S-1 1 tm2217921-9_drsa.htm S-1 tm2217921-9_drsa - none - 105.9848549s
As filed with the Securities and Exchange Commission on November 18, 2022
Registration No. 333-      
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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
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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 37 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.
Joint Book-Running Managers
Credit Suisse
BofA Securities
Barclays
Citigroup
Evercore ISI
Jefferies
Co-Managers
TPH&Co.
Susquehanna Financial Group, LLLP
SMBC Nikko
The date of this prospectus is               , 2022.

 
TABLE OF CONTENTS
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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 September 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:
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.
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.
 
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MBbls” refers to one thousand barrels of crude oil or other liquid hydrocarbons.
Mcf” refers to one thousand cubic feet.
Mcf/d” refers to one thousand cubic feet per day.
Mcfe” refers to one thousand cubic feet of natural gas equivalent.
MMBtu” refers to one million 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 tons of LNG per year.
Mtpy” refers to million metric tons per year.
net acres” refers to the percentage of total acres an owner has out of a particular number of acres, or a specified tract. For example, an owner who has 50% interest in 100 acres owns 50 net acres.
net operated development well” refers to a gross operated development well that has been drilled, proportionately reduced by our working interest in such well.
NGL” refers to natural gas liquids.
NYMEX” refers to the New York Mercantile Exchange.
OPEC” refers to the Organization of the Petroleum Exporting Countries.
possible reserves” means those additional reserves that analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the estimate of proved plus probable plus possible reserves.
probable reserves” means those additional reserves that analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves. In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the estimate of proved plus probable reserves.
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.
 
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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 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 September 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.
 
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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.
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.
 
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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 196 proved undeveloped, 162 probable and 150 possible horizontal locations, and 652 proved developed non-producing, 738 probable, and 294 possible 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 96.1% 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. In addition, the BKV-BPP Power Joint Venture is in the process of developing a retail marketing business to sell electricity to commercial, industrial, and residential retail customers in Texas through its wholly owned subsidiary, BKV-BPP Retail, LLC, and has recently received the necessary approvals from the Public Utility Commission of Texas and ERCOT to do so. We intend to continue to build out our power generation business through opportunistic acquisitions of power generation assets and 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
Through our CCUS business, we aim to reduce man-made GHG emissions by capturing CO2 emitted in connection with natural gas activities, whether from our own operations or third party operations, as well as from other energy and industrial sources. Our process involves capturing CO2 before it is released into the atmosphere and then compressing the captured CO2 and transporting it via pipeline to sites where it can be injected into underground injection control (“UIC”) wells. Although we formally launched our CCUS business in March 2022 with the establishment of BKV dCarbon Ventures, we have been evaluating project opportunities and developing our CCUS business for 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 returns via tax credits and other tax benefits by the end of 2023, and we expect to begin generating positive Adjusted EBITDAX in 2025. We currently expect to be capable of funding our entire CCUS business with cash flows from operations, as well as from a variety of external sources, at our discretion, which may include joint ventures, project-based equity partnerships and federal grants.
We seek to execute CCUS projects with attractive standalone economics for high, medium and low CO2 concentration streams that contribute to our goals 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 of the Scope 1, 2 and 3 emissions from our owned and operated upstream businesses by the early 2030s. We estimate that our owned and operated upstream Scope 1 and 2 emissions were approximately 2.2 Mtpy CO2e as of September 30, 2022 and that our owned and operated upstream Scope 1, 2 and 3 emissions were 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 1, 2 and 3 emissions. Additionally, we have identified twelve potential CCUS projects that we believe are commercially viable based on economics supported by the carbon tax credits available under Section 45Q of the Code (“Section 45Q tax credits”) and that we believe can be completed by 2029 in order to achieve our Scope 1, 2 and 3 emissions goals. Of these twelve identified projects:

we have reached FID and entered into definitive agreements with respect to the Barnett Zero Project and reached internal FID for the Cotton Cove Project, which have a combined forecasted sequestration volume of approximately 0.27 Mtpy CO2e by the end of 2024;

three are natural gas processing (“NGP”) projects that we anticipate reaching FID by December 31, 2023 and, if FID is approved, achieving forecasted sequestration volume of approximately 1.39 Mtpy CO2e by the end of 2025;

three are higher concentration industrial projects that we anticipate reaching FID by the end of 2023 and, if FID is approved, achieving first sequestration between 2026 and 2029 and which have a combined forecasted sequestration volume of approximately 14.5 Mtpy CO2e; and
 
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four other CCUS projects are under evaluation that have a combined forecasted sequestration volume of approximately 13.24 Mtpy CO2e.
In addition, we expect to continuously identify and evaluate additional CCUS projects. While the aggregate forecasted volume of carbon capture and sequestration from our twelve identified potential CCUS projects is approximately 30 Mtpy CO2e, which is more than our current Scope 1, 2 and 3 emissions from our owned and operated upstream businesses, we do not anticipate achieving an aggregate yearly volume of sequestration of 30 Mtpy CO2e by the early 2030s and there can be no guarantee that we will be able to execute and complete any of the twelve identified CCUS projects (or any other CCUS projects) with sufficient volumes of CO2e sequestration to achieve our Scope 1, 2 and 3 emissions goals on the timelines we anticipate. Our CCUS business and all of our CCUS projects are in the early stages of development and while we have reached FID and entered into definitive agreements with respect to the Barnett Zero Project and reached internal FID for the Cotton Cove Project, we have not reached FID or executed any definitive agreements with respect to the other ten potential projects we have identified above and may not be able to reach agreement on terms acceptable to us, or to achieve our projected timeline for commercial operations. 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 enhanced Section 45Q tax credits, the details of which have not yet been released and are to be included in future guidance. For more information about the risks involved in our CCUS business, see “Risk Factors — Risks Related to Our CCUS Business.”
Barnett Zero Project
In June 2022, we reached FID and entered into a definitive agreement in connection with our first high concentration CCUS project in the Barnett with EnLink Midstream, LLC (“EnLink”). This CCUS project, which we refer to as the Barnett Zero Project, will separate CO2 from substantially all of our EnLink-gathered natural gas production. In the Barnett Zero Project, EnLink will transport our natural gas produced in the Barnett to its natural gas processing plant in Bridgeport, Texas, where the CO2 waste stream will be captured, compressed and then sequestered via our nearby injection well. We expect the Barnett Zero Project to achieve an average sequestration rate of up to approximately 185,000 metric tons of CO2e 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.
Cotton Cove Project
On October 18, 2022, BKV dCarbon Ventures reached internal FID to develop our second CCUS project in the Barnett. This CCUS project, which we refer to as the Cotton Cove Project, will separate, dispose of, and geologically sequester CO2 generated as a byproduct of our natural gas production in the Barnett and will utilize our newly acquired BKV Midstream assets to do so. We estimate the Cotton Cove Project will geologically sequester up to approximately 45,000 metric tons of CO2e per year initially, which we expect will increase to an average of up to approximately 82,350 metric tons of CO2e per year by the end of 2024 through ongoing well development in the area. We currently estimate the total investment required by us for the Cotton Cove Project to be between approximately $14.0 and $24.0 million. We intend 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 sequestration 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 identified potential NGP projects under evaluation as described above. As part of the Cotton Cove Project, we also seek to pilot, and then scale, post-combustion carbon capture technology that would allow us to sequester up to an additional approximately 250,000 metric tons per year of captured CO2e from low concentration emissions from within our BKV Midstream operations. As part of this process, we intend to utilize compressor waste heat to reduce energy requirements and cost. We expect this project will offset our current Scope 1 and 2 annual emissions from our owned and operated upstream businesses by approximately 4% by 2025. Although the Barnett Zero Project and the Cotton Cove Project
 
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represent approximately 8% and 4%, respectively, of our estimated Scope 1 and 2 emissions from our owned and operated upstream businesses, the emissions reductions from these two projects combined represent approximately 0.27 Mtpy CO2e, or 45% of our remaining Scope 1 and 2 emissions after taking into account the expected reductions from our “Pad of the Future” program, emissions and leak surveys, and installation of solar power (estimated to be approximately 0.61 Mtpy CO2e), bringing us closer to our goal of reaching net zero Scope 1 and 2 emissions across our owned and operated upstream businesses by the end of 2025. See “— Path to Net Zero Emissions.”
BKVerde
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. As of November 17, 2022, we have paid $8.3 million to Verde CO2 under the development agreement. 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.
Additional Projects
In addition to the Barnett Zero Project and the Cotton Cove Project, we have identified three potential NGP projects that we expect to reach FID by year end 2023. A significant portion of the carbon capture infrastructure and midstream infrastructure necessary to execute these potential NGP projects already exists. Therefore, if approved at FID, and assuming we are able to execute definitive agreements on the terms and timeline we believe are obtainable, we expect these projects to start sequestration operations before December 31, 2025. We expect these three NGP projects to have individual sequestration volumes of approximately 0.29, 0.5 and 0.6 Mtpy CO2e, respectively, and a combined aggregate sequestration volume of approximately 1.39 Mtpy CO2e. The volume of forecast sequestration from these projects, together with approximately 0.27 Mtpy CO2e expected to be sequestered by the Barnett Zero Project and the Cotton Cove Project (all together having a combined forecast sequestration volume of approximately 1.66 Mtpy CO2e), would be capable of offsetting more emissions by December 31, 2025 than our remaining Scope 1 and 2 emissions from our owned and operated upstream businesses (estimated to be approximately 0.61 Mtpy CO2e, after taking into account the expected reductions from our “Pad of the Future” program, emissions and leak surveys, and installation of solar power). See “— Path to Net Zero Emissions.” However, we have not reached FID or entered into definitive agreements for any of these three additional NGP projects and we may not complete all or any of these three additional NGP projects by December 31, 2025, in which case, we may not be able to achieve our goal of net zero Scope 1 and 2 emissions from our owned and operated upstream businesses by the end of 2025.
We are currently evaluating and have begun commercial discussions with respect to seven additional CCUS projects. Three of these seven additional CCUS projects are potential industrial projects that we anticipate will reach FID by the end of 2023. If approved at FID, and assuming definitive agreements are timely executed containing terms we believe are obtainable, we expect to initiate sequestration operations between 2026 and 2029. We expect these three potential industrial CCUS projects to have a combined aggregate sequestration volume of approximately 14.5 Mtpy CO2e. We anticipate that the remaining four potential CCUS projects may reach FID during or after 2024. If approved at FID, and assuming definitive agreements are timely executed containing terms we believe are obtainable, we expect such projects to begin sequestration operations between 2026 and 2029. We expect these four potential CCUS projects to have a combined aggregate sequestration volume of approximately 13.24 Mtpy CO2e. These seven potential CCUS projects have a combined forecasted sequestration volume of approximately 27.74 Mtpy CO2e. We believe that we will be able to complete a sufficient number of these or other CCUS projects in order to meet our Scope 1, 2 and 3 emissions goals by the early 2030s. See “— Path to Net Zero Emissions” for a more detailed description of how we anticipate reaching our Scope 1, 2 and 3 emissions goals.
 
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We estimate the aggregate investment required by us to offset all of our Scope 3 emissions through a sufficient number of the identified potential CCUS projects and associated carbon credits, to be between approximately $1.3 billion and $1.8 billion over the next seven to ten years. We expect to be capable of funding this investment cost through our cash flows from operations, as well as a variety of external sources, at our discretion, 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.
We believe we can achieve our goal of net zero Scope 1, 2 and 3 emissions for our owned and operated upstream businesses by the early 2030s if we are able to complete the minimum number of these identified CCUS projects having a sufficient forecasted volume of carbon capture to offset those emissions on the timeline and upon terms that we believe are obtainable. However, large scale CCUS projects are 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, in which case, we may not be able to achieve our net zero emissions goals on the timelines we have established.
To help us achieve our goal of becoming a leader in CCUS, we established a steering committee that includes two engineers renowned for their work in the development of CCUS projects: Dr. Paitoon (P.T.) Tontiwachwuthikul (Professor of Industrial & Process Systems Engineering & Fellow, Canadian Academy of Engineering) and Dr. Malcolm A. Wilson (Program Director, CO2 Management, Office of Energy & Environment (OEE), Adjunct Professor of Engineering and Graduate Studies). These individuals are professors at the University of Regina, a leading carbon capture research institution, and each has been engaged in CCUS for over 30 years.
For more information on our CCUS business, see “Business — Overview — Our Operations  — Carbon Capture, Utilization and Sequestration,” and “Business — Our Operations — Carbon Capture, Utilization and Sequestration.”
Path to Net Zero Emissions
We estimate that our owned and operated upstream Scope 1 and 2 emissions were approximately 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 pursuant to the Subpart W requirements of the federal Clean Air Act GHG reporting program regulations of the U.S. Environmental Protection Agency (“EPA”) and supplemented with additional inventories that are not required to be reported under 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 submission 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 approximately 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)
 
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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 engage third party consultants to develop, estimate and review our Scope 3 emissions.
The charts below reflect (i) our owned and operated upstream Scope 1 and 2 emissions estimates 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 estimates 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 early 2030s, 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.
[MISSING IMAGE: tm2217921d9-bc_barnett4clr.jpg]
(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 review period versus 12-month period which must have regulatory updates (current proposed OOOO.b,c) to include continuous flyover/satellite technology sensitivities.
(3)
Installation of a 2.5 MW to 5 MW solar farm. We have obtained permits for 2.5 MW and are in the process of obtaining permits for the remaining 2.5 MW.
 
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[MISSING IMAGE: tm2217921d9-bc_nepaprod4clr.jpg]
(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 review period versus 12-month period which must have regulatory updates (current proposed OOOO.b,c) to include continuous flyover/satellite technology sensitivities. Installation of a 2.5 MW to 5 MW solar farm. We have obtained permits for 2.5 MW and are in the process of obtaining permits for the remaining 2.5 MW.
(3)
Scope 3 calculated emissions are based on an estimated net production rate of approximately 900 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.
Planned Path to Net Zero (Scope 1 and 2)
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 approximately $36.9 million. Once this expansion is completed, we expect to eliminate an aggregate of approximately 1.40 Mtpy CO2e, or approximately 64%, of the currently estimated annual Scope 1 and 2 emissions from our owned and operated upstream businesses.
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,
 
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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, as discussed under “— Carbon Capture, Utilization and Sequestration” above, we believe that the Barnett Zero Project and the Cotton Cove Project, together with the three additional NGP projects that we have identified, are capable of offsetting more than the approximately 0.61 Mtpy CO2e of the Scope 1 and 2 emissions from our owned and operated upstream businesses that we currently estimate will remain after taking into account the expected reductions from our “Pad of the Future” program, emissions and leak surveys, and installation of solar power. Although no definitive agreements have been entered into with respect to any of these additional NGP projects, we expect all three to reach FID by year end 2023. A significant portion of the carbon capture infrastructure and midstream infrastructure necessary to execute these potential NGP projects already exists. Therefore, if approved at FID, and assuming we are able to execute definitive agreements on the terms and timeline we believe are obtainable, we expect these projects to start sequestration operations before December 31, 2025. We expect these three NGP projects to have individual sequestration volumes of approximately 0.29, 0.5 and 0.6 Mtpy CO2e, respectively, and a combined aggregate sequestration volume of approximately 1.39 Mtpy CO2e. The volume of forecast sequestration from these projects, together with approximately 0.27 Mtpy CO2e expected to be sequestered by the Barnett Zero Project and the Cotton Cove Project (all together having a combined forecast sequestration volume of approximately 1.66 Mtpy CO2e), would be capable of offsetting more emissions by December 31, 2025 than our remaining Scope 1 and 2 emissions from our owned and operated upstream businesses (estimated to be approximately 0.61 Mtpy CO2e, after taking into account the expected reductions from our “Pad of the Future” program, emissions and leak surveys, and installation of solar power). However, we have not reached FID or entered into definitive agreements for any of these additional potential CCUS projects and have not reached FID with respect to any of them. If we are unable to complete any of these three additional CCUS projects by December 31, 2025, we may not be able to achieve our goal of net zero Scope 1 and 2 emissions from our owned and operated upstream businesses by the end of 2025.
Planned Path to Net Zero (Scope 1, 2 and 3)
We also aspire to offset the Scope 3 emissions impact of our owned and operated upstream businesses by the early 2030s, which we estimate to be approximately 13.9 Mtpy CO2e as of September 30, 2022. As discussed in “— Carbon Capture, Utilization and Sequestration,” above, we have identified twelve potential CCUS projects that we believe are commercially viable, including the Barnett Zero Project, the Cotton Cove Project and the three potential NGP projects, that we estimate have a combined forecasted volume of carbon capture and sequestration of approximately 30 Mtpy CO2e (which is more than our current Scope 1, 2 and 3 emissions from our owned and operated upstream businesses). However, there can be no guarantee that we will be able to execute and complete any of these identified CCUS projects. If we are not able to complete CCUS projects having a sufficient forecast volume of carbon capture to offset our Scope 1, 2 and 3 emissions on the timeline and upon terms that we believe are obtainable, we may not be able to achieve our goal of net zero Scope 1, 2 and 3 emissions from our owned and operated upstream businesses by the early 2030s. Large scale CCUS projects are subject to numerous risks and uncertainties and there can be no guarantee that we will be able to achieve our net zero Scope 1, 2 and 3 emissions goal.
In addition, 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. 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 additional emissions resulting from our continued growth.
Business Strategy
Our strategy is to create value for our stockholders by managing and growing our integrated asset base and focusing on our net zero objectives. Our strategy has the following principal elements:

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.”

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 516 Bcfe of probable reserves and 167 Bcfe of possible reserves, at an average of approximately $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 669 Bcfe of probable reserves and 360 Bcfe of possible reserves. By combining our reserves into a growing asset base with vertically integrated components, we believe we can enhance margins and create a “closed loop” business that reduces Scope 1 and 2 emissions in our owned and operated upstream businesses and captures margin across the value chain. Estimates of probable and possible reserves are inherently imprecise and are more uncertain than proved reserves but have not been adjusted for risk due to that uncertainty, and therefore they may not be comparable with each other and should not be summed either together or with estimates of proved reserves. For more information regarding the presentation of probable and possible reserves, see “Business — Preparation of Reserve Estimates and Internal Controls.”

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 September 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
 
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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.

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 our CCUS projects 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
 
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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 by the early 2030s. 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 at least 1.0 Mtpy CO2e by the end of 2025, which exceeds the balance of our current Scope 1 and 2 emissions from our owned and operated upstream businesses. However, if we are not able to complete CCUS projects having sufficient forecasted volumes of CO2e, we may not be able to achieve this goal.

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 September 30, 2022, we had a Total Net Leverage Ratio of 1.3x. 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 FID to develop our first CCUS project and entered into a definitive 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 sequestration rate of up to approximately 185,000 metric tons of CO2e per year. We currently estimate the total investment required by us for the Barnett Zero Project to be between $20.0 and $22.0 million. We are targeting commencement of CO2 sequestration activities by the second half of 2023, subject to our ability to secure all required permits, at which point we expect this project will be one of the first permanent commercial CO2 disposal and sequestration projects to come online in the United States. We expect this project will 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 Scope 1 and 2 emissions across our owned and operated upstream businesses 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,
 
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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 November 17, 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 was paid on October 31, 2022, and the remaining $40.2 million must be paid by November 30, 2022. We intend to make the remaining payment with cash flows from operations. See “Note 13 — Credit and Other Risk” 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 November 17, 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 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 (as amended by that certain First Amendment to Revolving Credit Agreement dated as of November 11, 2022, 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 November 17, 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.
 
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Cotton Cove CCUS Project
On October 18, 2022, BKV dCarbon Ventures reached internal FID to develop our second CCUS project in the Barnett. This CCUS project, which we refer to as the Cotton Cove Project, will separate, dispose of, and geologically sequester CO2 generated as a byproduct of our natural gas production in the Barnett and will utilize our newly acquired BKV Midstream assets to do so. We estimate the Cotton Cove Project will geologically sequester up to approximately 45,000 metric tons of CO2e per year initially, which we expect will increase to an average of up to approximately 82,350 metric tons of CO2e per year by the end of 2024 through ongoing well development in the area. We currently estimate the total investment required by us for the Cotton Cove Project to be between approximately $14.0 and $24.0 million. We intend 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 sequestration 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 identified potential NGP projects under evaluation as described in “— Carbon Capture, Utilization and Sequestration.” As part of the Cotton Cove Project, we also seek to pilot, and then scale, post-combustion carbon capture technology that would allow us to sequester up to an additional approximately 250,000 metric tons per year of captured CO2e from low concentration emissions from within our BKV Midstream operations. As part of this process, we intend to utilize compressor waste heat to reduce energy requirements and cost. We expect this project will offset our current Scope 1 and 2 annual emissions from our owned and operated upstream businesses by approximately 4% by 2025. Although the Barnett Zero Project and the Cotton Cove Project represent approximately 8% and 4%, respectively, of our estimated Scope 1 and 2 emissions from our owned and operated upstream businesses, the emissions reductions from these two projects combined represent approximately 0.27 Mtpy CO2e, or 45% of our remaining Scope 1 and 2 emissions after taking into account the expected reductions from our “Pad of the Future” program, emissions and leak surveys, and installation of solar power (estimated to be approximately 0.61 Mtpy CO2e), bringing us closer to our goal of reaching net zero Scope 1 and 2 emissions across our owned and operated upstream businesses by the end of 2025. See “— Path to Net Zero Emissions.
Letter of Intent with EEMNA
On November 11, 2022, we entered into a non-binding letter of intent with ENGIE Energy Marking NA, Inc (“EEMNA”) to build a framework for verifiable environmental attributes with the use of carbon credits applied to natural gas energy. Under this framework, we intend to measure, reduce and verify emissions using operational technologies, such as continuous emissions monitoring. In addition, we expect to deliver sequestered carbon credits from our CCUS business to EEMNA under this marketing program. Project Canary, an environmental certification and ESG data company, will reconcile sensing technologies and measure, analyze, and report the environmental attributes of the sequestrated carbon to support decarbonization. This initiative strives to provide a market in which an LNG buyer, gas utility, power utility or other end-user can purchase measured and verified sequestrated carbon credits from a single, trusted company. These carbon credits would not apply toward a reduction of our own Scope 1, 2 or 3 owned and operated upstream emissions. We anticipate eventually selling to EEMNA, for marketing to end-users, net zero natural gas that incorporates measured, sequestrated carbon credits derived from our CCUS business.
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
 
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Thailand. With nearly four decades of experience in business operations covering 10 countries across the Pacific Rim region and the United States, Banpu is an international versatile energy provider committed to its Greener & Smarter strategy, which prioritizes environmentally sustainable businesses and leverages smart technologies and innovations. Upon completion of this offering, Banpu will beneficially own approximately    % of our common stock (or approximately    % if the underwriters exercise in full their option to purchase additional shares of our common stock). Banpu has informed us that although it may reduce a portion of its ownership position over time, it intends to remain a long-term stockholder and supporter of BKV. If, after this initial public offering, Banpu and its wholly owned subsidiaries cease to own at least 51% of our equity interests, or if they allow any lien to exist on our equity interests that they own, such event will be an event of default under the Term Loan Credit Agreement and the Revolving Credit Agreement. See “Risk Factors — Risks Related to Our Relationship with Banpu and its Affiliates.”
 
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Our Structure
The chart below displays a summary of our ownership structure after giving effect to this offering.
[MISSING IMAGE: tm2217921d6-fc_ourstru4c.jpg]
(1)
Consists of management, directors and other employee and non-employee stockholders.
The information in the chart above does not include 10,000,000 additional shares of our common stock reserved for future awards pursuant to the BKV Corporation 2022 Equity and Incentive Compensation
 
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Plan (the “2022 Plan”), including        shares of common stock that may be issued upon vesting of equity awards that we expect to be granted in connection with this offering, and 1,000,000 shares of our common stock available for purchase by employees pursuant to the BKV Corporation Employee Stock Purchase Plan (the “ESPP”).
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.
We will remain an emerging growth company under the JOBS Act until December 31, 2022. While we continue to be an emerging growth company until the end of the 2022 fiscal year, we expect our revenues will exceed $1.235 billion during the year ending December 31, 2022 and we will no longer qualify as an emerging growth company as of December 31, 2022.
Controlled Company
We intend to apply to list our common stock on the NYSE under the symbol “BKV.” Upon completion of this offering, BNAC will hold approximately    % of our total outstanding shares of common stock (or approximately    % if the underwriters exercise in full their option to purchase additional shares),
 
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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;

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.
 
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The Offering
Issuer
BKV Corporation, a Delaware corporation
Securities offered
Common stock, par value $0.01 per share (“common stock”)
Common stock offered by us
       shares (or        shares if the underwriters exercise in full their option to purchase additional shares)
Underwriters’ option to purchase additional shares
The underwriters have an option for a period of 30 days to purchase up to an additional        shares of our common stock.
Common stock outstanding immediately after this offering
       shares (or        shares if the underwriters exercise in full their option to purchase additional shares)
Use of proceeds
We estimate that the net proceeds to us from the sale of our common stock in this offering, after deducting underwriting discounts and commissions and estimated offering expenses payable by us, will be approximately $      million (or approximately $      million if the underwriters exercise in full their option to purchase additional shares), based on an assumed initial public offering price of $      per share (the midpoint of the price range set forth on the cover page of this prospectus).
Of the net proceeds we receive from the sale of our common stock in this offering, we intend to use approximately $       million to repay in full the loan under the $75 Million A&R Loan Agreement (as defined herein) with BNAC, $       million to make additional contingent consideration payments payable in connection with the Devon Barnett Acquisition and the remainder for other general corporate purposes, including to fund the expansion of our CCUS business. 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
 
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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 10,000,000 additional shares of our common stock reserved for future awards pursuant to our 2022 Plan and 1,000,000 shares of our common stock available for purchase by employees pursuant to the our ESPP, which will become effective upon the completion of this offering.
Unless otherwise indicated and except for our historical consolidated financial statements and related notes included elsewhere in this prospectus, the information in this prospectus:

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

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:
 
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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;
 
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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.
 
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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 nine months ended September 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 nine months ended September 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 September 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.
Nine Months
Ended September 30,
Year Ended December 31,
Pro Forma
Nine Months
Ended
September 30,
2022
Pro Forma
Year Ended
December 31,
2021
2022
2021
2021
2020
(in thousands, except per share amounts)
Revenues and other operating income
Natural gas sales
$ 969,525 $ 359,716 $ 597,050 $ 101,758 * *
NGL sales
247,404 151,165 225,135 11,952 * *
Oil sales
7,544 5,491 7,560 1,333 * *
Natural gas, NGL and oil sales
1,224,473 516,372 829,745 115,043 1,443,705 1,137,725
Midstream revenues
6,080 5,529 6,917 7,458 9,701 13,161
Derivative gains (losses), net
(720,312) (500,604) (383,847) 20,755 (720,312) (383,847)
Marketing revenues
7,197 51,246 52,616 7,197 52,616
Other
2,008 251 33 2,256 518
Total revenues and other operating income
519,446 72,543 505,682 143,289 742,547 820,173
 
25

 
Nine Months
Ended September 30,
Year Ended
December 31,
Pro Forma
Nine Months
Ended
September 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
86,870 64,244 88,105 31,260 145,046 185,853
Taxes other than income
86,164 28,453 45,650 5,151 96,860 67,317
Gathering and transportation
153,281 124,287 173,587 178,602 223,382
Accretion of asset retirement obligations
8,874 7,439 10,030 3,211 10,647 13,616
Depreciation, depletion, and amortization
68,606 61,219 81,986 83,388 93,248 141,718
Exploration and impairment
34 34 560 34
General and administrative
107,341 62,653 85,740 29,442 102,241 91,860
Accretion of right of use liabilities(1)
190 167 227 184 190 227
Total operating expenses
511,326 348,496 485,359 153,196 626,834 724,007
Income (loss) from operations
8,120 (275,953) 20,323 (9,907) 115,713 96,166
Other income and expense
Loss on contingent consideration liabilities(2)
(31,089) (193,350) (194,968) 7,135 (31,089) (194,968)
Interest expense
(22,334) (314) (2,134) (1,713) (44,225) (51,018)
Other income
1,051 628 872 1,051 872
Bargain purchase gain
163,653 163,653
Gain on settlement of litigation
16,866 16,866
Income (loss) from equity affiliates
14,486 910 14,486 910
Interest income
382 2 8 121 382 8
Income (loss) before income taxes
151,135 (468,987) (174,989) (4,364) 236,837 (148,030)
Income tax benefit (expense)
2,989 107,918 40,526 (38,982) (16,722) 34,325
Net income (loss) and comprehensive income (loss) attributable to BKV Corporation
154,124 (361,069) (134,463) (43,346) 220,115 (113,705)
Less accretion of preferred stock to redemption value
(3,545) (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
154,124 (375,867) (170,714) (43,806) 220,115 (149,956)
Net income (loss) and comprehensive income (loss)
per common share
Basic
$ 1.31 $ (3.21) $ (1.46) $ (0.42) $ 1.88 $ (1.28)
Diluted
$ 1.24 $ (3.21) $ (1.46) $ (0.42) $ 1.77 $ (1.28)
Weighted average number of common shares outstanding
Basic
117,316 117,027 116,904 105,275 117,316 116,904
Diluted
124,597 117,027 116,904 105,275 124,597 116,904
Balance Sheet Information (at period end):
Restricted Cash(3)
$ 17,473 $ $ $ ** **
Cash & cash equivalents
$ 167,143 $ 86,245 $ 134,667 $ 17,445 ** **
Total natural gas properties, net
$ 2,203,766 $ 1,149,303 $ 1,176,117 $ 1,169,297 ** **
Total assets
$ 2,748,365 $ 1,585,858 $ 1,620,828 $ 1,342,492 ** **
Total liabilities
$ 1,811,085 $ 973,679 $ 865,889 $ 262,424 ** **
Total mezzanine equity
$ 159,230 $ 137,992 $ 83,847 $ 137,212 ** **
Total stockholders’ equity
$ 778,050 $ 474,187 $ 671,092 $ 942,856 ** **
 
26

 
Nine Months
Ended September 30,
Year Ended
December 31,
Pro Forma
Nine Months
Ended
September 30,
2022
Pro Forma
Year Ended
December 31,
2021
2022
2021
2021
2020
(in thousands, except per share amounts)
Statement of Cash Flows Information
Net cash provided by (used in) operating activities
$ 231,075 $ 274,488 $ 358,133 $ (7,405) ** **
Net cash used in investing activities
$ (756,333) $ (74,868) $ (161,858) $ (513,992) ** **
Net cash (used in) provided by financing activities
$ 575,206 $ (130,820) $ (79,053) $ 442,723 ** **
Other Financial Data (unaudited)(4)
Adjusted EBITDAX
$ 332,514 $ 237,417 $ 281,024 $ 65,148 $ 425,007 $ 413,698
Upstream Reinvestment Rate
38% 10% 24% 16% ** **
Adjusted Free Cash Flow
$ 142,970 $ 89,108 $ 165,090 $ 56,604 ** **
Adjusted Free Cash Flow Margin
12% 16% 19% 34% ** **
Total Net Leverage Ratio(5)
1.3x 0x 0.11x 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 September 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 nine months ended September 30, 2022 and for the pro forma nine months ended September 30, 2022, Adjusted EBITDAX has been annualized to $443.4 million and $566.7 million, respectively.
*
Revenues with respect to the 2022 Barnett Assets (as defined herein) for the nine months ended September 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 September 30, 2022, and no pro forma balance sheet is presented. See “Unaudited Pro Forma Combined Consolidated Financial Statements.”
 
27

 
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, 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.
Nine Months Ended September 30,
Year Ended December 31,
Pro Forma
Nine Months
Ended
September 30,
2022
(in thousands)
Pro Forma
Year Ended
December 31,
2021
(in thousands)
2022
2021
2021
2020
(in thousands)
(in thousands)
Net income (loss)
$ 154,124 $ (361,069) $ (134,463) $ (43,346) $ 220,115 $ (113,705)
Unrealized derivative loss
(gain)
158,734 377,035 115,161 (10,329) 158,734 115,161
Forward month gas
derivative settlement(1)
32,010 39,636 15,406 (5,489) 32,010 15,406
Accretion of asset retirement obligation
8,874 7,439 10,030 3,211 10,647 13,616
Accretion of right of use
liabilities
480 249 330 336 480 330
Depreciation, depletion, and amortization
76,677 65,509 88,473 86,644 93,248 141,718
Exploration and impairment expense
34 34 560 34
Change in contingent
consideration liabilities
31,089 193,350 194,968 (7,135) 31,089 194,968
Interest expense
22,334 314 2,134 1,713 44,225 51,018
Income tax (benefit) expense
(2,989) (107,918) (40,526) 38,982 (16,722) (34,325)
 
28

 
Nine Months Ended September 30,
Year Ended December 31,
Pro Forma
Nine Months
Ended
September 30,
2022
(in thousands)
Pro Forma
Year Ended
December 31,
2021
(in thousands)
2022
2021
2021
2020
(in thousands)
(in thousands)
Equity-based
compensation expense
29,320 22,838 30,387 29,320 30,387
Bargain purchase gain
(163,653) (163,653)
Loss (income) from equity affiliates
(14,486) (910) (14,486) (910)
Adjusted EBITDAX
$ 332,514 $ 237,417 $ 281,024 $ 65,148 $ 425,007 $ 413,698
(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.
Nine Months Ended
September 30,
Year Ended
December 31,
2022
2021
2021
2020
(in thousands)
Net cash provided by (used in) operating activities
$ 231,076 $ 274,488 $ 358,133 $ (7,405)
Changes in operating assets and liabilities
(8,381) (162,671) (126,862) 74,536
Cash paid for capital expenditures and settlement of contingent considerations (excluding leasehold costs and acquisitions)
(79,726) (22,709) (66,181) (10,527)
Adjusted Free Cash Flow
$ 142,970 $ 89,108 $ 165,090 $ 56,604
 
29

 
Summary Reserve, Production and Operating Data
Ryder Scott, our independent petroleum engineers, prepared estimates of our natural gas, NGL and oil 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”) (except for the table that provides our estimated reserves as of September 30, 2022 at “NYMEX strip pricing” using pricing based on NYMEX future prices as of market close on September 30, 2022). For more information about our reserve volumes and values, 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 estimated proved reserve, probable reserve and possible 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 natural gas, NGL and oil reserves and their values, including many factors beyond our control. In addition, estimates of probable and possible reserves are inherently imprecise and are more uncertain than proved reserves but have not been adjusted for risk due to that uncertainty, and therefore they may not be comparable with each other and should not be summed either together or with estimates of proved reserves. See “Risk Factors — Risks Related to Our Upstream Business and Industry — Our estimated natural gas, NGL and oil 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 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
Standardized Measure (millions)
$ 6,150 $ 2,119 $ 504
PV-10 (millions)(2)(3)
$ 7,844 $ 2,672 $ 552
Estimated proved undeveloped reserves:
Natural gas (MMcf)
1,140,466 950,359 92,373
 
30

 
September 30,
2022
December 31,
2021
2020
Natural gas liquids (MBbls)
42,896 13,722
Oil (MBbls)
620 58
Total estimated proved undeveloped reserves (MMcfe)(4)(5)
1,401,561 1,033,040 92,373
Standardized Measure (millions)
$ 1,498 $ 294 $ 6
PV-10 (millions)(2)(6)
$ 1,974 $ 403 $ 9
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)(7)
$ 9,818 $ 3,074 $ 561
Estimated probable reserves:
Natural gas (MMcf)
940,531 522,442 61,884
Natural gas liquids (MBbls)
67,117 31,227
Oil (MBbls)
1,625 486
Total estimated probable reserves (MMcfe)(5)(8)
1,352,989 712,725 61,884
Standardized Measure (millions)
$ 851 $ 146 $
PV-10 (millions)(2)(9)
$ 1,126 $ 202 $
Estimated possible reserves:
Natural gas (MMcf)
552,597 381,941
Natural gas liquids (MBbls)
35,121 32,047
Oil (MBbls)
1,364 1,841
Total estimated possible reserves (MMcfe)(5)(8)
771,478 585,269
Standardized Measure (millions)
$ 324 $ 51 $
PV-10 (millions)(2)(10)
$ 432 $ 75 $
(1)
Prices for natural gas, oil and NGLs, respectively, used in preparing our estimated proved reserves and the associated PV-10 Value based on SEC Pricing (i) at 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)
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
 
31

 
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.
(3)
The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated proved developed reserves as of September 30, 2022 and December 31, 2021 and 2020:
September 30,
2022
December 31,
2021
2020
PV-10 (millions)
$ 7,844 $ 2,672 $ 552
Present value of future income taxes discounted at 10%
(1,694) (553) (48)
Standardized Measure
$ 6,150 $ 2,119 $ 504
(4)
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.
(5)
Sustained lower prices for oil and natural gas may cause us to forecast less capital to be available for development of our PUD, probable and possible reserves, which may cause us to decrease the amount of our PUD, probable and possible reserves we expect to develop within the allowed time frame. In addition, lower oil and natural gas prices may cause our PUD, probable and possible reserves to become uneconomic to develop, which would cause us to remove them from their respective reserve category.
(6)
The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated proved undeveloped reserves as of September 30, 2022 and December 31, 2021 and 2020:
September 30,
2022
December 31,
2021
2020
PV-10 (millions)
$ 1,974 $ 403 $ 9
Present value of future income taxes discounted at 10%
(476) (108) (3)
Standardized Measure
$ 1,498 $ 294 $ 6
(7)
The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated proved reserves 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
(8)
Estimates of probable and possible reserves, respectively, and the respective future cash flows related to such estimates, are inherently imprecise and are more uncertain than proved reserves, and the future cash flows related to such estimates. For more information regarding the presentation of probable and possible reserves, see “Business — Preparation of Reserve Estimates and Internal Controls.”
(9)
The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated probable reserves as of September 30, 2022 and December 31, 2021 and 2020:
September 30,
2022
December 31,
2021
2020
PV-10 (millions)
$ 1,126 $ 202 $    —
Present value of future income taxes discounted at 10%
(275) (56)
Standardized Measure
$ 851 $ 146 $
 
32

 
(10)
The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated possible reserves as of September 30, 2022 and December 31, 2021 and 2020:
September 30,
2022
December 31,
2021
2020
PV-10 (millions)
$ 432 $ 75 $    —
Present value of future income taxes discounted at 10%
(108) (24)
Standardized Measure
$ 324 $ 51 $
During the nine months ended September 30, 2022 and the year ended December 31, 2021, we incurred costs of approximately $26.0 million and $7.2 million, respectively, to convert 41.4 Bcfe and 19.4 Bcfe, respectively, of proved undeveloped reserves to proved developed reserves. Estimated future development costs relating to the development of our proved undeveloped reserves at September 30, 2022 and December 31, 2021 are approximately $963.2 million and $578.3 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 to proved developed reserves offset by a downward revision of 79.4 Bcfe to proved developed reserves due to increased production costs.
Extensions and discoveries increased as a result of the completion of our 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 developed 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 of proved undeveloped reserves primarily consisted of a downward revision to proved undeveloped reserves of 146.7 Bcfe due to a combination of performance adjustments and lower average pricing of natural gas during 2020, and a downward revision of 186.5 Bcfe which removed locations due to lower average pricing of natural gas during 2020. Proved developed reserves were adjusted downward by 48.8 Bcfe due to lower average natural gas prices and performance.
 
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There were no extensions and discoveries of proved developed or proved undeveloped reserves during the year ended December 31, 2020.
Estimated Reserves at NYMEX Strip Pricing
The following table provides our total estimated proved reserve, probable reserve and possible reserve information prepared by Ryder Scott as of September 30, 2022, using NYMEX strip prices as of market close on September 30, 2022 and PV-10 Value and the Standardized Measure for such period. We have included this information in order to provide an additional method of presentation of the fair value of our assets and the cash flows that we expect to generate from those assets based on the market’s forward-looking pricing expectations as of September 30, 2022. The historical 12-month pricing average in our September 30, 2022 disclosures above does not reflect the prevailing natural gas and oil futures. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of natural gas and oil prices as of a certain date, although we caution investors that this information should be viewed as a helpful alternative, not a substitute, for the data presented based on SEC Pricing. In addition, we believe that NYMEX strip pricing provides relevant and useful information because it is widely used by investors in our industry as a basis for comparing the relative size and value of our reserves to our peers. Our estimated reserves based on NYMEX futures were otherwise prepared on the same basis as our SEC reserves for the comparable period. Actual future prices may vary significantly from the NYMEX strip prices on September 30, 2022. Actual revenue and value generated may be more or less than the amounts disclosed. There are numerous uncertainties inherent in estimating quantities of natural gas, NGL and oil reserves and their values, including many factors beyond our control. In addition, estimates of probable and possible reserves are inherently imprecise and are more uncertain than proved reserves but have not been adjusted for risk due to that uncertainty, and therefore they may not be comparable with each other and should not be summed either together or with estimates of proved reserves. See “Risk Factors — Risks Related to Our Upstream Business and Industry — Our estimated natural gas, NGL and oil 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.”
September 30,
2022
Estimated proved developed reserves at NYMEX Strip Pricing:
Natural gas (MMcf)
3,664,049
Producing
3,275,209
Non-producing
388,839
Natural gas liquids (MBbls)
167,260
Producing
153,398
Non-producing
13,862
Oil (MBbls)
1,059
Producing
955
Non-producing
104
Total estimated proved developed reserves (MMcfe)
4,673,960
Producing
4,201,327
Non-producing
472,633
Standardized Measure (millions)
3,846
PV-10 (millions)(1)
4,847
Estimated proved undeveloped reserves at NYMEX Strip Pricing:
Natural gas (MMcf)
1,139,781
Natural gas liquids (MBbls)
42,895
Oil (MBbls)
620
 
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September 30,
2022
Total estimated proved undeveloped reserves (MMcfe)(2)(3)
1,400,871
Standardized Measure (millions)
717
PV-10 (millions)(4)
960
Estimated proved reserves at NYMEX Strip Pricing:
Natural gas (MMcf)
4,803,830
Natural gas liquids (MBbls)
210,155
Oil (MBbls)
1,679
Total estimated proved reserves (MMcfe)
1,790,770
Standardized Measure (millions)
$ 4,563
PV-10 (millions)(5)
$ 5,807
Estimated probable reserves at NYMEX Strip Pricing:
Natural gas (MMcf)
923,286
Natural gas liquids (MBbls)
210,155
Oil (MBbls)
1,605
Total estimated probable reserves (MMcfe)(3)(6)
1,332,901
Standardized Measure (millions)
$ 373
PV-10 (millions)(7)
$ 423
Estimated possible reserves at NYMEX Strip Pricing:
Natural gas (MMcf)
521,542
Natural gas liquids (MBbls)
30,699
Oil (MBbls)
1,128
Total estimated possible reserves (MMcfe)(3)(6)
712,508
Standardized Measure (millions)
$ 99
PV-10 (millions)(8)
$ 139
(1)
The following table provides a reconciliation of the Standardized Measure to PV-10 (applying NYMEX Strip Pricing) with respect to estimated proved developed reserves as of September 30, 2022:
September 30,
2022
PV-10 (millions)
$ 4,847
Present value of future income taxes discounted at 10%
(1,001)
Standardized Measure
$ 3,846
(2)
Proved undeveloped reserves 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)
Sustained lower prices for oil and natural gas may cause us to forecast less capital to be available for development of our PUD, probable and possible reserves, which may cause us to decrease the amount of our PUD, probable and possible reserves we expect to develop within the allowed time frame. In addition, lower oil and natural gas prices may cause our PUD, probable and possible reserves to become uneconomic to develop, which would cause us to remove them from their respective reserve category.
(4)
The following table provides a reconciliation of the Standardized Measure to PV-10 (applying NYMEX Strip Pricing) with respect to estimated proved undeveloped reserves as of September 30, 2022:
 
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September 30,
2022
PV-10 (millions)
$ 960
Present value of future income taxes discounted at 10%
(243)
Standardized Measure
$ 717
(5)
The following table provides a reconciliation of the Standardized Measure to PV-10 (applying NYMEX Strip Pricing) with respect to estimated proved reserves as of September 30, 2022:
September 30,
2022
PV-10 (millions)
$ 5,807
Present value of future income taxes discounted at 10%
(1,244)
Standardized Measure
$ 4,563
(6)
Estimates of probable and possible reserves, respectively, and the respective future cash flows related to such estimates, are inherently imprecise and are more uncertain than proved reserves, and the future cash flows related to such estimates. For more information regarding the presentation of probable and possible reserves, see “Business — Preparation of Reserve Estimates and Internal Controls.
(7)
The following table provides a reconciliation of the Standardized Measure to PV-10 (applying NYMEX Strip Pricing) with respect to estimated probable reserves as of September 30, 2022:
September 30,
2022
PV-10 (millions)
$ 423
Present value of future income taxes discounted at 10%
(50)
Standardized Measure
$ 373
(8)
The following table provides a reconciliation of the Standardized Measure to PV-10 (applying NYMEX Strip Pricing) with respect to estimated possible reserves as of September 30, 2022:
September 30,
2022
PV-10 (millions)
$ 139
Present value of future income taxes discounted at 10%
(40)
Standardized Measure
$ 99
 
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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:

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

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

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;

the level of global drilling, exploration and production;

the level of global inventories;

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

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;

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

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;

local and global supply and demand fundamentals and transportation availability;

United States storage levels of natural gas and NGLs;

weather conditions and other natural disasters;

domestic and foreign governmental regulations, including environmental initiatives and taxation;
 
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overall domestic and global economic conditions;

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

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;

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

speculative trading in natural gas and NGL derivative contracts;

technological advances affecting energy consumption and energy supply;

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

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 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 reserves at SEC
 
38

 
Pricing 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 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.
In addition, estimates of probable reserves, and the future cash flows related to such estimates, are inherently imprecise and are more uncertain than estimates of proved reserves, and the future cash flows related to such estimates, but have not been adjusted for risk due to that uncertainty. Because of such uncertainty, estimates of probable reserves, and the future cash flows related to such estimates, may not be comparable to estimates of proved and possible reserves, respectively, and the respective future cash flows related to such estimates, and should not be summed arithmetically with estimates of either proved or possible reserves, respectively, and the respective future cash flows related to such estimates. When producing an estimate of the amount of natural gas, NGLs and oil that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of 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. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. 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. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
Estimates of possible reserves, and the future cash flows related to such estimates, are also inherently imprecise and are more uncertain than estimates of proved and probable reserves, respectively, and the respective future cash flows related to such estimates, but have not been adjusted for risk due to that uncertainty. Because of such uncertainty, estimates of possible reserves, and the future cash flows related to such estimates, may not be comparable to estimates of proved and probable reserves, respectively, and the respective future cash flows related to such estimates, and should not be summed arithmetically with estimates of either proved or probable reserves, respectively, and the respective future cash flows related to such estimates. When producing an estimate of the amount of natural gas, NGLs and oil that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price
 
39

 
changes and other factors. 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. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserve 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. Possible reserves also include incremental quantities associated with a greater percentage of recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves. 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 we believe 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.
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:

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

actual cost of development and production expenditures;

the amount and timing of actual production;

transportation and processing; and

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 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
 
40

 
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 September 30, 2022, we carried unproved natural gas, NGL and oil property costs of $17.1 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 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
 
41

 
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 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
 
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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:

unexpected drilling conditions;

title problems;

pressure or irregularities in formations;

equipment failures or accidents;

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

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 re