial statements at all times.

(a) Tangible Net Worth of not less than $500 million at all times. “Tangible Net Worth” is defined as the sum of the paid-up capital and retained earnings of Borrower less intangible assets.

(b) Leverage Ratio of not more than 2.00 to 1.00. “Leverage Ratio” means, as of any date of determination, the ratio of the consolidated indebtedness of the Borrower, calculated according to GAAP, on such date to the consolidated EBITDA of the Borrower for the most recently completed for consecutive fiscal quarters of the Borrower prior to such date.

(c) Interest Coverage Ratio of not less than 2.00 to 1.00. “Interest Coverage Ratio” means, as of any date of determination, the ratio of the consolidated EBITDA of the Borrower, calculated according to GAAP, for the most recently completed for consecutive fiscal quarters of the Borrower prior to such date, to the consolidated interest expense of the Borrower (including, without limitation, that portion attributable to capital leases in accordance with GAAP and capitalized interest), premium payments, debt discount, fees, charges, and related expenses with respect to all outstanding indebtedness of the Borrower on a consolidated basis including all commissions, discounts, and other fees and charges owed with respect to letters of credit, bank guarantees, and bankers' acceptances, in each case whether or not paid in cash during such period.

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Our Ref:
BKV Corporation SAF	PRIVATE AND CONFIDENTIAL

6.2 Financial and Management Statements; Covenant Compliance.

(a) The Borrower shall deliver to the Bank the audited annual consolidated financial statements of the Borrower, and of Banpu Public Company Limited (the “Parent”), as soon as available but in any event within 120 days after the end of the fiscal year of each such entity all in reasonable detail and prepared in accordance with GAAP for the Borrower and IFRS for the Parent, each audited and accompanied by a report and unqualified opinion of a certified public accounting firm of recognized standing reasonably acceptable to the Bank, which report and opinion shall be prepared in accordance with GAAP or IFRS, as applicable, and shall not be subject to any “going concern” or like qualification or exception or any qualification or exception as to the scope of such audit.

(b) The Borrower shall deliver to the Bank quarterly unaudited consolidated financial statements of the Borrower, and of the Parent, within 60 days after the end of the first three fiscal quarters of the Borrower.

(c) Concurrently with the delivery of the quarterly financial statements referred to in clause “b” above, and with the annual financial statement referred to in clause “a” above, a certification from an authorized, knowledgeable officer of the Borrower stating, in form and substance satisfactory to the Bank, that the Borrower is in compliance with the financial covenants set forth in clauses “a” and “b” of Section 6.1 above as of the end of the period covered by such financial statements, that all of the representations and warranties made by the Credit Parties in the Facility Documents are true and correct in all material respects as of the date of such certificate, and that no Event of Default, or any event or circumstance which, with the giving of notice and/or the lapse of time and/or upon your making any necessary certification and/or determination under this Facility Letter might constitute an Event of Default.

7.             SANCTIONS

The Borrower is advised that there are specific sanctions and regulations imposed by the U.S. and other Government Authorities against certain countries, entities and individuals. Under these measures, the Bank may be unable to process or engage in transactions that involve a breach of such sanctions, and Governmental Authorities may require disclosure of information. The Bank is not liable for rejecting any presentation of documents that may cause a breach of those sanctions, or for any disclosures of any information as a result of actual or apparent breach of such sanctions. This Section applies notwithstanding any inconsistency with the current edition of the International Chamber of Commerce Uniform Customs and Practice for Documentary Credits. The Credit Partis have made certain representations to the Bank and made certain covenants in favor of the Bank with regard to sanctions and prohibited transactions in the Standard Terms.

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BKV Corporation SAF	PRIVATE AND CONFIDENTIAL

8.             CONDITIONS PRECEDENT

8.1 Conditions Precedent to the Availability of the Facility.

Application by the Borrower to utilize the Facility will not be considered unless the Borrower has complied with all the conditions of this Facility Letter and such other provisions as the Bank may determine from time to time, and, including without limitation receipt of the following in form and substance acceptable to the Bank:

(a) Duly executed and delivered Facility Documents from all parties thereto containing such terms and conditions as the Bank may in its absolute discretion require duly executed and duly stamped (where applicable) and in registrable form (if applicable);

(b) The last annual financial statement and quarterly financial statements under Section 6.2;

(c) A certificate of each Credit Party, certified by a duly authorized, knowledgeable officer of the applicable Credit Party (an “Authorized Officer”), dated the date hereof, attaching:

(1) Such Credit Party’s Certificate of Incorporation (or equivalent) certified by the relevant authority of the jurisdiction of organization of the Credit Party;

(2) Such Credit Party’s by-laws, operating agreement, or partnership agreement, as applicable, as in effect on the date hereof;

(3) Resolutions of the governing body of such Credit Party approving each Facility Document to which it is or is to be a party, and of all documents evidencing other necessary corporate, partnership, or limited liability company action;

(4) a certification that the names, titles, and signatures of the officers of the applicable Credit Party, each authorized to sign each Facility Document to which it is or is to be a party and other documents to be delivered hereunder and thereunder are true and correct;

(5) a good standing certificate from the state of each Credit Party’s incorporation or formation, as applicable and from each other jurisdiction where such Credit Party should be in good standing under the laws of such jurisdiction, unless failure to be so qualified could not result in a material adverse effect to the Borrower, any other Credit Party, or the Bank; and

(6) attesting to the accuracy of the conditions set forth in the following clause “d”.

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BKV Corporation SAF	PRIVATE AND CONFIDENTIAL

(d) (i) the representations and warranties of the Credit Parties in any Facility Document to which they are a party, or which are contained in any document furnished at any time under or in connection herewith or therewith, are true and correct in all material respects on the date hereof, except (1) to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct in all material respects as of such earlier date, and (2) in the case of any representation and warranty qualified by materiality, they shall be true and correct in all respects; (ii) both before and after giving effect to the closing of the Facility and any Advance made or SBLC issued hereunder on such date, no Event of Default, or any other event which would, with the giving of notice, passing of time, or occurrence of some other event constitute an Event of Default, has occurred and continues; and (iii) no material adverse change in such Credit Party or any of their respective affiliates financial condition, operating environment, management or any other conditions which, in the opinion of the Bank, materially affect any Credit Party’s ability to perform its respective obligations under the Facility Documents to which it are a party or effect the enforceability of any of the material provisions of the Facility Documents or any right or remedy of the Bank thereunder or under applicable Law (a “Material Adverse Change”).

(e) At least five Business Days prior to the date hereof, Borrower shall deliver a Beneficial Ownership Certification covering the Credit Parties;

(f) Bank shall have received, at least five business days prior to the date hereof, all documentation and other information required by regulatory authorities under applicable “know your customer” and anti-money laundering rules and regulations, including, without limitation, the PATRIOT Act.

(g) Legal opinion by Baker & Hostetler LLP, as outside counsel to the Bank, under the laws of the State of New York and the state of each Credit Party’s incorporation or formation, as applicable.

(h) All other information which the Bank or its counsel reasonably request.

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BKV Corporation SAF	PRIVATE AND CONFIDENTIAL

8.2 Conditions Precedent to Each Utilization. Notwithstanding the Bank’s discretion to refrain from making any Advances or issuing (or amending or extending) any SBLC, or allowing any other Utilizations, the Borrower shall comply with the following conditions precedent before receiving an Advance, the issuance (amendment or extension) of any SBLC, or any other Utilization:

(i) With respect to: (1) a request for an Advance, the Bank shall have received a Notice of Drawing, and (2) a request for an SBLC, the Bank shall have received a Notice of Letter of Credit Request, each in accordance with Section 5.3(c) hereof;

(ii) the representations and warranties of each Credit Party in any Facility Document to which it is a party, or which are contained in any document furnished at any time under or in connection herewith or therewith, are true and correct in all material respects on the date hereof, except (1) to the extent that such representations and warranties specifically refer to an earlier date, in which case they shall be true and correct in all material respects as of such earlier date, and (2) in the case of any representation and warranty qualified by materiality, they shall be true and correct in all respects; (ii) both before and after giving effect to the closing of the Facility and any Advance made or SBLC issued (or amended or extended) hereunder on such date, no Event of Default, or any other event which would, with the giving of notice, passing of time, or occurrence of some other event constitute an Event of Default, has occurred and continues; and (iii) no Material Adverse Change has occurred; and

(iii) Borrower shall provide any other documents required by the Bank from time to time and adhere to and abide by all other conditions precedent as the Bank may in its absolute discretion require.

9.             GUARANTORS. Each Credit Party acknowledges and agrees that BKV Barnett LLC, BKV Operating LLC, and BKV Chelsea LLC are required to be a Guarantor. Each Credit Party represents and warrants as of the date hereof and as of each other date on which any representations and warranties under the Facility Documents are made, that each of the aforementioned subsidiaries is a Guarantor.

10.          ACKNOWLEDGMENT OF UNCOMMITTED, DISCRETIONARY NATURE.

By its execution and delivery of this Facility Letter, each Credit Party acknowledges and agrees that you have reviewed, understand, and accept the terms of this Facility Letter (including the Standard Terms attached hereto as Exhibit B) and the other Facility Documents to which it is a party, and have had the opportunity for legal counsel of your choice to review and advise you on such terms. Each Credit Party is aware that the Facility is provided on an uncommitted, discretionary, demand basis, and that, in consequence of such, the Bank may, as provided in the Standard Terms, change the Applicable Rate, the LC Fee, and any applicable margin in its sole discretion including but without limitation on the occurrence of any Benchmark Replacement for any Utilizations based on the LIBO Rate.

The terms and provisions of this Facility Letter and any of the other Facility Documents shall not create any right in any Person other than the Credit Parties and the Bank and no other Person shall have the right to enforce or benefit from the terms hereof or thereof.

The Credit Parties agree that the terms and provisions of this Facility Letter and the other Facility Documents are confidential and may not be disclosed by the Credit Parties to any other Person (except as required by Applicable Law) other than the Parent, and the Credit Party’s (and Parent’s) accountants, attorneys and other advisors and only in connection with the transactions contemplated by this Facility Letter and on a confidential basis unless specifically approved by the Bank.

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BKV Corporation SAF	PRIVATE AND CONFIDENTIAL

We trust that the above terms and conditions are acceptable to the Credit Parties. The Credit Parties shall signify acceptance by having their respective duly authorized signatories to sign and return to the Bank an original counterpart of this Facility Letter.

If you have any queries, please do not hesitate to contact Edwin Chan at (213) 624-1189 x123 or EdwinChan@ocbc.com who shall be pleased to assist you.

We are pleased to be of service to you and look forward to hearing from you in due course.

Yours faithfully,

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BKV Corporation SAF	PRIVATE AND CONFIDENTIAL

Oversea-Chinese Banking Corporation Limited, Los Angeles Agency

Name: Charles Ong

Title: General Manager and Head USA

We hereby accept the Facility on the terms and conditions mentioned in this Facility Letter including the Bank’s Standard Terms and Conditions Governing Banking Facilities, a copy of which we acknowledge receiving.

BKV CORPORATION

Name: Christopher Kalnin

Title: CEO

BKV BARNETT, LLC

Name: Christopher Kalnin

Title: CEO

BKV OPERATING, LLC

Name: Christopher Kalnin

Title: CEO

BKV CHELSEA, LLC

Name: Christopher Kalnin

Title: CEO

12

EX-10.28

Exhibit 10.28

February 7, 2022

CONFIDENTIAL

BKV Corporation

1200 17th Street, Suite 2100
Denver, CO 80202

Attn: John Jimenez | Chief Financial Officer

Ladies and Gentlemen,

Standard Chartered Bank (the "Bank") is pleased to offer you the Facilities subject to the terms and conditions set out in this facility letter (this "Facility Letter"), the Global Master Credit Terms (Uncommitted) (“GMCT (Uncommitted)”), the Global Master Trade Terms (“GMTT”), the RCS and other relevant documents provided to you and the relevant application forms (the foregoing, collectively, the "Agreement").

The Facility Letter will lapse by close of business on the date falling 30 Banking Days after the date of this Facility Letter (or such other date acceptable to the Bank in its absolute discretion) and will have no further effect unless it is countersigned by you and received by the Bank before that time at:

Alex Wang
Standard Chartered Bank
1095 Avenue of the Americas
New York, New York 10036

Email: alexzy.wang@sc.com

Terms not defined in this Facility Letter are defined in the Agreement.

This Facility Letter may be executed in any number of counterparts and this has the same effect as if the signatures on the counterparts were on a single copy of this Facility Letter. Any reference to “executed” or “signature” relating to this Facility Letter shall be deemed to include any execution or signing of this Facility Letter made or delivered by electronic mail or other electronic means, each of which shall have the same legal effect, validity or enforceability as a manually executed signature.

for and on behalf of

Standard Chartered Bank

Full name

Young Sok Kim

Title

Director

Date

March 16, 2022

Signature – please ensure signature remains within the box

/s/ Young Sok Kim  

© Copyright 2017-2021 Standard Chartered Bank. All rights reserved. Page 1 of 7

Facility Letter (Uncommitted) - United States of America  

We accept your offer to make available to us each Facility described in the Agreement and agree to be bound by the terms of the Agreement.

for and on behalf of	for and on behalf of
BKV Corporation	BKV Corporation
Full name	Full name
Christopher P. Kalnin
Title / Position	Title / Position
CEO
Date	Date
March 11, 2022
Signature – please ensure signature remains within the box	Signature – please ensure signature remains within the box
/s/ Christopher P. Kalnin

for and on behalf of	for and on behalf of
BKV Chafee Corners, LLC	BKV Chafee Corners, LLC
Full name	Full name
Christopher P. Kalnin
Title / Position	Title / Position
CEO
Date	Date
March 11, 2022
Signature – please ensure signature remains within the box	Signature – please ensure signature remains within the box
/s/ Christopher P. Kalnin

for and on behalf of	for and on behalf of
BKV Chelsea, LLC	BKV Chelsea, LLC
Full name	Full name
Christopher P. Kalnin
Title / Position	Title / Position

© Copyright 2017-2021 Standard Chartered Bank. All rights reserved. Page 2 of 7

Facility Letter (Uncommitted) - United States of America  

CEO
Date	Date
March 11, 2022
Signature – please ensure signature remains within the box	Signature – please ensure signature remains within the box
/s/ Christopher P. Kalnin

for and on behalf of	for and on behalf of
BKV Operating, LLC	BKV Operating, LLC
Full name	Full name
Christopher P. Kalnin
Title / Position	Title / Position
CEO
Date	Date
March 11, 2022
Signature – please ensure signature remains within the box	Signature – please ensure signature remains within the box
/s/ Christopher P. Kalnin

for and on behalf of	for and on behalf of
BKV Barnett, LLC	BKV Barnett, LLC
Full name	Full name
Christopher P. Kalnin
Title / Position	Title / Position
CEO
Date	Date
March 11, 2022
Signature – please ensure signature remains within the box	Signature – please ensure signature remains within the box
/s/ Christopher P. Kalnin

© Copyright 2017-2021 Standard Chartered Bank. All rights reserved. Page 3 of 7

Facility Letter (Uncommitted) - United States of America  

1.	Borrower(s)
1.1	The entities listed in column (1) of the table below will be referred to as the "Borrowers" and each a "Borrower".
1.2	Each Borrower will enter or accede to the Agreement in a manner satisfactory to the Bank.

(1)	(2)	(3)
Name of company registration number	Jurisdiction of incorporation	Registered Address
BKV Corporation ("Designated Borrower")	Delaware	251 Little Falls Drive, Wilmington, New Castle County, Delaware, 19808
BKV Chaffee Corners, LLC	Delaware	251 Little Falls Drive, Wilmington, New Castle County, Delaware, 19808
BKV Chelsea, LLC	Delaware	251 Little Falls Drive, Wilmington, New Castle County, Delaware, 19808
BKV Operating, LLC	Delaware	251 Little Falls Drive, Wilmington, New Castle County, Delaware, 19808
BKV Barnett, LLC	Delaware	919 N Market St, STE 725, Wilmington, New Castle County, Delaware, 19801

2.	Facilities
2.1	General Banking Facilities
	(a)	Designated Facility Limits and Designated Sub-Limits In addition to any Designated Facility Limit allocated for a Borrower, the Bank may also offer any Borrower a Facility which has a Designated Sub-Limit. The sum of the utilised portions of all Designated Sub-Limits shall not exceed the relevant Designated Facility Limit. The total amount all Borrowers may draw down under all Facilities shall not exceed the Total Facility Limit.

(1)	(2)	(3)
Type(s) of Facility	Designated Facility Limit(s)	Borrower(s) and Designated Sub-Limit(s), if applicable
1.     Commercial Standby Letters of Credit	USD25,000,000	Designated Borrower
2.     Revolving Term Loans	USD15,000,000	Designated Borrower and Borrowers
Total Facility Limits	USD25,000,000.00

(b)   Designated Combined Facility Limits

The total aggregate amount all Borrowers may draw down for each of the combined Facilities specified in Column (1) below in aggregate shall not exceed the corresponding Designated Combined Facility Limit in Column (2) below.

(1)	(2)
Type(s) of Facility	Designated Combined Facility Limit
Facility 1 and 2	USD 25,000,000.00

3.	Pricing and Conditions
	Any reference to a Borrower under this section is a reference to each Borrower of the relevant Facility specified in Clause 2 (Facilities) of this Facility Letter.

Type(s) of Facility	Terms and Conditions
Commercial Standby Letter of Credit	·	Purpose: To issue commercial standby letter of credit
	·	Only available for Designated Borrower
	·	Tenor: 3 years, any single expiration date of any commercial standby letter of credit not to extend beyond August 31, 2024
	·	USD 2,500 transfer fees
	·	1.5% per annum flat charge per commercial standby letter of credit
	·	Evergreen Not Allowed
	·	Facility limit is revolving

Revolving Term Loans	•	Purpose: For general corporate purposes and/or working capital requirements
	•	Available for all Borrowers
	•	Currency: USD
	•	Interest Rate: The rate of interest shall be the rate to be determined by the Bank and agreed upon by the Borrower at the time of each drawdown for each drawdown amount and/or on the date of changing interest for the relevant loan
	•	Max tenor: 1 year
	•	Interest Period: Subject to the drawdown tenor agreed for the applicable drawdown.
	•	Available interest period selection: 1, 3, 6, 12 months, and applicable interest rate per SCBs calculation after Libor retires
	•	Auto-renewal allowed subject to Bank’s annual review and approval
	•	Payment in full at the end of tenor with 2 business days cooling period before Borrower is able to redraw
	•	Multiple drawdowns allowed, subject to a minimum of $1mn for each drawdown

© Copyright 2017-2021 Standard Chartered Bank. All rights reserved. Page 4 of 7

Facility Letter (Uncommitted) - United States of America  

4. Fees

Fee: As in above Pricing and Conditions

5. Contact Details

5.1 Contact details for the Bank 

Name and Title	Address Telephone No. Fax No. Email
Alex Wang Relationship Manager Global Subsidiaries	Address: Standard Chartered Bank 1095 Avenue of the Americas New York, New York 10036   Tel: 862-317-7620   Email: alexzy.wang@sc.com

5.2 Contact details for the Designated Borrower

Name and Title	Address Telephone No. Fax No. Email
John Jimenez | Chief Financial Officer	Address: 1200 17th Street, Suite 2100 Denver, CO 80202   Telephone No.: 720-375-9680 Cell No.: 336-213-4918   Email: johnjimenez@bkvcorp.com

5.3 Service of Process

The Designated Borrower and each of the Borrowers irrevocably consents to process being served in any action by mailing a copy thereof by registered or certified mail, postage prepaid, return receipt requested, or by an internationally recognized courier service to its address specified in Clause 5.2 above or its registered address, to the attention of John Jimenez, Chief Financial Officer.

The Designated Borrower and each of the Borrowers irrevocably waives, to the fullest extent possible, a claim of error by reason of any such service and agree that said service (i) shall be deemed in every respect effective service of process upon it in any such action and (ii) shall be taken and held to be valid personal service upon and personal delivery to it.

The foregoing provisions shall not limit the Bank’s right to serve process in any other manner permitted by law or limit the Bank’s right to bring any such action or to obtain execution on any judgment rendered in any such action in any other appropriate jurisdiction or in any other matter. 

© Copyright 2017-2021 Standard Chartered Bank. All rights reserved. Page 5 of 7

Facility Letter (Uncommitted) - United States of America  

6. Joint Liability

6.1	Where there is more than one Borrower specified in this Facility Letter (unless otherwise agreed by the Bank and each Borrower), the following shall apply:
	(a)	Each Borrower is jointly and severally liable with the other Borrowers for all sums payable or owing to the Bank under any Facility (whether incurred by that Borrower or not).  Each Borrower further agrees that the Bank is not required to make any reference to the other Borrowers in relation to the utilisation of any Facility by any Borrower.
	(b)	Each Borrower's obligations and liabilities will not be affected by (i) any time or indulgence granted to or composition with any other Borrower or any other person; (ii) any change, variation or termination of any agreement or arrangement with any other Borrower or any other person; (iii)  winding up, dissolution, administration or re-organisation of any Borrower or any change on the status, function, control or ownership of any Borrower; (iv) any release of, or any neglect to obtain, perfect or enforce, any rights or securities against any Borrower or any other person; or (v) any unenforceability or invalidity of any obligations of any Borrower or any other person.

7.	Definitions
7.1	In the Agreement, unless the context otherwise requires:

“Compounding the Rate”	means the compounding daily value of the RFR calculated in arrears for the relevant Interest Period (or the Lookback if one applies).
“Compounding RFR Index Rate”	means the percentage change in the relevant RFR index between the first day and the last day of the Lookback.
“Compounding the Balance”	means the daily value of the RFR on the principal balance and accrued but unpaid interest in respect of the relevant Facility and calculated daily for the relevant Interest Period (or the Lookback if one applies).
"Financial Statements"	means for each Obligor other than the Parent, its audited financial statement for its annual financial year.
"Interest Payment Date"	means such interest payment date as may be specified against the applicable Facility in Clause 3 (Pricing and Conditions) of this Facility Letter.
"Interest Period"	means such interest period as may be specified against the applicable Facility in Clause 3 (Pricing and Conditions) of this Facility Letter.
“Lock-Out”	means the interest rate applicable for each day in the Interest Period falling after the Lock-Out Date shall be fixed at the daily value of the RFR on the Lock-Out Date.
“Lock-Out Date”	means the date falling on the number of RFR Banking Days prior to the Interest Payment Date as stated in Lock-Out in Clause 3 (Pricing and Conditions) in respect of the relevant Facility.
"Lookback"	means, in respect of an Interest Period, the period which commences on and includes “x”  RFR Banking Days prior to the beginning of the relevant Interest Period and which ends on and includes “x”  RFR Banking Days prior to the end date of such Interest Period, where “x” is the number of RFR Banking Days as stated as the Lookback in Clause 3 (Pricing and Conditions).
“Observation Shift”	means the applicable rate used for calculating Interest is calculated and weighted by reference to the Lookback rather than the Interest Period.
"Parent"	means Banpu Public Company Limited
"RFR Banking Day"	means a day (other than a Saturday or Sunday) on which banks are open for general business in the principal financial centre of the country of the RFR currency.
“RFR IRS Term Rate”	means for (i) any relevant currency and (ii) the applicable corresponding tenor, the market quoted interest rate swap or overnight index swap based on the relevant risk-free reference rate determined by the Bank.
“Simple Interest RFR Rate”	means the daily simple interest value of the RFR calculated in arrears for the relevant Interest Period (or the Lookback if one applies).

8. Additional Conditions

8.1      Additional Requirements

            N/A

© Copyright 2017-2021 Standard Chartered Bank. All rights reserved. Page 6 of 7

Facility Letter (Uncommitted) - United States of America  

9. GMCT Country Supplement

9.1      Clauses to be added, deleted or amended in the GMCT  (Uncommitted)

Existing definitions in Clause (Definitions) of GMCT (Uncommitted) shall be amended as follows, and new definitions which appear below shall be added to Clause (Definitions) of GMCT (Uncommitted):

DEFINITIONS

"Banking Day" means a day (other than a Saturday or Sunday) on which banks are open for general business in New York City.

"Default Rate" means 2% per annum higher than the rate of interest applicable to the amount payable which would have been applied to the amount had such amount not become due, or such rate as advised by the Bank to the Borrower from time to time.

"Jurisdiction" means the State of New York.

"Spot Rate" means at any date the Bank's spot rate of exchange for the purchase of the relevant currency in the New York foreign exchange market at around 11:00 am New York time using the Base Currency for the relevant Facility.

The following clauses shall be added to and form part of Clause (Representations and warranties) of the GMCT (Uncommitted):

Margin Regulations.  No Borrower is engaged, whether directly or incidentally or as an important part of its activities, in the business of purchasing or carrying “margin stock” (as such term is defined in Regulation T, U or X of the Board of Governors of the Federal Reserve System), or of extending credit to others for such purpose and less than 25% of each Borrower’s assets constitutes margin stock. No proceeds of any extension of credit will be used for the purpose, whether immediate, incidental or ultimate, of purchasing or carrying any such margin stock.

Investment Company Act.  The Borrowers are not, and are not “controlled by”, an “investment company” as defined in, or subject to regulation under, the Investment Company Act of 1940.

Clause (Provision of other services) of the GMCT (Uncommitted) shall be deleted in its entirety.

Clause (Governing law and jurisdiction) of GMCT (Uncommitted) shall be deleted and replaced with the following:

The Agreement and all non-contractual obligations arising in any way out of or in connection with the Agreement are governed by the laws of the Jurisdiction and each Borrower irrevocably submits to the non-exclusive jurisdiction of any New York State or federal court of the United States of America sitting in New York County and waives to the fullest extent permitted by law any objection or claim that such Borrower has or may have that the venue of that action or proceeding in any such court or that such action or proceeding was brought in an inconvenient court and agrees not to plead or claim this.

The following Clause shall be added to and form part of Clause (Governing law and jurisdiction) of the GMCT (Uncommitted):

Waiver of Trial by Jury

EACH PARTY TO THIS AGREEMENT HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY).  EACH PARTY TO THIS AGREEMENT HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PERSON HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PERSON WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES TO THIS AGREEMENT HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

The following clause shall be added to the GMCT (Uncommitted):

USA PATRIOT Act Notice.  Pursuant to the requirements of the USA PATRIOT Act (Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism Act of 2001, the “Act”), the Bank is required to obtain, verify and record information that identifies each Borrower, which information includes such Borrower’s name and address and other information that will allow the Bank to identify such Borrower in accordance with the Act.

10. GMTT Country Supplement

10.1      Clauses to be added, deleted or amended in the GMTT

None

© Copyright 2017-2021 Standard Chartered Bank. All rights reserved. Page 7 of 7

EX-99.1

Exhibit 99.1

KALNIN VENTURES, LLC

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

BARNETT ASSETS

SEC Parameters

As of

December 31, 2020

Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

KALNIN VENTURES, LLC

TABLE OF CONTENTS

DISCUSSION
PETROLEUM RESERVES DEFINITIONS
	TABLE NO.
PROPERTY RANKING	A
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA	B
SUMMARY OF INITIAL BASIC DATA	C
GRAND SUMMARIES
TOTAL PROVED	1
PROVED PRODUCING	2
PROVED SHUT-IN	3

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS - TBPE FIRM LICENSE No. F-1580

 

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET    SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

October 21, 2022

BKV Corp.
1200 17th Street, Suite 1850
Denver, CO 80202

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared a revised report presenting our results for the estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of Kalnin Ventures, LLC (Kalnin) referred to as the Barnett Assets as of December 31, 2020. This revised report supersedes our prior report dated January 19, 2021 as of December 31, 2020, in order to provide additional required public disclosures for filings made with the SEC. The reserves and income data, as well as the underlying assumptions, in this report are the same as those included in our prior report; however this report was prepared for public disclosure by BKV Corp. (BKV) in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The subject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).

The properties referred to as the Barnett Assets evaluated by Ryder Scott account for a portion of Kalnin’s total net proved reserves as of December 31, 2020. Based on information provided by Kalnin, the third party estimate conducted by Ryder Scott addresses 100 percent of the total proved developed net liquid hydrocarbon reserves and 78 percent of the total proved developed net gas reserves of Kalnin.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2020 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices that were used in this report. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

BKV Corp. – Barnett Assets (SEC)
October 21, 2022
Page 2

SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
Kalnin Ventures, LLC
Barnett Assets
As of December 31, 2020

	Proved
	Developed					Total
	Producing		Non-Producing(1)			Proved
Net Reserves
Oil/Condensate – Mbbl		723		0			723
Plant Products – Mbbl		107,234		0			107,234
Gas – MMcf		1,480,707		0			1,480,707
Income Data ($M)
Future Gross Revenue	$	3,895,477	$	0		$	3,895,477
Deductions		2,927,668		3,214			2,930,882
Future Net Income (FNI)	$	967,809	$	(3,214	)	$	964,595
Discounted FNI @ 10%	$	464,232	$	(2,933	)	$	461,299

(1) Negative values for Future Net Income and Discounted FNI are due to abandonment liability.

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (Mbbl). All gas volumes are expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas volumes are located. All gas reserves volumes are reported on an “as sold” basis. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of Kalnin. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Gas reserves account for approximately 61 percent of the total future gross revenue from proved reserves and liquid hydrocarbon reserves account for the remaining 39 percent of total future gross revenue from the proved reserves reported herein.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Barnett Assets (SEC)
October 21, 2022
Page 3

	Discounted Future Net Income ($M) As of December 31, 2020
Discount Rate Percent	Total Proved
6	$	592,818
9	$	488,931
12	$	413,879
15	$	357,828

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The negative values of future net income and discounted FNI shown in the proved developed non-producing category comprise shut-in wells with only an abandonment liability.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Kalnin’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those 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.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Barnett Assets (SEC)
October 21, 2022
Page 4

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Kalnin’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Kalnin owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Barnett Assets (SEC)
October 21, 2022
Page 5

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves attributable to the producing wells and/or reservoirs included herein were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data available through August or October 2020, depending on the availability of data for a given case and in those cases where such data were considered to be definitive. The data used in these analyses were furnished to Ryder Scott by Kalnin or obtained from public data sources and were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Kalnin has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Kalnin with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, abandonment costs after salvage, product prices based on the SEC regulations, and adjustments or differentials to product prices. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Kalnin. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Barnett Assets (SEC)
October 21, 2022
Page 6

Future Production Rates

For the producing wells included herein, our forecasts of future production rates and decline trends are based on the historical performance data of each well.

The future production rates from wells currently on production may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

We furnished the above mentioned average prices in effect on December 31, 2020. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

Product prices which were actually used for each property reflect adjustments for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Kalnin and accepted as factual data.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$39.57/bbl	$29.07/bbl
	NGLs	Mont Belvieu	$18.70/bbl	$14.39/bbl
	Gas	Henry Hub	$1.985/MMBTU	$1.64/Mcf

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by Kalnin and are based on the operating expense reports of Kalnin and include only those costs directly applicable to the leases or wells. Certain gathering and transportation costs are also included as operating costs. The operating costs furnished by Kalnin were reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Kalnin. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Barnett Assets (SEC)
October 21, 2022
Page 7

The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by Kalnin were accepted without independent verification.

Current costs used by Kalnin were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to Kalnin. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by BKV.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Barnett Assets (SEC)
October 21, 2022
Page 8

For filings made with the SEC under the 1933 securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement on Form S-1 by BKV. Our consent for such use is included as a separate exhibit to the filings made with the SEC by BKV.

We have provided BKV with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by BKV and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
SEG (LPC)/pl

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2020 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG and regulatory issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year, including one course in which he was the primary instructor, covering topics such as reserves evaluation methods and evaluation software, RTA/PTA, ethics, regulatory issues, greenhouse gas management, geothermal energy, and more.

Based on his educational background, professional training and more than 15 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS
Page 2

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS
Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) 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.

(v) 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)
SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)
EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas 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; and

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves 

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing 

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In 

Shut-in Reserves are expected to be recovered from: 

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe 

Behind-pipe Reserves are expected to be recovered from 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 all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas 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.

(i)   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.

(ii)  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.

(iii) 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

EX-99.2

Exhibit 99.2

KALNIN VENTURES, LLC

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

CHAFFEE CORNERS ASSETS

SEC Parameters

As of

December 31, 2020

Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY     PETROLEUM CONSULTANTS

KALNIN VENTURES, LLC

TABLE OF CONTENTS

DISCUSSION 

PETROLEUM RESERVES DEFINITIONS

	TABLE NO.
PROPERTY RANKING	A
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA	B
SUMMARY OF INITIAL BASIC DATA	C
GRAND SUMMARIES
TOTAL PROVED	1
PROVED PRODUCING	2
PROVED UNDEVELOPED	3

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS - TBPE FIRM LICENSE No. F-1580

 

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET    SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

October 21, 2022

BKV Corp. 

1200 17th Street, Suite 1850 

Denver, CO 80202

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared a revised report presenting our results for the estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Kalnin Ventures, LLC (Kalnin) referred to as the Chaffee Corners Assets as of December 31, 2020. This revised report supersedes our prior report dated January 19, 2021 as of December 31, 2020, in order to provide additional required public disclosures for filings made with the SEC. The reserves and income data, as well as the underlying assumptions, in this report are the same as those included in our prior report; however this report was prepared for public disclosure by BKV Corp. (BKV) in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The subject properties are located in the state of Pennsylvania. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).

The properties referred to as the Chaffee Corners Assets evaluated by Ryder Scott account for a portion of Kalnin’s total net proved reserves as of December 31, 2020. Based on information provided by Kalnin, the third party estimate conducted by Ryder Scott addresses 0 percent of the total proved developed net liquid hydrocarbon reserves, 3 percent of the total proved developed net gas reserves, 0 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 10 percent of the total proved undeveloped net gas reserves of Kalnin.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2020 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices that were used in this report. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows. 

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

BKV Corp. - Chaffee Corners Assets (SEC) 

October 21, 2022 

Page 2

SEC PARAMETERS 

Estimated Net Reserves and Income Data 

Certain Leasehold Interests of 

Kalnin Ventures, LLC 

Chaffee Corners Assets 

As of December 31, 2020 

	Proved
	Developed  Producing		Undeveloped		Total  Proved
Net Reserves
Gas – MMcf		61,380		9,044		70,424
Income Data ($M)
Future Gross Revenue	$	56,803	$	8,364	$	65,167
Deductions		27,905		4,989		32,894
Future Net Income (FNI)	$	28,898	$	3,375	$	32,273
Discounted FNI @ 10%	$	18,406	$	144	$	18,550

All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of Kalnin. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes, but in the state of Pennsylvania, these taxes are zero. The deductions incorporate the normal direct costs of operating the wells, the Pennsylvania Impact Fee (presented herein as ad valorem taxes), development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Gas reserves account for 100 percent of the total future gross revenue from the proved reserves reported herein.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows. 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

BKV Corp. - Chaffee Corners Assets (SEC) 

October 21, 2022 

Page 3

	Discounted Future Net Income  As of December 31, 2020 ($M)
Discount Rate  Percent	Total Proved
6	$	22,694
9	$	19,460
12	$	16,935
15	$	14,931

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Kalnin’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those 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.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

BKV Corp. - Chaffee Corners Assets (SEC) 

October 21, 2022 

Page 4

Kalnin’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Kalnin owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above. 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

BKV Corp. - Chaffee Corners Assets (SEC) 

October 21, 2022 

Page 5

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods or analogy. In general, the producing reserves were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data available through October 2020 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Kalnin or obtained from public data sources and were considered sufficient for the purpose thereof. In certain producing cases where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as the sole basis for the reserves estimates was considered to be inappropriate, decline parameters were guided by analogy to other more established wells.

All of the proved undeveloped reserves included herein were estimated by analogy based on analogue data furnished to Ryder Scott by Kalnin or which we have obtained from public data sources that were available through October 2020. The data utilized from the analogues incorporated into our analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Kalnin has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Kalnin with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as gas gathering and handling fees, the Pennsylvania Impact Fee, development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, base maps. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Kalnin. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations. 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

BKV Corp. - Chaffee Corners Assets (SEC) 

October 21, 2022 

Page 6

Future Production Rates

For the producing wells included herein, our forecasts of future production rates and decline trends are based on historical performance data. If no definitive production decline trend has been established, future production rates were based on analogy. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Analogy data were used to estimate the anticipated initial production rates for those locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Kalnin. Locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

We furnished the above mentioned average prices in effect on December 31, 2020. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Kalnin. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Kalnin to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark price adjusted for differentials and referred to herein as the “average realized price.” The average realized price shown in the table below was determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in this report. 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

BKV Corp. - Chaffee Corners Assets (SEC) 

October 21, 2022 

Page 7

Geographic Area	Product	Price  Reference	Average  Benchmark  Price	Average  Proved  Realized  Price
North America
United States	Gas	Henry Hub	$1.985/MMBTU	$0.93/Mcf

The effects of derivative instruments designated as price hedges of gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by Kalnin and are based on the operating expense reports of Kalnin and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were reviewed by us for their reasonableness using information furnished by Kalnin for this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Kalnin and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Kalnin were reviewed by us for their reasonableness using information furnished by Kalnin for this purpose. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by Kalnin were accepted without independent verification.

The proved undeveloped reserves in this report have been incorporated herein in accordance with Kalnin’s plans to develop these reserves as of December 31, 2020. The implementation of Kalnin’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Kalnin’s management. As the result of our inquiries during the course of preparing this report, Kalnin has informed us that the development activities included herein have been subjected to and received the internal approvals required by Kalnin’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Kalnin. Kalnin has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, Kalnin has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2020, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Kalnin were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.  

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

BKV Corp. - Chaffee Corners Assets (SEC) 

October 21, 2022 

Page 8

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to Kalnin. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by BKV.

For filings made with the SEC under the 1933 securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement on Form S-1 by BKV. Our consent for such use is included as a separate exhibit to the filings made with the SEC by BKV.

We have provided BKV with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by BKV and the original signed report letter, the original signed report letter shall control and supersede the digital version. 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

BKV Corp. - Chaffee Corners Assets (SEC) 

October 21, 2022 

Page 9

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
SEG (LPC)/pl

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2020 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG and regulatory issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year, including one course in which he was the primary instructor, covering topics such as reserves evaluation methods and evaluation software, RTA/PTA, ethics, regulatory issues, greenhouse gas management, geothermal energy, and more.

Based on his educational background, professional training and more than 15 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007. 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale. 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS 

Page 2 

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B)  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.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS 

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) 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.

(v) 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. 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by: 

SOCIETY OF PETROLEUM ENGINEERS (SPE) 

WORLD PETROLEUM COUNCIL (WPC) 

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) 

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG) 

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas 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; and

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. 

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES 

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from: 

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from 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 all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas 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.

(i) 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.

(ii) 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.

(iii) 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY      PETROLEUM CONSULTANTS

EX-99.3

Exhibit 99.3

KALNIN VENTURES, LLC 

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

CHELSEA ASSETS 

SEC Parameters 

As of

December 31, 2020 

Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

KALNIN VENTURES, LLC

TABLE OF CONTENTS

DISCUSSION 

PETROLEUM RESERVES DEFINITIONS 

	TABLE NO.
PROPERTY RANKING	A
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA	B
SUMMARY OF INITIAL BASIC DATA	C
GRAND SUMMARIES
TOTAL PROVED	1
PROVED PRODUCING	2
PROVED SHUT-IN	3
PROVED UNDEVELOPED	4
PROBABLE UNDEVELOPED	5

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS - TBPE FIRM LICENSE No. F-1580 

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET    SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

October 21, 2022

BKV Corp.

1200 17th Street, Suite 1850

Denver, CO 80202

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared a revised report presenting our results for the estimate of the proved and probable reserves, future production, and income attributable to certain leasehold interests of Kalnin Ventures, LLC (Kalnin) referred to as the Chelsea Assets as of December 31, 2020. This revised report supersedes our prior report dated January 19, 2021 as of December 31, 2020, in order to provide additional required public disclosures for filings made with the SEC. The reserves and income data, as well as the underlying assumptions, in this report are the same as those included in our prior report; however this report was prepared for public disclosure by BKV Corp. (BKV) in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The subject properties are located in the state of Pennsylvania. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).

The properties referred to as the Chelsea Assets evaluated by Ryder Scott account for a portion of Kalnin’s total net proved and probable reserves as of December 31, 2020. Based on information provided by Kalnin, the third party estimate conducted by Ryder Scott addresses 0 percent of the total proved and 0 percent of the total probable developed net liquid hydrocarbon reserves, 10 percent of the total proved and 0 percent of the total probable developed net gas reserves, 0 percent of the total proved and 0 percent of the total probable undeveloped net liquid hydrocarbon reserves, and 24 percent of the total proved and 14 percent of the total probable undeveloped net gas reserves of Kalnin.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2020 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices that were used in this report. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows. 

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Kalnin Ventures, LLC

Chelsea Assets

As of December 31, 2020

	Proved
	Developed							Total
	Producing		Non-Producing(1)			Undeveloped		Proved
Net Reserves
Gas – MMcf		179,158		0			21,818		200,976
Income Data ($M)
Future Gross Revenue	$	139,084	$	0		$	18,719	$	157,803
Deductions		89,577		579			11,412		101,568
Future Net Income (FNI)	$	49,507	$	(579	)	$	7,307	$	56,235
Discounted FNI @ 10%	$	35,325	$	(528	)	$	2,371	$	37,168

(1) Negative values for Future Net Income and Discounted FNI are due to abandonment liability.

	Total
	Probable
	Undeveloped
Net Reserves
Gas – MMcf		8,809
Income Data ($M)
Future Gross Revenue	$	7,642
Deductions		5,276
Future Net Income (FNI)	$	2,366
Discounted FNI @ 10%	$	301

All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of Kalnin. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes, but in the state of Pennsylvania, these taxes are zero. The deductions incorporate the normal direct costs of operating the wells, the Pennsylvania Impact Fee (presented herein as ad valorem taxes), development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 3 

Gas reserves account for 100 percent of the total future gross revenue from the proved and probable reserves reported herein.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income ($M) As of December 31, 2020
Discount Rate	Total		Total
Percent	Proved		Probable
6	$	43,652	$	735
9	$	38,639	$	383
12	$	34,498	$	173
15	$	31,086	$	47

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved and probable reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The negative values of future net income and discounted FNI shown in the proved developed non-producing category comprise shut-in wells with only an abandonment liability.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved and probable gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Kalnin’s request, this report addresses the proved and probable reserves attributable to the properties evaluated herein.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chelsea Assets (SEC) 

October 21, 2022

Page 4 

Proved oil and gas reserves are “those 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.” The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “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.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and are presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserves categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved and probable reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Kalnin’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved and probable reserves actually recovered and amounts of proved and probable income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which Kalnin owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 5 

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved and probable reserves for the properties included herein were estimated by performance methods or analogy. In general, the producing reserves were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data available through October 2020 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Kalnin or obtained from public data sources and were considered sufficient for the purpose thereof. In certain producing cases where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as the sole basis for the reserves estimates was considered to be inappropriate, decline parameters were guided by analogy to other more established wells.

All of the proved and probable undeveloped reserves included herein were estimated by analogy based on analogue data furnished to Ryder Scott by Kalnin or which we have obtained from public data sources that were available through October 2020. The data utilized from the analogues incorporated into our analysis were considered sufficient for the purpose thereof.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 6

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Kalnin has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved and probable production and income, we have relied upon data furnished by Kalnin with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as gas gathering and handling fees, the Pennsylvania Impact Fee, development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, and base maps. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Kalnin. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved and probable reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved and probable reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For the producing wells included herein, our forecasts of future production rates and decline trends are based on historical performance data. If no definitive production decline trend has been established, future production rates were based on analogy. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Analogy data were used to estimate the anticipated initial production rates for those locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Kalnin. Locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 7

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

We furnished the above mentioned average prices in effect on December 31, 2020. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Kalnin. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Kalnin to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark price adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in this report.

					Average		Average
			Average		Proved		Probable
Geographic		Price	Benchmark		Realized		Realized
Area	Product	Reference	Price		Price		Price
North America
United States	Gas	Henry Hub		$1.985/MMBTU		$0.79/Mcf	$0.87/Mcf

The effects of derivative instruments designated as price hedges of gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by Kalnin and are based on the operating expense reports of Kalnin and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were reviewed by us for their reasonableness using information furnished by Kalnin for this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Kalnin and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Kalnin were reviewed by us for their reasonableness using information furnished by Kalnin for this purpose. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by Kalnin were accepted without independent verification. 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 8

The proved and probable undeveloped reserves in this report have been incorporated herein in accordance with Kalnin’s plans to develop these reserves as of December 31, 2020. The implementation of Kalnin’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Kalnin’s management. As the result of our inquiries during the course of preparing this report, Kalnin has informed us that the development activities included herein have been subjected to and received the internal approvals required by Kalnin’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Kalnin. Kalnin has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, Kalnin has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2020, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Kalnin were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to Kalnin. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 9

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by BKV.

For filings made with the SEC under the 1933 securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement on Form S-1 by BKV. Our consent for such use is included as a separate exhibit to the filings made with the SEC by BKV.

We have provided BKV with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by BKV and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
SEG (LPC)/pl

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2020 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG and regulatory issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year, including one course in which he was the primary instructor, covering topics such as reserves evaluation methods and evaluation software, RTA/PTA, ethics, regulatory issues, greenhouse gas management, geothermal energy, and more.

Based on his educational background, professional training and more than 15 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES DEFINITIONS

Page 2

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves.   Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES DEFINITIONS

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii)  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) 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.

(v) 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.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are 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.

(i)  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.

(ii)  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.  

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES DEFINITIONS

Page 4

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.  

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas 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; and

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from: 

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from 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 all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas 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.

(i) 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.

(ii) 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.

(iii) 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

EX-99.4

Exhibit 99.4

KALNIN VENTURES, LLC

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

BKV ASSETS

SEC Parameters

As of

December 31, 2020

Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

KALNIN VENTURES, LLC

TABLE OF CONTENTS

DISCUSSION 

PETROLEUM RESERVES DEFINITIONS

	TABLE NO.
PROPERTY RANKING	A
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA	B
SUMMARY OF INITIAL BASIC DATA	C
GRAND SUMMARIES
TOTAL PROVED	1
PROVED PRODUCING	2
PROVED SHUT-IN	3
PROVED UNDEVELOPED	4
PROBABLE UNDEVELOPED	5

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS - TBPE FIRM LICENSE No. F-1580 

 

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET    SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

October 21, 2022

BKV Corp. 

1200 17th Street, Suite 1850 

Denver, CO 80202

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared a revised report presenting our results for the estimate of the proved and probable reserves, future production, and income attributable to certain leasehold interests of Kalnin Ventures, LLC (Kalnin) referred to as the BKV Assets as of December 31, 2020. This revised report supersedes our prior report dated January 19, 2021 as of December 31, 2020, in order to provide additional required public disclosures for filings made with the SEC. The reserves and income data, as well as the underlying assumptions, in this report are the same as those included in our prior report; however this report was prepared for public disclosure by BKV Corp. (BKV) in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The subject properties are located in the state of Pennsylvania. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).

The properties referred to as the BKV Assets evaluated by Ryder Scott account for a portion of Kalnin’s total net proved and probable reserves as of December 31, 2020. Based on information provided by Kalnin, the third party estimate conducted by Ryder Scott addresses 0 percent of the total proved and 0 percent of the total probable developed net liquid hydrocarbon reserves, 9 percent of the total proved and 0 percent of the total probable developed net gas reserves, 0 percent of the total proved and 0 percent of the total probable undeveloped net liquid hydrocarbon reserves, and 66 percent of the total proved and 86 percent of the total probable undeveloped net gas reserves of Kalnin.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2020 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices that were used in this report. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows. 

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 2

SEC PARAMETERS 

Estimated Net Reserves and Income Data 

Certain Leasehold Interests of 

Kalnin Ventures, LLC 

BKV Assets 

As of December 31, 2020

	Proved
	Developed							Total Proved
	Producing		Non-Producing(1)			Undeveloped
Net Reserves
Gas – MMcf		171,915		0			61,512		233,427
Income Data ($M)
Future Gross Revenue	$	143,136	$	0		$	52,709	$	195,845
Deductions		89,026		395			32,786		122,207
Future Net Income (FNI)	$	54,110	$	(395	)	$	19,923	$	73,638
Discounted FNI @ 10%	$	38,017	$	(361	)	$	6,284	$	43,940

(1) Negative values for Future Net Income and Discounted FNI are due to abandonment liability.

	Total Probable Undeveloped
Net Reserves
Gas – MMcf		53,076
Income Data ($M)
Future Gross Revenue	$	46,043
Deductions		29,705
Future Net Income (FNI)	$	16,338
Discounted FNI @ 10%	$	1,661

All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of Kalnin. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes, but in the state of Pennsylvania, these taxes are zero. The deductions incorporate the normal direct costs of operating the wells, the Pennsylvania Impact Fee (presented herein as ad valorem taxes), development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 3

Gas reserves account for 100 percent of the total future gross revenue from the proved and probable reserves reported herein.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income ($M) As of December 31, 2020
Discount Rate Percent		Total Proved		Total Probable
6	$	53,221	$	4,529
9	$	45,996	$	2,192
12	$	40,268	$	849
15	$	35,681	$	72

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved and probable reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The negative values of future net income and discounted FNI shown in the proved developed non-producing category comprise shut-in wells with only an abandonment liability.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved and probable gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Kalnin’s request, this report addresses the proved and probable reserves attributable to the properties evaluated herein.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 4

Proved oil and gas reserves are “those 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.” The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “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.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and are presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserves categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved and probable reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Kalnin’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved and probable reserves actually recovered and amounts of proved and probable income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which Kalnin owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 5

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved and probable reserves for the properties included herein were estimated by performance methods or analogy. In general, the producing reserves were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data available through October 2020 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Kalnin or obtained from public data sources and were considered sufficient for the purpose thereof. In certain producing cases where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as the sole basis for the reserves estimates was considered to be inappropriate, decline parameters were guided by analogy to other more established wells.

All of the proved and probable undeveloped reserves included herein were estimated by analogy based on analogue data furnished to Ryder Scott by Kalnin or which we have obtained from public data sources that were available through October 2020. The data utilized from the analogues incorporated into our analysis were considered sufficient for the purpose thereof.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 6

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Kalnin has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved and probable production and income, we have relied upon data furnished by Kalnin with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as gas gathering and handling fees, the Pennsylvania Impact Fee, development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, and base maps. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Kalnin. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved and probable reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved and probable reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For the producing wells included herein, our forecasts of future production rates and decline trends are based on historical performance data. If no definitive production decline trend has been established, future production rates were based on analogy. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Analogy data were used to estimate the anticipated initial production rates for those locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Kalnin. Locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 7

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

We furnished the above mentioned average prices in effect on December 31, 2020. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Kalnin. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Kalnin to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark price adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in this report.

Geographic Area	Product	Price Reference	Average Benchmark Price	Average Proved Realized Price	Average Probable Realized Price
North America
United States	Gas	Henry Hub	$1.985/MMBTU	$0.84/Mcf	$0.87/Mcf

The effects of derivative instruments designated as price hedges of gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by Kalnin and are based on the operating expense reports of Kalnin and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were reviewed by us for their reasonableness using information furnished by Kalnin for this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Kalnin and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Kalnin were reviewed by us for their reasonableness using information furnished by Kalnin for this purpose. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by Kalnin were accepted without independent verification.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 8

The proved and probable undeveloped reserves in this report have been incorporated herein in accordance with Kalnin’s plans to develop these reserves as of December 31, 2020. The implementation of Kalnin’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Kalnin’s management. As the result of our inquiries during the course of preparing this report, Kalnin has informed us that the development activities included herein have been subjected to and received the internal approvals required by Kalnin’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Kalnin. Kalnin has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, Kalnin has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2020, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Kalnin were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to Kalnin. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 9

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by BKV.

For filings made with the SEC under the 1933 securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement on Form S-1 by BKV. Our consent for such use is included as a separate exhibit to the filings made with the SEC by BKV.

We have provided BKV with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by BKV and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
SEG (LPC)/pl

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2020 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG and regulatory issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year, including one course in which he was the primary instructor, covering topics such as reserves evaluation methods and evaluation software, RTA/PTA, ethics, regulatory issues, greenhouse gas management, geothermal energy, and more.

Based on his educational background, professional training and more than 15 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES DEFINITIONS

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES DEFINITIONS 

Page 2

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B)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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES DEFINITIONS 

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)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.

(v)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.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are 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.

(i)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.

(ii)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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES DEFINITIONS 

Page 4

(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by: 

SOCIETY OF PETROLEUM ENGINEERS (SPE) 

WORLD PETROLEUM COUNCIL (WPC) 

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) 

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG) 

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas 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; and

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves 

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES 

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing 

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In 

Shut-in Reserves are expected to be recovered from: 

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;  

(2) wells which were shut-in for market conditions or pipeline connections; or  

(3) wells not capable of production for mechanical reasons.

Behind-Pipe 

Behind-pipe Reserves are expected to be recovered from 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 all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas 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.

(i)  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.

(ii)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.

(iii)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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

EX-99.5

Exhibit 99.5

BKV CORP.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

BARNETT ASSETS

SEC Parameters

As of

December 31, 2021

Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV CORP.

TABLE OF CONTENTS

DISCUSSION

PETROLEUM RESERVES DEFINITIONS

	TABLE NO.
PROPERTY RANKING	A
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA	B
SUMMARY OF INITIAL BASIC DATA	C
GRAND SUMMARIES
TOTAL PROVED	1
PROVED PRODUCING	2
PROVED BEHIND PIPE	3
PROVED UNDEVELOPED	4
PROBABLE UNDEVELOPED	5
POSSIBLE UNDEVELOPED	6

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS - TBPE FIRM LICENSE No. F-1580

 

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET    SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

October 21, 2022

BKV Corp.

1200 17th Street, Suite 1850

Denver, CO 80202

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared a revised report presenting our results for the estimate of the proved, probable and possible reserves, future production, and income attributable to certain leasehold and royalty interests of BKV Corp. (BKV) referred to as the Barnett Assets as of December 31, 2021. This revised report supersedes our prior report dated December 13, 2021 as of December 31, 2021, in order to provide additional required public disclosures for filings made with the SEC. The reserves and income data, as well as the underlying assumptions, in this report are the same as those included in our prior report; however this report was prepared for public disclosure by BKV in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The subject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).

The properties referred to as the Barnett Assets evaluated by Ryder Scott account for a portion of BKV’s total net proved, probable and possible reserves as of December 31, 2021. Based on information provided by BKV, the third party estimate conducted by Ryder Scott addresses 100 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net liquid hydrocarbon reserves, 81 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net gas reserves, 100 percent of the total proved, 100 percent of the total probable and 100 percent of the total possible undeveloped net liquid hydrocarbon reserves, and 49 percent of the total proved, 62 percent of the total probable and 51 percent of the total possible undeveloped net gas reserves of BKV.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2021 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices that were used in this report. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

BKV Corp. – Barnett Assets (SEC)

October 21, 2022

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

BKV Corp.

Barnett Assets

As of December 31, 2021

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Reserves
Oil/Condensate – Mbbl		867		0		58		925
Plant Products – Mbbl		142,961		8,472		13,722		165,155
Gas – MMcf		1,882,781		148,214		468,762		2,499,757
Income Data ($M)
Future Gross Revenue	$	9,266,575	$	668,814	$	1,895,851	$	11,831,240
Deductions		4,423,562		321,608		1,105,838		5,851,008
Future Net Income (FNI)	$	4,843,013	$	347,206	$	790,013	$	5,980,232
Discounted FNI @ 10%	$	2,226,324	$	106,070	$	207,677	$	2,540,071

	Total Probable Undeveloped		Total Possible Undeveloped
Net Reserves
Oil/Condensate – Mbbl		486		1,841
Plant Products – Mbbl		31,227		32,047
Gas – MMcf		321,838		194,841
Income Data ($M)
Future Gross Revenue	$	1,843,920	$	1,426,533
Deductions		962,484		801,286
Future Net Income (FNI)	$	881,436	$	625,247
Discounted FNI @ 10%	$	167,944	$	62,478

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (Mbbl). All gas volumes are expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas volumes are located. All gas reserves volumes are reported on an “as sold” basis. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of BKV. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Barnett Assets (SEC)

October 21, 2022

Page 3

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Gas reserves account for approximately 70 percent and liquid hydrocarbon reserves account for the remaining 30 percent of total future gross revenue from proved reserves. Gas reserves account for approximately 63 percent and liquid hydrocarbon reserves account for the remaining 37 percent of total future gross revenue from probable reserves. Gas reserves account for approximately 45 percent and liquid hydrocarbon reserves account for the remaining 55 percent of total future gross revenue from possible reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income ($M) As of December 31, 2021
Discount Rate Percent		Total Proved		Total Probable		Total Possible
8	$	2,889,213	$	224,027	$	96,193
12	$	2,263,496	$	127,473	$	40,726
15	$	1,943,207	$	85,742	$	21,311
20	$	1,570,202	$	45,515	$	6,652

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved, probable and possible reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved developed non-producing reserves included herein consist of the behind pipe status category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved, probable and possible gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At BKV’s request, this report addresses the proved, probable and possible reserves attributable to the properties evaluated herein.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Barnett Assets (SEC)

October 21, 2022

Page 4

Proved oil and gas reserves are “those 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.” The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “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.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and are presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserves categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable and possible reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

BKV’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which BKV owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Barnett Assets (SEC)

October 21, 2022 

Page 5

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1)  performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved, probable and possible reserves for the properties included herein were estimated by performance methods or analogy. All of the proved reserves attributable to producing wells and/or reservoirs were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data ending between May and September 2021, depending on the availability of data for a given case and in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved developed non-producing as well as all of the proved, probable, and possible undeveloped reserves included herein were estimated by analogy. The data utilized from the analogues were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Barnett Assets (SEC)

October 21, 2022

Page 6

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

BKV has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved, probable and possible production and income, we have relied upon data furnished by BKV with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, and base maps. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by BKV. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved, probable and possible reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved, probable and possible reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For the producing wells included herein, our forecasts of future production rates and decline trends are based on the historical performance data of each well.

The initial performance of analogous wells was used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by BKV. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions, and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Barnett Assets (SEC)

October 21, 2022

Page 7

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

We furnished BKV with the above mentioned average prices in effect on December 31, 2021. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, certain NGL fractionation and transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by BKV. The differentials furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Proved Realized Prices	Average Probable Realized Prices	Average Possible Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$66.56/Bbl	$58.94/Bbl	$58.94/Bbl	$58.94/Bbl
	NGLs	WTI Cushing	$66.56/Bbl	$22.01/Bbl	$22.01/Bbl	$22.01/Bbl
	Gas	Henry Hub	$3.598/MMBTU	$3.46/Mcf	$3.75/Mcf	$3.45/Mcf

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by BKV and are based on the operating expense reports of BKV and include only those costs directly applicable to the leases or wells. Certain gas gathering and transportation costs were included as operating expenses. The operating costs furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Barnett Assets (SEC)

October 21, 2022

Page 8

Development costs were furnished to us by BKV and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by BKV were accepted without independent verification.

The proved developed non-producing and proved, probable, and possible undeveloped reserves in this report have been incorporated herein in accordance with BKV’s plans to develop these reserves as of December 31, 2021. The implementation of BKV’s development plans as presented to us and incorporated herein is subject to the approval process adopted by BKV’s management. As the result of our inquiries during the course of preparing this report, BKV has informed us that the development activities included herein have been subjected to and received the internal approvals required by BKV’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to BKV. BKV has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, BKV has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2021, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by BKV were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Barnett Assets (SEC)
October 21, 2022 

Page 9

We are independent petroleum engineers with respect to BKV. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by BKV.

For filings made with the SEC under the 1933 securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement on Form S-1 by BKV. Our consent for such use is included as a separate exhibit to the filings made with the SEC by BKV.

We have provided BKV with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by BKV and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
SEG (LPC)/pl

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2020 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG and regulatory issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year, including one course in which he was the primary instructor, covering topics such as reserves evaluation methods and evaluation software, RTA/PTA, ethics, regulatory issues, greenhouse gas management, geothermal energy, and more.

Based on his educational background, professional training and more than 15 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

(ii)   In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) 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.

(v)  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.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are 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.

(i)   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.

(ii)  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.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 4

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)   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.

(ii)  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.

(iii) 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.

(iv) 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.

(v)  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 areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by: 

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG) 

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA) 

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas 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; and

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from 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 all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas 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.

(i)  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.

(ii) 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.

(iii) 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

EX-99.6

Exhibit 99.6

BKV CORP.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

CHAFFEE CORNERS ASSETS

SEC Parameters

As of

December 31, 2021

Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV CORP.

TABLE OF CONTENTS

DISCUSSION

PETROLEUM RESERVES DEFINITIONS

	TABLE NO.
PROPERTY RANKING	A
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA	B
SUMMARY OF INITIAL BASIC DATA	C
GRAND SUMMARIES
TOTAL PROVED	1
PROVED PRODUCING	2
PROVED SHUT-IN	3
PROVED UNDEVELOPED	4
PROBABLE UNDEVELOPED	5
POSSIBLE UNDEVELOPED	6

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS - TBPE FIRM LICENSE No. F-1580

 

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET    SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

October 21, 2022

BKV Corp.

1200 17th Street, Suite 1850

Denver, CO 80202

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared a revised report presenting our results for the estimate of the proved, probable and possible reserves, future production, and income attributable to certain leasehold interests of BKV Corp. (BKV) referred to as the Chaffee Corners Assets as of December 31, 2021. This revised report supersedes our prior report dated December 13, 2021 as of December 31, 2021, in order to provide additional required public disclosures for filings made with the SEC. The reserves and income data, as well as the underlying assumptions, in this report are the same as those included in our prior report; however this report was prepared for public disclosure by BKV in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The subject properties are located in the state of Pennsylvania. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).

The properties referred to as the Chaffee Corners Assets evaluated by Ryder Scott account for a portion of BKV’s total net proved, probable and possible reserves as of December 31, 2021. Based on information provided by BKV, the third party estimate conducted by Ryder Scott addresses 0 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net liquid hydrocarbon reserves, 3 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net gas reserves, 0 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible undeveloped net liquid hydrocarbon reserves, and 1 percent of the total proved, 6 percent of the total probable and less than 1 percent of the total possible undeveloped net gas reserves of BKV.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2021 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices that were used in this report. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

BKV Corp. – Chaffee Corners Assets (SEC)

October 21, 2022

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

BKV Corp.

Chaffee Corners Assets

As of December 31, 2021

	Proved
	Developed							Total
	Producing		Non-Producing(1)			Undeveloped		Proved
Net Reserves
Gas – MMcf		64,993		0			6,499		71,492
Income Data ($M)
Future Gross Revenue	$	220,106	$	0		$	22,013	$	242,119
Deductions		69,642		57			9,819		79,518
Future Net Income (FNI)	$	150,464	$	(57	)	$	12,194	$	162,601
Discounted FNI @ 10%	$	75,049	$	(53	)	$	4,069	$	79,065

(1) Negative values for Future Net Income and Discounted FNI are due to abandonment liability.

	Total		Total
	Probable		Possible
	Undeveloped		Undeveloped
Net Reserves
Gas – MMcf		31,944		980
Income Data ($M)
Future Gross Revenue	$	108,184	$	3,319
Deductions		64,391		2,379
Future Net Income (FNI)	$	43,793	$	940
Discounted FNI @ 10%	$	6,227	$	3

All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of BKV. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes, but in the state of Pennsylvania, these taxes are zero. The deductions incorporate the normal direct costs of operating the wells, the Pennsylvania Impact Fee (presented herein as ad valorem taxes), development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chaffee Corners Assets (SEC)

October 21, 2022

Page 3

Gas reserves account for 100 percent of the total future gross revenue from the proved, probable, and possible reserves reported herein.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income ($M)
	As of December 31, 2021
Discount Rate	Total		Total			Total
Percent	Proved		Probable			Possible
8	$	88,256	$	9,482		$	67
12	$	71,663	$	3,861		$	(37	)
15	$	62,948	$	1,429		$	(70	)
20	$	52,574	$	(846	)	$	(86	)

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved, probable and possible reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The negative values of future net income and discounted FNI shown in the proved developed non-producing category comprise shut-in wells with only an abandonment liability.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved, probable and possible gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At BKV’s request, this report addresses the proved, probable and possible reserves attributable to the properties evaluated herein.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chaffee Corners Assets (SEC)

October 21, 2022

Page 4

Proved oil and gas reserves are “those 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.” The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “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.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and are presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserves categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable and possible reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

BKV’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which BKV owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chaffee Corners Assets (SEC)

October 21, 2022

Page 5

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved, probable and possible reserves for the properties included herein were estimated by performance methods or analogy. All of the proved reserves attributable to producing wells and/or reservoirs were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data ending between June and September 2021, depending on the availability of data for a given case and in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved, probable, and possible undeveloped reserves included herein were estimated by analogy. The data utilized from the analogues were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chaffee Corners Assets (SEC)

October 21, 2022

Page 6

BKV has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved, probable and possible production and income, we have relied upon data furnished by BKV with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, the Pennsylvania Impact Fee, development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, and base maps. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by BKV. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved, probable and possible reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved, probable and possible reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For the producing wells included herein, our forecasts of future production rates and decline trends are based on the historical performance data of each well.

The initial performance of analogous wells was used to estimate the anticipated initial production rates for those locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by BKV. Locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions, and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chaffee Corners Assets (SEC)

October 21, 2022

Page 7

We furnished BKV with the above mentioned average prices in effect on December 31, 2021. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by BKV. The differentials furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose.

In addition, the table below summarizes the net volume weighted benchmark price adjusted for differentials and referred to herein as the “average realized prices.” The average realized price shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

					Average		Average	Average
			Average		Proved		Probable	Possible
Geographic		Price	Benchmark		Realized		Realized	Realized
Area	Product	Reference	Price		Price		Price	Price
North America	Gas	Henry Hub		$3.598/MMBTU		$3.39/Mcf	$3.39/Mcf	$3.39/Mcf

The effects of derivative instruments designated as price hedges of gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by BKV and are based on the operating expense reports of BKV and include only those costs directly applicable to the leases or wells. The operating costs furnished by BKV were reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by BKV to determine these costs. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by BKV and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by BKV were reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by BKV to determine these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by BKV were accepted without independent verification.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chaffee Corners Assets (SEC)

October 21, 2022

Page 8

The proved, probable, and possible undeveloped reserves in this report have been incorporated herein in accordance with BKV’s plans to develop these reserves as of December 31, 2021. The implementation of BKV’s development plans as presented to us and incorporated herein is subject to the approval process adopted by BKV’s management. As the result of our inquiries during the course of preparing this report, BKV has informed us that the development activities included herein have been subjected to and received the internal approvals required by BKV’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to BKV. BKV has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, BKV has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2021, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by BKV were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to BKV. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

BKV Corp. – Chaffee Corners Assets (SEC)

October 21, 2022

Page 9

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by BKV.

For filings made with the SEC under the 1933 securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement on Form S-1 by BKV. Our consent for such use is included as a separate exhibit to the filings made with the SEC by BKV.

We have provided BKV with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by BKV and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
SEG (LPC)/pl

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2020 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG and regulatory issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year, including one course in which he was the primary instructor, covering topics such as reserves evaluation methods and evaluation software, RTA/PTA, ethics, regulatory issues, greenhouse gas management, geothermal energy, and more.

Based on his educational background, professional training and more than 15 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES DEFINITIONS

Page 2

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES DEFINITIONS

Page 3

(ii)  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) 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.

(v) 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.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are 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.

(i)  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.

(ii) 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.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.  

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES DEFINITIONS

Page 4

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)  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.

(ii) 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.

(iii) 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.

(iv) 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.

(v)  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 areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas 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; and

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from 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 all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas 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.

(i) 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.

(ii) 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.

(iii) 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS 

EX-99.7

Exhibit 99.7

BKV CORP.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

CHELSEA ASSETS

SEC Parameters

As of

December 31, 2021

Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV CORP.

TABLE OF CONTENTS

DISCUSSION

PETROLEUM RESERVES DEFINITIONS

	TABLE NO.
PROPERTY RANKING	A
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA	B
SUMMARY OF INITIAL BASIC DATA	C
GRAND SUMMARIES
TOTAL PROVED	1
PROVED PRODUCING	2
PROVED SHUT-IN	3
PROVED UNDEVELOPED	4
PROBABLE UNDEVELOPED	5
POSSIBLE UNDEVELOPED	6

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS - TBPE FIRM LICENSE No. F-1580

 

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET    SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

October 21, 2022

BKV Corp.

1200 17th Street, Suite 1850

Denver, CO 80202

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared a revised report presenting our results for the estimate of the proved, probable and possible reserves, future production, and income attributable to certain leasehold interests of BKV Corp. (BKV) referred to as the Chelsea Assets as of December 31, 2021. This revised report supersedes our prior report dated December 13, 2021 as of December 31, 2021, in order to provide additional required public disclosures for filings made with the SEC. The reserves and income data, as well as the underlying assumptions, in this report are the same as those included in our prior report; however this report was prepared for public disclosure by BKV in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The subject properties are located in the state of Pennsylvania. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).

The properties referred to as the Chelsea Assets evaluated by Ryder Scott account for a portion of BKV’s total net proved, probable and possible reserves as of December 31, 2021. Based on information provided by BKV, the third party estimate conducted by Ryder Scott addresses 0 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net liquid hydrocarbon reserves, 8 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net gas reserves, 0 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible undeveloped net liquid hydrocarbon reserves, and 18 percent of the total proved, 16 percent of the total probable and 29 percent of the total possible undeveloped net gas reserves of BKV.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2021 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices that were used in this report. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows. 

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

BKV Corp.

Chelsea Assets

As of December 31, 2021

	Proved
	Developed							Total
	Producing		Non-Producing(1)			Undeveloped		Proved
Net Reserves
Gas – MMcf		198,498		0			174,139		372,637
Income Data ($M)
Future Gross Revenue	$	548,433	$	0		$	484,880	$	1,033,313
Deductions		326,523		352			288,102		614,977
Future Net Income (FNI)	$	221,910	$	(352	)	$	196,778	$	418,336
Discounted FNI @ 10%	$	130,841	$	(322	)	$	65,149	$	195,668

(1) Negative values for Future Net Income and Discounted FNI are due to abandonment liability.

	Total		Total
	Probable		Possible
	Undeveloped		Undeveloped
Net Reserves
Gas – MMcf		84,140		111,682
Income Data ($M)
Future Gross Revenue	$	233,015	$	306,859
Deductions		164,371		232,123
Future Net Income (FNI)	$	68,644	$	74,736
Discounted FNI @ 10%	$	12,921	$	7,419

All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of BKV. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 3

The future gross revenue is after the deduction of production taxes, but in the state of Pennsylvania, these taxes are zero. The deductions incorporate the normal direct costs of operating the wells, the Pennsylvania Impact Fee (presented herein as ad valorem taxes), development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Gas reserves account for 100 percent of the total future gross revenue from the proved, probable, and possible reserves reported herein.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

		Discounted Future Net Income ($M)
		As of December 31, 2021
Discount Rate		Total		Total		Total
Percent		Proved		Probable		Possible
	8	$	221,047	$	17,962	$	12,247
	12	$	175,026	$	9,203	$	4,216
	15	$	150,522	$	5,314	$	1,317
	20	$	121,204	$	1,565	$	(808	)

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved, probable and possible reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The negative values of future net income and discounted FNI shown in the proved developed non-producing category comprise shut-in wells with only an abandonment liability.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved, probable and possible gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At BKV’s request, this report addresses the proved, probable and possible reserves attributable to the properties evaluated herein.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 4

Proved oil and gas reserves are “those 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.” The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “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.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and are presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserves categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable and possible reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

BKV’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which BKV owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 5

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved, probable and possible reserves for the properties included herein were estimated by performance methods or analogy. All of the proved reserves attributable to producing wells and/or reservoirs were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data ending between June and September 2021, depending on the availability of data for a given case and in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved, probable, and possible undeveloped reserves included herein were estimated by analogy. The data utilized from the analogues were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 6

BKV has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved, probable and possible production and income, we have relied upon data furnished by BKV with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, the Pennsylvania Impact Fee, development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, and base maps. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by BKV. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved, probable and possible reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved, probable and possible reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For the producing wells included herein, our forecasts of future production rates and decline trends are based on the historical performance data of each well.

The initial performance of analogous wells was used to estimate the anticipated initial production rates for those locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by BKV. Locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions, and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 7

We furnished BKV with the above mentioned average prices in effect on December 31, 2021. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by BKV. The differentials furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose.

In addition, the table below summarizes the net volume weighted benchmark price adjusted for differentials and referred to herein as the “average realized prices.” The average realized price shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Price	Average Proved Realized Price	Average Probable Realized Price	Average Possible Realized Price
North America	Gas	Henry Hub	$3.598/MMBTU	$2.77/Mcf	$2.77/Mcf	$2.75/Mcf

The effects of derivative instruments designated as price hedges of gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by BKV and are based on the operating expense reports of BKV and include only those costs directly applicable to the leases or wells. The operating costs furnished by BKV were reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by BKV to determine these costs. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by BKV and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by BKV were reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by BKV to determine these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by BKV were accepted without independent verification.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022 

Page 8

The proved, probable, and possible undeveloped reserves in this report have been incorporated herein in accordance with BKV’s plans to develop these reserves as of December 31, 2021. The implementation of BKV’s development plans as presented to us and incorporated herein is subject to the approval process adopted by BKV’s management. As the result of our inquiries during the course of preparing this report, BKV has informed us that the development activities included herein have been subjected to and received the internal approvals required by BKV’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to BKV. BKV has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, BKV has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2021, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by BKV were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to BKV. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)

October 21, 2022

Page 9

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by BKV.

For filings made with the SEC under the 1933 securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement on Form S-1 by BKV. Our consent for such use is included as a separate exhibit to the filings made with the SEC by BKV.

We have provided BKV with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by BKV and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
SEG (LPC)/pl

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2020 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG and regulatory issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year, including one course in which he was the primary instructor, covering topics such as reserves evaluation methods and evaluation software, RTA/PTA, ethics, regulatory issues, greenhouse gas management, geothermal energy, and more.

Based on his educational background, professional training and more than 15 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

(ii)  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) 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.

(v) 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.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are 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.

(i)  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.

(ii) 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.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 4

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)  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.

(ii) 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.

(iii) 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.

(iv) 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.

(v)  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 areas are in communication with the proved reservoir.

(vi)  Pursuant to paragraph (a)(22)(iii) of this section, 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by: 

SOCIETY OF PETROLEUM ENGINEERS (SPE) 

WORLD PETROLEUM COUNCIL (WPC) 

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) 

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG) 

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas 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; and

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES 

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from: 

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from 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 all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas 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.

(i) 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.

(ii) 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.

(iii) 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

EX-99.8

Exhibit 99.8 

BKV CORP.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

BKV ASSETS

SEC Parameters

As of

December 31, 2021

Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President RYDER SCOTT COMPANY, L.P. TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV CORP.

TABLE OF CONTENTS

DISCUSSION 

PETROLEUM RESERVES DEFINITIONS

	TABLE NO.
PROPERTY RANKING	A
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA	B
SUMMARY OF INITIAL BASIC DATA	C
GRAND SUMMARIES
TOTAL PROVED	1
PROVED PRODUCING	2
PROVED SHUT-IN	3
PROVED UNDEVELOPED	4
PROBABLE UNDEVELOPED	5
POSSIBLE UNDEVELOPED	6

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS - TBPE FIRM LICENSE No. F-1580 

 

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET    SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

October 21, 2022

BKV Corp. 

1200 17th Street, Suite 1850 

Denver, CO 80202

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared a revised report presenting our results for the estimate of the proved, probable and possible reserves, future production, and income attributable to certain leasehold interests of BKV Corp. (BKV) referred to as the BKV Assets as of December 31, 2021. This revised report supersedes our prior report dated December 13, 2021 as of December 31, 2021, in order to provide additional required public disclosures for filings made with the SEC. The reserves and income data, as well as the underlying assumptions, in this report are the same as those included in our prior report; however this report was prepared for public disclosure by BKV in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The subject properties are located in the state of Pennsylvania. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations).

The properties referred to as the BKV Assets evaluated by Ryder Scott account for a portion of BKV’s total net proved, probable and possible reserves as of December 31, 2021. Based on information provided by BKV, the third party estimate conducted by Ryder Scott addresses 0 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net liquid hydrocarbon reserves, 8 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net gas reserves, 0 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible undeveloped net liquid hydrocarbon reserves, and 32 percent of the total proved, 16 percent of the total probable and 19 percent of the total possible undeveloped net gas reserves of BKV.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2021 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices that were used in this report. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data 

Certain Leasehold Interests of 

BKV Corp. 

BKV Assets 

As of December 31, 2021

	Proved
	Developed							Total
	Producing		Non-Producing(1)			Undeveloped		Proved
Net Reserves
Gas – MMcf		200,440		0			300,958		501,398
Income Data ($M)
Future Gross Revenue	$	558,998	$	0		$	848,149	$	1,407,147
Deductions		333,748		518			497,081		831,347
Future Net Income (FNI)	$	225,250	$	(518	)	$	351,068	$	575,800
Discounted FNI @ 10%	$	134,529	$	(474	)	$	125,610	$	259,665

(1) Negative values for Future Net Income and Discounted FNI are due to abandonment liability.

	Total		Total
	Probable		Possible
	Undeveloped		Undeveloped
Net Reserves
Gas – MMcf		84,520		74,438
Income Data ($M)
Future Gross Revenue	$	236,108	$	204,528
Deductions		162,300		154,743
Future Net Income (FNI)	$	73,808	$	49,785
Discounted FNI @ 10%	$	14,993	$	4,937

All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of BKV. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes, but in the state of Pennsylvania, these taxes are zero. The deductions incorporate the normal direct costs of operating the wells, the Pennsylvania Impact Fee (presented herein as ad valorem taxes), development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 3

Gas reserves account for 100 percent of the total future gross revenue from the proved, probable, and possible reserves reported herein.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income ($M)
	As of December 31, 2021
Discount Rate	Total		Total		Total
Percent	Proved		Probable		Possible
8	$	295,171	$	20,373	$	8,153
12	$	230,879	$	10,993	$	2,804
15	$	196,806	$	6,760	$	873
20	$	156,160	$	2,586	$	(542	)

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved, probable and possible reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The negative values of future net income and discounted FNI shown in the proved developed non-producing category comprise shut-in wells with only an abandonment liability.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved, probable and possible gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At BKV’s request, this report addresses the proved, probable and possible reserves attributable to the properties evaluated herein.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 4

Proved oil and gas reserves are “those 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.” The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “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.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and are presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserves categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable and possible reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

BKV’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which BKV owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 5

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved, probable and possible reserves for the properties included herein were estimated by performance methods or analogy. All of the proved reserves attributable to producing wells and/or reservoirs were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data ending between June and September 2021, depending on the availability of data for a given case and in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved, probable, and possible undeveloped reserves included herein were estimated by analogy. The data utilized from the analogues were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 6

BKV has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved, probable and possible production and income, we have relied upon data furnished by BKV with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, the Pennsylvania Impact Fee, development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, and base maps. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by BKV. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved, probable and possible reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved, probable and possible reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For the producing wells included herein, our forecasts of future production rates and decline trends are based on the historical performance data of each well.

The initial performance of analogous wells was used to estimate the anticipated initial production rates for those locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by BKV. Locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions, and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 7

We furnished BKV with the above mentioned average prices in effect on December 31, 2021. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by BKV. The differentials furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose.

In addition, the table below summarizes the net volume weighted benchmark price adjusted for differentials and referred to herein as the “average realized prices.” The average realized price shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

					Average		Average	Average
			Average		Proved		Probable	Possible
Geographic		Price	Benchmark		Realized		Realized	Realized
Area	Product	Reference	Price		Price		Price	Price
North America	Gas	Henry Hub		$3.598/MMBTU		$2.81/Mcf	$2.79/Mcf	$2.75/Mcf

The effects of derivative instruments designated as price hedges of gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by BKV and are based on the operating expense reports of BKV and include only those costs directly applicable to the leases or wells. The operating costs furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by BKV and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by BKV were accepted without independent verification.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 8

The proved, probable, and possible undeveloped reserves in this report have been incorporated herein in accordance with BKV’s plans to develop these reserves as of December 31, 2021. The implementation of BKV’s development plans as presented to us and incorporated herein is subject to the approval process adopted by BKV’s management. As the result of our inquiries during the course of preparing this report, BKV has informed us that the development activities included herein have been subjected to and received the internal approvals required by BKV’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to BKV. BKV has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, BKV has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2021, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by BKV were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to BKV. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – BKV Assets (SEC) 

October 21, 2022 

Page 9

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by BKV.

For filings made with the SEC under the 1933 securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement on Form S-1 by BKV. Our consent for such use is included as a separate exhibit to the filings made with the SEC by BKV.

We have provided BKV with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by BKV and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
SEG (LPC)/pl

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2020 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG and regulatory issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year, including one course in which he was the primary instructor, covering topics such as reserves evaluation methods and evaluation software, RTA/PTA, ethics, regulatory issues, greenhouse gas management, geothermal energy, and more.

Based on his educational background, professional training and more than 15 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS 

Page 2

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) 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.  

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS 

Page 3

(ii)  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) 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.

(v) 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.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves.  Probable reserves are 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.

(i)  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.

(ii) 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.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS 

Page 4

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) 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.

(ii) 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.

(iii)  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.

(iv)  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.

(v)  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 areas are in communication with the proved reservoir.

(vi)  Pursuant to paragraph (a)(22)(iii) of this section, 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by: 

SOCIETY OF PETROLEUM ENGINEERS (SPE) 

WORLD PETROLEUM COUNCIL (WPC) 

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) 

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG) 

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas 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; and

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves 

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES 

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing 

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In 

Shut-in Reserves are expected to be recovered from: 

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe 

Behind-pipe Reserves are expected to be recovered from 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 all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas 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.

(i) 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.

(ii)  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.

(iii) 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

EX-99.9

Exhibit 99.9

BKV CORP.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

BARNETT ASSETS

SEC Parameters

As of

September 30, 2022

Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV CORP.

TABLE OF CONTENTS

DISCUSSION

PETROLEUM RESERVES DEFINITIONS

	TABLE NO.
PROPERTY RANKING	A
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA	B
SUMMARY OF INITIAL BASIC DATA	C
GRAND SUMMARIES
TOTAL PROVED	1
PROVED PRODUCING	2
PROVED SHUT-IN	3
PROVED BEHIND PIPE	4
PROVED UNDEVELOPED	5
TOTAL PROBABLE	6
PROBABLE BEHIND PIPE	7
PROBABLE UNDEVELOPED	8
TOTAL POSSIBLE	9
POSSIBLE BEHIND PIPE	10
POSSIBLE UNDEVELOPED	11

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS - TBPE FIRM LICENSE No. F-1580 

 

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET    SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

October 20, 2022

BKV Corp.

1200 17th Street, Suite 1850

Denver, CO 80202

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved, probable and possible reserves, future production, and income attributable to certain leasehold and royalty interests of BKV Corp. (BKV) referred to as the Barnett Assets as of September 30, 2022. The subject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). This report is a mechanical roll-forward of our initial report that was evaluated as of June 30, 2022 and published on July 8, 2022. No additional production data or cost data were considered since our prior evaluation, and this report includes the same volume projections and cost assumptions as previously, except that the effective date here is shifted forward to September 30, 2022. BKV has not informed Ryder Scott, and we are not aware, of any significant changes that would materially alter our projections or reserve assignments. Our third party study, presented herein, was prepared for public disclosure by BKV in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties referred to as the Barnett Assets evaluated by Ryder Scott account for a portion of BKV Corp’s total net proved, probable and possible reserves as of September 30, 2022. Based on information provided by BKV, the third party estimate conducted by Ryder Scott addresses 89 percent of the total proved, 100 percent of the total probable and 100 percent of the total possible developed net liquid hydrocarbon reserves, 56 percent of the total proved, 98 percent of the total probable and 100 percent of the total possible developed net gas reserves, 90 percent of the total proved, 100 percent of the total probable and 100 percent of the total possible undeveloped net liquid hydrocarbon reserves, and 50 percent of the total proved, 71 percent of the total probable and 45 percent of the total possible undeveloped net gas reserves of BKV.

The estimated reserves and future net income amounts presented in this report, as of September 30, 2022 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices that were used in this report. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows. 

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

BKV Corp. – Barnett Assets (SEC)

October 20, 2022

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

BKV Corp.

Barnett Assets

As of September 30, 2022

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Reserves
Oil/Condensate – Mbbl		823		103		560		1,486
Plant Products – Mbbl		144,453		13,863		38,737		197,053
Gas – MMcf		1,932,667		235,416		568,625		2,736,708
Income Data ($M)
Future Gross Revenue	$	15,182,687	$	1,735,766	$	4,560,281	$	21,478,734
Deductions		5,103,538		515,849		1,568,805		7,188,192
Future Net Income (FNI)	$	10,079,149	$	1,219,917	$	2,991,476	$	14,290,542
Discounted FNI @ 10%	$	4,418,960	$	407,446	$	1,079,831	$	5,906,237

	Probable
	Developed				Total
	Non-Producing		Undeveloped		Probable
Net Reserves
Oil/Condensate – Mbbl		0		1,625		1,625
Plant Products – Mbbl		25,886		41,231		67,117
Gas – MMcf		354,047		412,308		766,355
Income Data ($M)
Future Gross Revenue	$	2,751,361	$	3,750,948	$	6,502,309
Deductions		852,832		1,418,869		2,271,701
Future Net Income (FNI)	$	1,898,529	$	2,332,079	$	4,230,608
Discounted FNI @ 10%	$	394,488	$	530,044	$	924,532

	Possible
	Developed				Total
	Non-Producing		Undeveloped		Possible
Net Reserves
Oil/Condensate – Mbbl		0		1,364		1,364
Plant Products – Mbbl		9,999		25,122		35,121
Gas – MMcf		107,126		201,338		308,464
Income Data ($M)
Future Gross Revenue	$	899,209	$	1,998,099	$	2,897,308
Deductions		253,602		878,953		1,132,555
Future Net Income (FNI)	$	645,607	$	1,119,146	$	1,764,753
Discounted FNI @ 10%	$	96,085	$	153,612	$	249,697

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – Barnett Assets (SEC)

October 20, 2022

Page 3

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (Mbbl). All gas volumes are expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas volumes are located. All gas reserves volumes are reported on an “as sold” basis. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of BKV. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Gas reserves account for approximately 71 percent and liquid hydrocarbon reserves account for the remaining 29 percent of total future gross revenue from proved reserves. Gas reserves account for approximately 66 percent and liquid hydrocarbon reserves account for the remaining 34 percent of total future gross revenue from probable reserves. Gas reserves account for approximately 59 percent and liquid hydrocarbon reserves account for the remaining 41 percent of total future gross revenue from possible reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income ($M)
	As of September 30, 2022
Discount Rate	Total		Total		Total
Percent	Proved		Probable		Possible
8	$	6,712,014	$	1,189,888	$	351,896
12	$	5,272,748	$	729,689	$	179,909
15	$	4,542,766	$	523,635	$	112,579
20	$	3,694,302	$	315,438	$	53,944

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved, probable and possible reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – Barnett Assets (SEC)

October 20, 2022

Page 4

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved, probable, and possible developed non-producing reserves included herein consist of the behind pipe status category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved, probable and possible gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At BKV’s request, this report addresses the proved, probable and possible reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those 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.” The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “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.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and are presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserves categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable and possible reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts. 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – Barnett Assets (SEC)

October 20, 2022

Page 5

BKV’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which BKV owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – Barnett Assets (SEC)

October 20, 2022

Page 6

The proved, probable and possible reserves for the properties included herein were estimated by performance methods or analogy. All of the proved reserves attributable to producing wells and/or reservoirs were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data ending between March and June 2022, depending on the availability of data for a given case and in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved, probable, and possible developed non-producing as well as all of the proved, probable, and possible undeveloped reserves included herein were estimated by analogy. The data utilized from the analogues were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

BKV has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved, probable and possible production and income, we have relied upon data furnished by BKV with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, and base maps. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by BKV. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved, probable and possible reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved, probable and possible reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For the producing wells included herein, our forecasts of future production rates and decline trends are based on the historical performance data of each well.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – Barnett Assets (SEC)

October 20, 2022

Page 7

The initial performance of analogous wells was used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by BKV. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions, and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

We furnished BKV with the above mentioned average prices in effect on September 30, 2022. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, certain gas firm transportation fees, certain NGL fractionation and transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by BKV. The differentials furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

				Average	Average	Average
			Average	Proved	Probable	Possible
Geographic		Price	Benchmark	Realized	Realized	Realized
Area	Product	Reference	Prices	Prices	Prices	Prices
North America
	Oil/Condensate	WTI Cushing	$91.71/bbl	$84.20/bbl	$84.20/bbl	$84.20/bbl
United States	NGLs	WTI Cushing	$91.71/bbl	$32.40/bbl	$32.40/bbl	$32.40/bbl
	Gas	Henry Hub	$6.127/MMBTU	$5.84/Mcf	$5.87/Mcf	$5.77/Mcf

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – Barnett Assets (SEC)

October 20, 2022

Page 8

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by BKV and are based on the operating expense reports of BKV and include only those costs directly applicable to the leases or wells. Certain gas gathering and transportation costs were included as operating expenses. The operating costs furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by BKV and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness using information furnished by BKV for this purpose. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by BKV were accepted without independent verification.

The proved developed non-producing and proved, probable, and possible undeveloped reserves in this report have been incorporated herein in accordance with BKV’s plans to develop these reserves as of September 30, 2022. The implementation of BKV’s development plans as presented to us and incorporated herein is subject to the approval process adopted by BKV’s management. As the result of our inquiries during the course of preparing this report, BKV has informed us that the development activities included herein have been subjected to and received the internal approvals required by BKV’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to BKV. BKV has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, BKV has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of September 30, 2022, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by BKV were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – Barnett Assets (SEC)

October 20, 2022

Page 9

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to BKV. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analyses conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by BKV.

For filings made with the SEC under the 1933 securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement on Form S-1 by BKV. Our consent for such use is included as a separate exhibit to the filings made with the SEC by BKV.

We have provided BKV with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by BKV and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
SEG (LPC)/pl

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at https://ryderscott.com/employees/denver-employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2021 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year covering topics such as reserves evaluation methods and evaluation software, ethics, regulatory issues, greenhouse gas management, and more.

Based on his educational background, professional training and more than 16 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

PETROLEUM RESERVES DEFINITIONS

Page 2

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

PETROLEUM RESERVES DEFINITIONS

Page 3

(ii)  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)  Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)  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.

(v) 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.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are 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.

(i)  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.

(ii) 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.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

PETROLEUM RESERVES DEFINITIONS

Page 4

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)  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.

(ii) 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.

(iii)  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.

(iv)  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.

(v)  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 areas are in communication with the proved reservoir.

(vi)  Pursuant to paragraph (a)(22)(iii) of this section, 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas 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; and

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves 

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing 

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from: 

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe 

Behind-pipe Reserves are expected to be recovered from 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 all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas 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.

(i) 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.

(ii) 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.

(iii)  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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.  

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

EX-99.10

Exhibit 99.10

BKV CORP.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

CHAFFEE CORNERS ASSETS

SEC Parameters

As of

September 30, 2022

Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV CORP.

TABLE OF CONTENTS

DISCUSSION 

PETROLEUM RESERVES DEFINITIONS

	TABLE NO.
PROPERTY RANKING	A
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA	B
SUMMARY OF INITIAL BASIC DATA	C
GRAND SUMMARIES
TOTAL PROVED	1
PROVED PRODUCING	2
PROVED SHUT-IN	3
PROVED UNDEVELOPED	4
PROBABLE UNDEVELOPED	5
POSSIBLE UNDEVELOPED	6

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS - TBPE FIRM LICENSE No. F-1580

 

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET    SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

October 20, 2022

BKV Corp. 

1200 17th Street, Suite 1850 

Denver, CO 80202

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved, probable and possible reserves, future production, and income attributable to certain leasehold interests of BKV Corp. (BKV) referred to as the Chaffee Corners Assets as of September 30, 2022. The subject properties are located in the state of Pennsylvania. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). This report is a mechanical roll-forward of our initial report that was evaluated as of June 30, 2022 and published on July 8, 2022. No additional production data or cost data were considered since our prior evaluation, and this report includes the same volume projections and cost assumptions as previously, except that the effective date here is shifted forward to September 30, 2022. BKV has not informed Ryder Scott, and we are not aware, of any significant changes that would materially alter our projections or reserve assignments. Our third party study, presented herein, was prepared for public disclosure by BKV in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties referred to as the Chaffee Corners Assets evaluated by Ryder Scott account for a portion of BKV Corp’s total net proved, probable and possible reserves as of September 30, 2022. Based on information provided by BKV, the third party estimate conducted by Ryder Scott addresses 0 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net liquid hydrocarbon reserves, 2 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net gas reserves, 0 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible undeveloped net liquid hydrocarbon reserves, and 1 percent of the total proved, 5 percent of the total probable and 2 percent of the total possible undeveloped net gas reserves of BKV.

The estimated reserves and future net income amounts presented in this report, as of September 30, 2022 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices that were used in this report. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

BKV Corp. – Chaffee Corners Assets (SEC) 

October 20, 2022 

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data 

Certain Leasehold Interests of 

BKV Corp.

Chaffee Corners Assets

As of September 30, 2022

	Proved
		Developed							Total
		Producing		Non-Producing(1)			Undeveloped		Proved
Net Reserves
Gas – MMcf			71,515		0			11,972		83,487
Income Data ($M)
Future Gross Revenue		$	430,694	$	0		$	72,100	$	502,794
Deductions			76,221		57			22,256		98,534
Future Net Income (FNI)		$	354,473	$	(57	)	$	49,844	$	404,260
Discounted FNI @ 10%		$	169,269	$	(54	)	$	20,393	$	189,608

(1) Negative values for Future Net Income and Discounted FNI are due to abandonment liability.

	Total  Probable  Undeveloped		Total  Possible  Undeveloped
Net Reserves
Gas – MMcf		28,916		8,115
Income Data ($M)
Future Gross Revenue	$	174,142	$	48,873
Deductions		51,861		21,013
Future Net Income (FNI)	$	122,281	$	27,860
Discounted FNI @ 10%	$	40,458	$	5,512

All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of BKV. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes, but in the state of Pennsylvania, these taxes are zero. The deductions incorporate the normal direct costs of operating the wells, the Pennsylvania Impact Fee (presented herein as ad valorem taxes), development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chaffee Corners Assets (SEC) 

October 20, 2022 

Page 3 

Gas reserves account for 100 percent of the total future gross revenue from the proved, probable, and possible reserves reported herein.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income ($M)
	As of September 30, 2022
Discount Rate	Total		Total		Total
Percent	Proved		Probable		Possible
8	$	211,968	$	48,454	$	7,401
12	$	171,734	$	34,212	$	4,139
15	$	150,792	$	27,104	$	2,720
20	$	125,920	$	19,069	$	1,360

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved, probable and possible reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The negative values of future net income and discounted FNI shown in the proved developed non-producing category comprise shut-in wells with only an abandonment liability.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved, probable and possible gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At BKV’s request, this report addresses the proved, probable and possible reserves attributable to the properties evaluated herein.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chaffee Corners Assets (SEC) 

October 20, 2022 

Page 4 

Proved oil and gas reserves are “those 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.” The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “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.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and are presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserves categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable and possible reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

BKV’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which BKV owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chaffee Corners Assets (SEC) 

October 20, 2022 

Page 5

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved, probable and possible reserves for the properties included herein were estimated by performance methods or analogy. All of the proved reserves attributable to producing wells and/or reservoirs were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data ending between April and June 2022, depending on the availability of data for a given case and in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved, probable, and possible undeveloped reserves included herein were estimated by analogy. The data utilized from the analogues were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chaffee Corners Assets (SEC) 

October 20, 2022 

Page 6

BKV has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved, probable and possible production and income, we have relied upon data furnished by BKV with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, the Pennsylvania Impact Fee, development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, and base maps. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by BKV. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved, probable and possible reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved, probable and possible reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For the producing wells included herein, our forecasts of future production rates and decline trends are based on the historical performance data of each well.

The initial performance of analogous wells was used to estimate the anticipated initial production rates for those locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by BKV. Locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions, and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chaffee Corners Assets (SEC) 

October 20, 2022 

Page 7

We furnished BKV with the above mentioned average price in effect on September 30, 2022. The initial SEC hydrocarbon price was determined using the 12-month average first-day-of-the-month benchmark price appropriate to the geographic area where the hydrocarbons are sold. The benchmark price is prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark price” and “price reference” used for the geographic area included in the report.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark price for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by BKV. The differentials furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose.

In addition, the table below summarizes the net volume weighted benchmark price adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

Geographic  Area	Product	Price  Reference	Average  Benchmark  Price	Average  Proved  Realized  Price	Average  Probable  Realized  Price	Average  Possible  Realized  Price
North America	Gas	Henry Hub	$6.127/MMBTU	$6.02/Mcf	$6.02/Mcf	$6.02/Mcf

The effects of derivative instruments designated as price hedges of gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by BKV and are based on the operating expense reports of BKV and include only those costs directly applicable to the leases or wells. Certain gathering and transportation fees are included as operating costs. The operating costs furnished by BKV were reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by BKV to determine these costs. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by BKV and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by BKV were reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by BKV to determine these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by BKV were accepted without independent verification. 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chaffee Corners Assets (SEC) 

October 20, 2022 

Page 8

The proved, probable, and possible undeveloped reserves in this report have been incorporated herein in accordance with BKV’s plans to develop these reserves as of September 30, 2022. The implementation of BKV’s development plans as presented to us and incorporated herein is subject to the approval process adopted by BKV’s management. As the result of our inquiries during the course of preparing this report, BKV has informed us that the development activities included herein have been subjected to and received the internal approvals required by BKV’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to BKV. BKV has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, BKV has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of September 30, 2022, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by BKV were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to BKV. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analyses conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chaffee Corners Assets (SEC) 

October 20, 2022 

Page 9

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by BKV.

For filings made with the SEC under the 1933 securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement on Form S-1 by BKV. Our consent for such use is included as a separate exhibit to the filings made with the SEC by BKV.

We have provided BKV with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by BKV and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
SEG (LPC)/pl

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at https://ryderscott.com/employees/denver-employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2021 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year covering topics such as reserves evaluation methods and evaluation software, ethics, regulatory issues, greenhouse gas management, and more.

Based on his educational background, professional training and more than 16 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS 

Page 2

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS 

Page 3

(ii)  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) 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.

(v) 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.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are 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.

(i)  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.

(ii) 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.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS 

Page 4

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)  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.

(ii) 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.

(iii) 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.

(iv) 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.

(v)  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 areas are in communication with the proved reservoir.

(vi)  Pursuant to paragraph (a)(22)(iii) of this section, 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by: 

SOCIETY OF PETROLEUM ENGINEERS (SPE) 

WORLD PETROLEUM COUNCIL (WPC) 

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) 

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG) 

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas 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; and

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES 

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing 

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In 

Shut-in Reserves are expected to be recovered from: 

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from 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 all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas 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.

(i) 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.

(ii) 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.

(iii) 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

EX-99.11

Exhibit 99.11

BKV CORP.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

CHELSEA ASSETS

SEC Parameters

As of

September 30, 2022

Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV CORP.

TABLE OF CONTENTS

DISCUSSION
PETROLEUM RESERVES DEFINITIONS
	TABLE NO.
PROPERTY RANKING	A
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA	B
SUMMARY OF INITIAL BASIC DATA	C
GRAND SUMMARIES
TOTAL PROVED	1
PROVED PRODUCING	2
PROVED SHUT-IN	3
PROVED BEHIND PIPE	4
PROVED UNDEVELOPED	5
PROBABLE UNDEVELOPED	6
POSSIBLE UNDEVELOPED	7

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS - TBPE FIRM LICENSE No. F-1580

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET   SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

October 20, 2022

BKV Corp.
1200 17th Street, Suite 1850
Denver, CO 80202

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved, probable and possible reserves, future production, and income attributable to certain leasehold interests of BKV Corp. (BKV) referred to as the Chelsea Assets as of September 30, 2022. The subject properties are located in the state of Pennsylvania. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). This report is a mechanical roll-forward of our initial report that was evaluated as of June 30, 2022 and published on July 8, 2022. No additional production data or cost data were considered since our prior evaluation, and this report includes the same volume projections and cost assumptions as previously, except that the effective date here is shifted forward to September 30, 2022. BKV has not informed Ryder Scott, and we are not aware, of any significant changes that would materially alter our projections or reserve assignments. Our third party study, presented herein, was prepared for public disclosure by BKV in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties referred to as the Chelsea Assets evaluated by Ryder Scott account for a portion of BKV Corp’s total net proved, probable and possible reserves as of September 30, 2022. Based on information provided by BKV, the third party estimate conducted by Ryder Scott addresses 0 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net liquid hydrocarbon reserves, 6 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net gas reserves, 0 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible undeveloped net liquid hydrocarbon reserves, and 14 percent of the total proved, 14 percent of the total probable and 32 percent of the total possible undeveloped net gas reserves of BKV.

The estimated reserves and future net income amounts presented in this report, as of September 30, 2022 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices that were used in this report. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

BKV Corp. – Chelsea Assets (SEC)
October 20, 2022
Page 2

SEC PARAMETERS 

Estimated Net Reserves and Income Data 

Certain Leasehold Interests of 

BKV Corp. 

Chelsea Assets 

As of September 30, 2022

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Reserves
Gas – MMcf		214,790		5,922		165,103		385,815
Income Data ($M)
Future Gross Revenue	$	1,181,725	$	32,879	$	910,548	$	2,125,152
Deductions		351,004		11,614		256,493		619,111
Future Net Income (FNI)	$	830,721	$	21,265	$	654,055	$	1,506,041
Discounted FNI @ 10%	$	416,386	$	10,405	$	270,560	$	697,351

	Total Probable Undeveloped		Total Possible Undeveloped
Net Reserves
Gas – MMcf		82,468		142,650
Income Data ($M)
Future Gross Revenue	$	454,499	$	782,806
Deductions		140,300		288,815
Future Net Income (FNI)	$	314,199	$	493,991
Discounted FNI @ 10%	$	94,570	$	106,953

All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of BKV. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes, but in the state of Pennsylvania, these taxes are zero. The deductions incorporate the normal direct costs of operating the wells, the Pennsylvania Impact Fee (presented herein as ad valorem taxes), development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)
October 20, 2022
Page 3

Gas reserves account for 100 percent of the total future gross revenue from the proved, probable, and possible reserves reported herein.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income ($M) As of September 30, 2022
Discount Rate Percent	Total Proved		Total Probable		Total Possible
8	$	782,903	$	115,436	$	139,633
12	$	628,527	$	78,455	$	82,983
15	$	547,360	$	60,405	$	57,845
20	$	450,260	$	40,582	$	33,032

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved, probable and possible reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe status categories.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved, probable and possible gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At BKV’s request, this report addresses the proved, probable and possible reserves attributable to the properties evaluated herein.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)
October 20, 2022
Page 4

Proved oil and gas reserves are “those 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.” The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “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.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and are presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserves categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable and possible reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

BKV’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which BKV owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)
October 20, 2022
Page 5

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved, probable and possible reserves for the properties included herein were estimated by performance methods or analogy. All of the proved reserves attributable to producing wells and/or reservoirs were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data ending between April and June 2022, depending on the availability of data for a given case and in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved, probable, and possible undeveloped reserves included herein were estimated by analogy. The data utilized from the analogues were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)
October 20, 2022
Page 6

BKV has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved, probable and possible production and income, we have relied upon data furnished by BKV with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, the Pennsylvania Impact Fee, development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, and base maps. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by BKV. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved, probable and possible reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved, probable and possible reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For the producing wells included herein, our forecasts of future production rates and decline trends are based on the historical performance data of each well.

The initial performance of analogous wells was used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by BKV. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions, and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)
October 20, 2022
Page 7

We furnished BKV with the above mentioned average price in effect on September 30, 2022. The initial SEC hydrocarbon price was determined using the 12-month average first-day-of-the-month benchmark price appropriate to the geographic area where the hydrocarbons are sold. The benchmark price is prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark price” and “price reference” used for the geographic area included in the report.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark price for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by BKV. The differentials furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose.

In addition, the table below summarizes the net volume weighted benchmark price adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Price	Average Proved Realized Price	Average Probable Realized Price	Average Possible Realized Price
North America	Gas	Henry Hub	$6.127/MMBTU	$5.51/Mcf	$5.51/Mcf	$5.49/Mcf

The effects of derivative instruments designated as price hedges of gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by BKV and are based on the operating expense reports of BKV and include only those costs directly applicable to the leases or wells. Certain gathering and transportation fees are included as operating costs. The operating costs furnished by BKV were reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by BKV to determine these costs. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by BKV and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by BKV were reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by BKV to determine these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by BKV were accepted without independent verification.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)
October 20, 2022
Page 8

The proved, probable, and possible undeveloped reserves in this report have been incorporated herein in accordance with BKV’s plans to develop these reserves as of September 30, 2022. The implementation of BKV’s development plans as presented to us and incorporated herein is subject to the approval process adopted by BKV’s management. As the result of our inquiries during the course of preparing this report, BKV has informed us that the development activities included herein have been subjected to and received the internal approvals required by BKV’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to BKV. BKV has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, BKV has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of September 30, 2022, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by BKV were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to BKV. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analyses conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – Chelsea Assets (SEC)
October 20, 2022
Page 9

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by BKV.

For filings made with the SEC under the 1933 securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement on Form S-1 by BKV. Our consent for such use is included as a separate exhibit to the filings made with the SEC by BKV.

We have provided BKV with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by BKV and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
SEG (LPC)/pl

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at https://ryderscott.com/employees/denver-employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2021 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year covering topics such as reserves evaluation methods and evaluation software, ethics, regulatory issues, greenhouse gas management, and more.

Based on his educational background, professional training and more than 16 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS
Page 2

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS
Page 3

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) 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.

(v) 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.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are 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.

(i) 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.

(ii) 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.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS
Page 4

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) 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.

(ii) 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.

(iii) 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.

(iv) 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.

(v) 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 areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:
RULE 4-10(a) of REGULATION S-X PART 210
UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by:
SOCIETY OF PETROLEUM ENGINEERS (SPE)
WORLD PETROLEUM COUNCIL (WPC)
AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)
SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)
SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)
EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas 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; and

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves 

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES
Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing 

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In 

Shut-in Reserves are expected to be recovered from:

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe 

Behind-pipe Reserves are expected to be recovered from 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 all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas 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.

(i)  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.

(ii) 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.

(iii) 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

EX-99.12

Exhibit 99.12

BKV CORP.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

BKV ASSETS

SEC Parameters

As of

September 30, 2022

Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV CORP.

TABLE OF CONTENTS

DISCUSSION 

PETROLEUM RESERVES DEFINITIONS

	TABLE NO.
PROPERTY RANKING	A
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA	B
SUMMARY OF INITIAL BASIC DATA	C
GRAND SUMMARIES
TOTAL PROVED	1
PROVED PRODUCING	2
PROVED SHUT-IN	3
PROVED BEHIND PIPE	4
PROVED UNDEVELOPED	5
PROBABLE UNDEVELOPED	6
POSSIBLE UNDEVELOPED	7

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS - TBPE FIRM LICENSE No. F-1580 

 

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET    SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

October 20, 2022

BKV Corp. 

1200 17th Street, Suite 1850 

Denver, CO 80202

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved, probable and possible reserves, future production, and income attributable to certain leasehold interests of BKV Corp. (BKV) referred to as the BKV Assets as of September 30, 2022. The subject properties are located in the state of Pennsylvania. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). This report is a mechanical roll-forward of our initial report that was evaluated as of June 30, 2022 and published on July 8, 2022. No additional production data or cost data were considered since our prior evaluation, and this report includes the same volume projections and cost assumptions as previously, except that the effective date here is shifted forward to September 30, 2022. BKV has not informed Ryder Scott, and we are not aware, of any significant changes that would materially alter our projections or reserve assignments. Our third party study, presented herein, was prepared for public disclosure by BKV in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties referred to as the BKV Assets evaluated by Ryder Scott account for a portion of BKV Corp’s total net proved, probable and possible reserves as of September 30, 2022. Based on information provided by BKV, the third party estimate conducted by Ryder Scott addresses 0 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net liquid hydrocarbon reserves, 7 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net gas reserves, 0 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible undeveloped net liquid hydrocarbon reserves, and 17 percent of the total proved, 10 percent of the total probable and 21 percent of the total possible undeveloped net gas reserves of BKV.

The estimated reserves and future net income amounts presented in this report, as of September 30, 2022 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices that were used in this report. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

BKV Corp. – BKV Assets (SEC) 

October 20, 2022 

Page 2

SEC PARAMETERS 

Estimated Net Reserves and Income Data 

Certain Leasehold Interests of 

BKV Corp. 

BKV Assets 

As of September 30, 2022

	Proved
	Developed						Total Proved
	Producing		Non-Producing		Undeveloped
Net Reserves
Gas – MMcf		247,934		15,858		192,008		455,800
Income Data ($M)
Future Gross Revenue	$	1,371,156	$	88,039	$	1,065,233	$	2,524,428
Deductions		397,051		31,694		324,742		753,487
Future Net Income (FNI)	$	974,105	$	56,345	$	740,491	$	1,770,941
Discounted FNI @ 10%	$	506,051	$	27,506	$	307,777	$	841,334

	Total Probable Undeveloped		Total Possible Undeveloped
Net Reserves
Gas – MMcf		56,630		93,339
Income Data ($M)
Future Gross Revenue	$	313,789	$	512,059
Deductions		104,428		189,641
Future Net Income (FNI)	$	209,361	$	322,418
Discounted FNI @ 10%	$	60,190	$	69,668

 All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of BKV. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes, but in the state of Pennsylvania, these taxes are zero. The deductions incorporate the normal direct costs of operating the wells, the Pennsylvania Impact Fee (presented herein as ad valorem taxes), development costs, and certain abandonment costs net of salvage. Certain gas processing costs are displayed in the cash flows as “Other” deductions. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – BKV Assets (SEC) 

October 20, 2022 

Page 3

Gas reserves account for 100 percent of the total future gross revenue from the proved, probable, and possible reserves reported herein.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income ($M) As of September 30, 2022
Discount Rate Percent		Total Proved		Total Probable		Total Possible
8	$	940,110	$	74,244	$	90,995
12	$	761,716	$	49,384	$	54,030
15	$	667,605	$	37,365	$	37,637
20	$	554,663	$	24,337	$	21,470

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved, probable and possible reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe status categories.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved, probable and possible gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At BKV’s request, this report addresses the proved, probable and possible reserves attributable to the properties evaluated herein.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – BKV Assets (SEC) 

October 20, 2022 

Page 4

Proved oil and gas reserves are “those 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.” The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “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.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and are presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserves categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved, probable and possible reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

BKV’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which BKV owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – BKV Assets (SEC) 

October 20, 2022 

Page 5

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved, probable and possible reserves for the properties included herein were estimated by performance methods or analogy. All of the proved reserves attributable to producing wells and/or reservoirs were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data ending between April and June 2022, depending on the availability of data for a given case and in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved, probable, and possible undeveloped reserves included herein were estimated by analogy. The data utilized from the analogues were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – BKV Assets (SEC) 

October 20, 2022 

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BKV has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved, probable and possible production and income, we have relied upon data furnished by BKV with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, the Pennsylvania Impact Fee, development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, and base maps. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by BKV. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved, probable and possible reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved, probable and possible reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For the producing wells included herein, our forecasts of future production rates and decline trends are based on the historical performance data of each well.

The initial performance of analogous wells was used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by BKV. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions, and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period. 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – BKV Assets (SEC) 

October 20, 2022 

Page 7

We furnished BKV with the above mentioned average price in effect on September 30, 2022. The initial SEC hydrocarbon price was determined using the 12-month average first-day-of-the-month benchmark price appropriate to the geographic area where the hydrocarbons are sold. The benchmark price is prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark price” and “price reference” used for the geographic area included in the report.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by BKV. The differentials furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose.

In addition, the table below summarizes the net volume weighted benchmark price adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Price	Average Proved Realized Price	Average Probable Realized Price	Average Possible Realized Price
North America	Gas	Henry Hub	$6.127/MMBTU	$5.54/Mcf	$5.54/Mcf	$5.49/Mcf

The effects of derivative instruments designated as price hedges of gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by BKV and are based on the operating expense reports of BKV and include only those costs directly applicable to the leases or wells. Certain gathering and transportation fees are included as operating costs. The operating costs furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by BKV and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by BKV were accepted without independent verification.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – BKV Assets (SEC) 

October 20, 2022 

Page 8

The proved, probable, and possible undeveloped reserves in this report have been incorporated herein in accordance with BKV’s plans to develop these reserves as of September 30, 2022. The implementation of BKV’s development plans as presented to us and incorporated herein is subject to the approval process adopted by BKV’s management. As the result of our inquiries during the course of preparing this report, BKV has informed us that the development activities included herein have been subjected to and received the internal approvals required by BKV’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to BKV. BKV has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, BKV has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of September 30, 2022, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by BKV were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to BKV. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analyses conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

BKV Corp. – BKV Assets (SEC) 

October 20, 2022 

Page 9

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by BKV.

For filings made with the SEC under the 1933 securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement on Form S-1 by BKV. Our consent for such use is included as a separate exhibit to the filings made with the SEC by BKV.

We have provided BKV with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by BKV and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
SEG (LPC)/pl

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at https://ryderscott.com/employees/denver-employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2021 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year covering topics such as reserves evaluation methods and evaluation software, ethics, regulatory issues, greenhouse gas management, and more.

Based on his educational background, professional training and more than 16 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

PETROLEUM RESERVES DEFINITIONS

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

PETROLEUM RESERVES DEFINITIONS 

Page 2

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

PETROLEUM RESERVES DEFINITIONS 

Page 3

(ii)  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)   Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)  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.

(v) 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.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are 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.

(i)  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.

(ii)  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.

(iii)  Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

PETROLEUM RESERVES DEFINITIONS 

Page 4

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)  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.

(ii) 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.

(iii) 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.

(iv) 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.

(v)  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 areas are in communication with the proved reservoir.

(vi)  Pursuant to paragraph (a)(22)(iii) of this section, 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by: 

SOCIETY OF PETROLEUM ENGINEERS (SPE) 

WORLD PETROLEUM COUNCIL (WPC) 

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) 

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG) 

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas 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; and

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves 

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES 

Page 2

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing 

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In 

Shut-in Reserves are expected to be recovered from: 

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe 

Behind-pipe Reserves are expected to be recovered from 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 all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas 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.

(i) 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.

(ii) 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.

(iii) 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS  

EX-99.13

Exhibit 99.13

BKV CORP.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

XTO AQUISITION ASSETS

SEC Parameters

As of

September 30, 2022

Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
RYDER SCOTT COMPANY, L.P.
TBPELS Firm Registration No. F-1580

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV CORP.

TABLE OF CONTENTS

DISCUSSION
PETROLEUM RESERVES DEFINITIONS
	TABLE NO.
PROPERTY RANKING	A
SUMMARY OF GROSS AND NET RESERVE AND INCOME DATA	B
SUMMARY OF INITIAL BASIC DATA	C
GRAND SUMMARIES
TOTAL PROVED	1
PROVED PRODUCING	2
PROVED BEHIND PIPE	3
PROVED UNDEVELOPED	4
PROBABLE BEHIND PIPE	5
NON-OPERATED OP_CAT SUMMARIES
PROVED PRODUCING	6
OPERATED OP_CAT SUMMARIES
TOTAL PROVED	7
PROVED PRODUCING	8
PROVED BEHIND PIPE	9
PROVED UNDEVELOPED	10
PROBABLE BEHIND PIPE	11
ROYALTY OP_CAT SUMMARIES
PROVED PRODUCING	12

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS - TBPE FIRM LICENSE No. F-1580

 

TBPELS REGISTERED ENGINEERING FIRM F-1580
633 17TH STREET    SUITE 1700	DENVER, COLORADO 80202	TELEPHONE (303) 339-8110

October 20, 2022

BKV Corp.

1200 17th Street, Suite 1850

Denver, CO 80202

Ladies and Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved and probable reserves, future production and income attributable to certain leasehold and royalty interests of BKV Corp. (BKV) as of September 30, 2022. The subject properties were recently acquired from XTO Energy Inc. (XTO) and are located in the Barnett Shale play of Texas, referred to herein as Project Europa. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). This report is a mechanical roll-forward of our initial report that was evaluated as of February 1, 2022 and published on May 18, 2022. No additional production data or cost data were considered since our prior evaluation, and this report includes the same volume projections and cost assumptions as previously, except that the effective date here is shifted forward to September 30, 2022. BKV has not informed Ryder Scott, and we are not aware, of any significant changes that would materially alter our projections or reserve assignments. Our third party study, presented herein, was prepared for public disclosure by BKV in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties referred to as the Project Europa evaluated by Ryder Scott account for a portion of BKV Corp’s total net proved, probable and possible reserves as of September 30, 2022. Based on information provided by BKV, the third party estimate conducted by Ryder Scott addresses 11 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible developed net liquid hydrocarbon reserves, 29 percent of the total proved, 2 percent of the total probable and 0 percent of the total possible developed net gas reserves, 10 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible undeveloped net liquid hydrocarbon reserves, and 18 percent of the total proved, 0 percent of the total probable and 0 percent of the total possible undeveloped net gas reserves of BKV.

The estimated reserves and future net income amounts presented in this report, as of September 30, 2022 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, as required by the SEC regulations. Actual future prices may vary considerably from the prices that were used in this report. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

1100 LOUISIANA, SUITE 4600	HOUSTON, TEXAS 77002-5294	TEL (713) 651-9191	FAX (713) 651-0849
SUITE 2800, 350 7TH AVENUE, S.W.	CALGARY, ALBERTA T2P 3N9	TEL (403) 262-2799

BKV Corp. – XTO Acquisition Assets (SEC Parameters)

October 11, 2022

Page 2

SEC PRICE AND CONSTANT COST PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests

BKV Corp.

As of September 30, 2022

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Reserves
Oil/Condensate – Mbbl		197		0		60		257
Plant Products – Mbbl		19,376		0		4,159		23,535
Gas – MMcf		999,853		133,852		202,758		1,336,463
Income Data ($M)
Future Gross Revenue	$	5,422,217	$	667,070	$	1,125,468	$	7,214,755
Deductions		1,667,662		167,951		297,587		2,133,200
Future Net Income (FNI)	$	3,754,555	$	499,119	$	827,881	$	5,081,555
Discounted FNI @ 10%	$	1,717,404	$	170,591	$	295,216	$	2,183,211

	Total
	Probable
	Non-Producing
Net Reserves
Oil/Condensate – Mbbl		0
Plant Products – Mbbl		0
Gas – MMcf		6,164
Income Data ($M)
Future Gross Revenue	$	31,266
Deductions		7,908
Future Net Income (FNI)	$	23,358
Discounted FNI @ 10%	$	6,083

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels and shown herein as thousands of barrels (Mbbl). All gas volumes are expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas volumes are located. All gas reserves volumes are reported on an “as sold” basis. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package ARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of BKV. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – XTO Acquisition Assets (SEC Parameters)

October 11, 2022

Page 3

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion and development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Gas reserves account for approximately 91 percent and liquid hydrocarbon reserves account for the remaining 9 percent of total future gross revenue from proved reserves. Gas reserves account for 100 percent of total future gross revenue from probable reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

	Discounted Future Net Income ($M)
	As of September 30, 2022
Discount Rate	Total		Total
Percent	Proved		Probable
8	$	2,476,132	$	7,584
12	$	1,950,903	$	4,947
15	$	1,681,228	$	3,701
20	$	1,365,541	$	2,371

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved and probable reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS and GUIDELINES” in this report. The developed proved and probable non-producing reserves included herein consist of the behind pipe status category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved and probable gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends primarily on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At BKV’s request, this report addresses the proved and probable reserves attributable to the properties evaluated herein.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – XTO Acquisition Assets (SEC Parameters)

October 11, 2022

Page 4

Proved oil and gas reserves are “those 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.” The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.” Probable reserves are “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.” Possible reserves are “those additional reserves which are less certain to be recovered than probable reserves” and thus the probability of achieving or exceeding the proved plus probable plus possible reserves is low.

The reserves included herein were estimated using deterministic methods and are presented as incremental quantities. Under the deterministic incremental approach, discrete quantities of reserves are estimated and assigned separately as proved, probable or possible based on their individual level of uncertainty. Because of the differences in uncertainty, caution should be exercised when aggregating quantities of oil and gas from different reserves categories. Furthermore, the reserves and income quantities attributable to the different reserves categories that are included herein have not been adjusted to reflect these varying degrees of risk associated with them and thus are not comparable.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved, probable and possible reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved and probable reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

BKV’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of reserves actually recovered and amounts of income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which BKV owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – XTO Acquisition Assets (SEC Parameters)

October 11, 2022

Page 5

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are 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.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved and probable reserves for the properties included herein were estimated by performance methods or analogy. All of the proved reserves attributable to producing wells and/or reservoirs were estimated by decline curve analysis, a performance method which utilized extrapolations of historical production and pressure data available through December 2021 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved and probable non-producing as well as all of the proved undeveloped reserves included herein were estimated by analogy. The data utilized from the analogues were furnished to Ryder Scott by BKV or obtained from public data sources and were considered sufficient for the purpose thereof.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – XTO Acquisition Assets (SEC Parameters)

October 11, 2022

Page 6

To estimate economically recoverable proved, probable and possible oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved, probable and possible reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

BKV has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved and probable production and income, we have relied upon data furnished by BKV with respect to property interests acquired, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, and base maps. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by BKV. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved and probable reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved and probable reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For the producing wells included herein, our forecasts of future production rates and decline trends are based on the historical performance data of each well.

The initial performance of analogous wells was used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by BKV. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, well completions, and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – XTO Acquisition Assets (SEC Parameters)

October 11, 2022

Page 7

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period.

We furnished BKV with the above mentioned average prices in effect on September 30, 2022. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by BKV. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by BKV to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserves category for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Proved Realized Prices	Average Probable Realized Prices
North America
	Oil/Condensate	WTI Cushing	$91.71/bbl	$86.51/bbl	N/A
United States	NGLs	WTI Cushing	$91.71/bbl	$27.93/bbl	N/A
	Gas	Henry Hub	$6.127/MMBTU	$5.06/Mcf	$5.23/Mcf

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – XTO Acquisition Assets (SEC Parameters)

October 11, 2022

Page 8

Costs

Operating costs for the leases and wells in this report were furnished by BKV and are based on the operating expense reports of XTO and include only those costs directly applicable to the leases or wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by BKV. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by BKV and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by BKV were reviewed by us for their reasonableness using information furnished by BKV for this purpose. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by BKV were accepted without independent verification.

The proved and probable developed non-producing and proved undeveloped reserves in this report have been incorporated herein in accordance with BKV’s plans to develop these reserves as of September 30, 2022. The implementation of BKV’s development plans as presented to us and incorporated herein is subject to the approval process adopted by BKV’s management. As the result of our inquiries during the course of preparing this report, BKV has informed us that the development activities included herein have been subjected to and received the internal approvals required by BKV’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to BKV. BKV has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, BKV has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of September 30, 2022, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by BKV were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

BKV Corp. – XTO Acquisition Assets (SEC Parameters)

October 11, 2022

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Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to BKV. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analyses conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by BKV.

For filings made with the SEC under the 1933 securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement on Form S-1 by BKV. Our consent for such use is included as a separate exhibit to the filings made with the SEC by BKV.

We have provided BKV with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by BKV and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

	Very truly yours,
	RYDER SCOTT COMPANY, L.P.
	TBPELS Firm Registration No. F-1580
	Stephen E. Gardner, P.E. Colorado License No. 44720 Managing Senior Vice President
SEG (LPC)/pl

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Stephen E. Gardner is the primary technical person responsible for the estimate of the reserves, future production and income.

Mr. Gardner, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Gardner served in a number of engineering positions with Exxon Mobil Corporation. For more information regarding Mr. Gardner’s geographic and job specific experience, please refer to the Ryder Scott Company website at https://ryderscott.com/employees/denver-employees.

Mr. Gardner earned a Bachelor of Science degree in Mechanical Engineering from Brigham Young University in 2001 (summa cum laude). He is a licensed Professional Engineer in the States of Colorado and Texas. Mr. Gardner is a member of the Society of Petroleum Engineers and a former chairperson of the Society of Petroleum Evaluation Engineers for the Denver Chapter. He also currently serves on the latter organization’s board of directors at the international level.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of 15 hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Gardner fulfills. As part of his 2021 continuing education hours, Mr. Gardner attended the annual Ryder Scott Reserves Conference, which covered a variety of reserves topics including analysis techniques for unconventional reservoirs, ESG issues, reserves definitions and guidelines, SEC comment letter trends, and others. In addition, Mr. Gardner participated in various SPE and SPEE technical seminars, and other internal company training courses throughout the year covering topics such as reserves evaluation methods and evaluation software, ethics, regulatory issues, greenhouse gas management, and more.

Based on his educational background, professional training and more than 16 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Gardner has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

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Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

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(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) 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.

(v) 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.

PROBABLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(18) defines probable oil and gas reserves as follows:

Probable reserves. Probable reserves are 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.

(i)  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.

(ii)  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.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

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(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

POSSIBLE RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(17) defines possible oil and gas reserves as follows:

Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)  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.

(ii) 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.

(iii) 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.

(iv) 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.

(v)  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 areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, 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.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas 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; and

(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.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

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Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from 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 all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas 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.

(i)  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.

(ii)  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.

(iii) 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS