S-1/A: General form of registration statement for all companies including face-amount certificate companies
Published on September 9, 2024
As filed with the Securities and Exchange Commission on September 9, 2024
Registration No. 333-268469
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
AMENDMENT NO. 13
TO
TO
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
UNDER
THE SECURITIES ACT OF 1933
BKV CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware
(State or other jurisdiction of incorporation or organization) |
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1311
(Primary Standard Industrial Classification Code Number) |
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85-0886382
(I.R.S. Employer Identification Number) |
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1200 17th Street, Suite 2100
Denver, Colorado 80202
(720) 375-9680
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
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:
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Samantha H. Crispin
M. Preston Bernhisel Adorys Velazquez Baker Botts L.L.P. 2001 Ross Avenue, Suite 900 Dallas, Texas 75201 (214) 953-6500 |
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Michael Chambers
Monica E. White Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, Texas 77002 (713) 546-5400 |
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Approximate date of commencement of proposed sale to the public:
As soon as practicable after the effective date of this registration statement.
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.
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Large accelerated filer
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Accelerated filer
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Non-accelerated filer
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Smaller reporting company
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Emerging growth company
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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.
TABLE OF CONTENTS
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Dealer Prospectus Delivery Obligation
Through and including , 2024 (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.”
Reverse Stock Split
On October 30, 2023, we completed a one-for-two reverse stock split. As a result of the reverse stock split, every two shares of our outstanding common stock were combined into and now represent one share of common stock, and fractional shares were paid out in cash. All shares of common stock issuable upon exercise of equity awards, as well as the applicable exercisable prices and weighted average fair value of the equity awards, and per share amounts contained throughout this prospectus have been retroactively adjusted.
Presentation of Financial, Reserves and Operating Data
Unless indicated otherwise, the historical financial information presented in this prospectus is that of BKV Corporation and its consolidated subsidiaries as of December 31, 2023 or June 30, 2024, as applicable. The historical natural gas, NGL and oil reserves data presented in this prospectus as of December 31, 2023, 2022 and 2021 are based on the reserves reports prepared by Ryder Scott Company, L.P., independent petroleum engineers.
In addition, unless indicated otherwise, the operational data presented in this prospectus is that of BKV Corporation and its consolidated subsidiaries on a consolidated basis as of and for the periods presented.
As a result of our acquisition transactions in recent years, our historical operating, financial and reserves data may not be comparable between periods presented in this prospectus. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors that Affect Comparability of Our Results of Operations.”
Trademarks and Trade Names
We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, ™ or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the rights of the applicable licensor to these trademarks, service marks and trade names.
Rounding and Percentages
The financial information and certain other information presented in this prospectus have been rounded to the nearest whole number or the nearest decimal. Therefore, the sum of the numbers in a column may not conform exactly to the total figure given for that column in certain tables in this prospectus. In addition, certain percentages presented in this prospectus reflect calculations based upon the underlying information prior to rounding and, accordingly, may not conform exactly to the percentages that would be derived if the relevant calculations were based upon the rounded numbers or may not sum due to rounding.
Other Considerations
This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” for additional information regarding these risks.
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You should read this prospectus and any written communication prepared by us or on our behalf in connection with this offering, together with the additional information described in the section of this prospectus titled “Where You Can Find More Information.” We have not authorized anyone to provide you with information or to make any representation in connection with this offering other than those contained herein. If anyone makes any recommendation or gives any information or representation regarding this offering, you should not rely on that recommendation, information or representation as having been authorized by us, the underwriters or any other person on our behalf. The information contained in this prospectus is accurate only as of the date of which it is shown, or if no date is otherwise indicated, the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our shares of common stock. We are offering to sell, and seeking offers to buy, shares of common stock only in jurisdictions where offers and sales are permitted. Our business, financial condition, results of operations and prospects may have changed since that date. Information contained on our website is not part of this prospectus.
No action is being taken in any jurisdiction outside the United States to permit a public offering of shares of common stock or possession or distribution of this prospectus in that jurisdiction. Persons who come into possession of this prospectus in jurisdictions outside the United States are required to inform themselves about and to observe any restrictions as to this offering and the distribution of this prospectus applicable to that jurisdiction.
Glossary of Oil and Natural Gas Terms
The following are abbreviations and definitions of certain terms used in this prospectus, which are commonly used in the oil and natural gas industry:
“Bbl” refers to one stock tank barrel, of 42 U.S. gallons liquid volume, used in this prospectus in reference to crude oil or other liquid hydrocarbons.
“Bcf” refers to one billion cubic feet of natural gas or CO2.
“Bcfe” refers to one billion cubic feet of natural gas equivalent.
“Btu” refers to British thermal unit, which is the heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit.
“CCUS” refers to carbon capture, utilization and sequestration.
“CO2” refers to carbon dioxide.
“CO2e” refers to carbon dioxide equivalent.
“developed acreage” refers to the number of acres that are allocated or assignable to productive wells or wells capable of production.
“developed reserves” are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
“dry hole” refers to a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“Effective NRI” refers to our share of leasehold ownership after all burdens, such as royalty and overriding royalty interests, have been deducted from the working interest, weighted by our net acres owned in the Barnett from the assets acquired in the Devon Barnett Acquisition and the Exxon Barnett Acquisition.
“gross acres,” “gross acreage” or “gross wells” refers to the total acres, acreage or wells, as the case may be, in which a working interest is owned.
“IPIECA” refers to the International Petroleum Industry Environmental Conservation Association.
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“lean gas” refers to natural gas that contains a few or no liquefiable liquid hydrocarbons.
“LNG” refers to liquefied natural gas.
“Maintenance Reinvestment Rate” for any period refers to the maximum rate of our total capital expenditures accrued for the development of natural gas properties (excluding leasehold costs and acquisitions) for such period as a percentage of Adjusted EBITDAX for the same period that is necessary to hold our production for such period flat.
“MBbls” refers to one thousand barrels of crude oil or other liquid hydrocarbons.
“Mcf” refers to one thousand cubic feet.
“Mcf/d” refers to one thousand cubic feet per day.
“Mcfe” refers to one thousand cubic feet of natural gas equivalent.
“MMBtu” refers to one million Btus.
“MMcf” refers to one million cubic feet.
“MMcf/d” refers to one million cubic feet per day.
“MMcfe” refers to one million cubic feet of natural gas equivalent, calculated by converting barrels of crude oil or other liquid hydrocarbons to natural gas at a ratio of one Bbl to six Mcf of natural gas. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
“MMcfe/d” refers to one million cubic feet of natural gas equivalent per day.
“Mtpa” refers to million metric tons of LNG per year.
“Mtpy” refers to million metric tons per year.
“net acres” refers to the percentage of total acres an owner has out of a particular number of acres, or a specified tract. For example, an owner who has 50% interest in 100 acres owns 50 net acres.
“net operated development well” refers to a gross operated development well that has been drilled, proportionately reduced by our working interest in such well.
“NGL” refers to natural gas liquids.
“NYMEX” refers to the New York Mercantile Exchange.
“OPEC” refers to the Organization of the Petroleum Exporting Countries.
“proved developed non-producing reserves” refers to proved developed reserves expected to be recovered from (i) completion intervals that are open at the time of the estimate but which have not yet started producing, (ii) wells which were shut-in for market conditions or pipeline connections, (iii) wells not capable of production for mechanical reasons or (iv) zones in existing wells that will require additional completion work or future re‑completion before start of production with minor cost to access these reserves, in each case, which production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. While not a requirement for disclosure under SEC regulations, proved developed non-producing reserves have been sub-classified and calculated by Ryder Scott in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
“proved developed producing reserves” or “PDP reserves” refers to quantities of proved developed reserves expected to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. While not a requirement for disclosure under SEC regulations, PDP reserves have been sub-classified and calculated by Ryder Scott in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
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“proved reserves” refers to quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined an HKO elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (a) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (b) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
“PUD reserves” refers to proved undeveloped reserves.
“rich gas” refers to natural gas containing heavier hydrocarbons than a lean gas.
“Scope 1 emissions” refers to direct GHG emissions that occur from sources that are controlled or owned by an organization.
“Scope 2 emissions” refers to indirect GHG emissions associated with the purchase of electricity, steam, heat or cooling.
“Scope 3 emissions” refers to GHG emissions that result from the end use of an organization’s products, as estimated per Category 11 (Use of Sold Product), as well as emissions from other business activities from assets not owned or controlled by the organization but that the organization indirectly impacts in its value chain.
“Tcfe” refers to one trillion cubic feet of natural gas equivalent.
“undeveloped acreage” refers to acreage under lease on which wells have not been drilled or completed such that there is not production of commercial quantities of hydrocarbons.
“undeveloped reserves” are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
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“Upstream Reinvestment Rate” for any period refers to our total capital expenditures accrued for the development of natural gas properties (excluding leasehold costs and acquisitions) for such period as a percentage of Adjusted EBITDAX for the same period.
“working interest” refers to the right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
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Commonly Used Defined Terms
As used in this prospectus, unless the context indicates or otherwise requires, the terms listed below have the following meanings:
“Banpu” refers to our sponsor, Banpu Public Company Limited, a public company listed on the Stock Exchange of Thailand and the ultimate parent company of BKV Corporation, BNAC, Banpu Power and BPPUS.
“Banpu Power” refers to Banpu Power Public Company Limited, a public company listed on the Stock Exchange of Thailand. Banpu owns approximately 78.66% of Banpu Power as of June 30, 2024.
“Barnett” refers to the Barnett Shale in the Fort Worth Basin of Texas.
“BKV Barnett” refers to BKV Barnett LLC, a Delaware limited liability company and wholly owned subsidiary of BKV Corporation.
“BKV Chaffee” refers to BKV Chaffee Corners, LLC, a Delaware limited liability company and former wholly owned subsidiary of BKV Corporation.
“BKV Chelsea” refers to BKV Chelsea, LLC, a Delaware limited liability company and wholly owned subsidiary of BKV Corporation.
“BKV dCarbon Ventures” refers to BKV dCarbon Ventures, LLC, a Delaware limited liability company and the CCUS business of BKV Corporation.
“BKV Midstream” refers to BKV Midstream, LLC, a Delaware limited liability company and wholly owned subsidiary of BKV Corporation.
“BKV O&G” refers to BKV Oil and Gas Capital Partners, L.P., a Delaware limited partnership and wholly owned subsidiary of BKV Corporation, which was dissolved on September 19, 2022, on which date all ownership interests in subsidiaries of BKV O&G were assigned to BKV Corporation.
“BKV Operating” refers to BKV Operating, LLC, a Delaware limited liability company and wholly owned subsidiary of BKV Corporation.
“BKV Upstream Midstream” refers to BKV Upstream Midstream, LLC, a Delaware limited liability company and wholly owned subsidiary of BKV Corporation.
“BKV-BPP Cotton Cove” or “BKV-BPP Cotton Cove Joint Venture” refers to BKV-BPP Cotton Cove, LLC, a Delaware limited liability company and the joint venture between BKV dCarbon Ventures and BPPUS, in which we own an indirect 51% interest.
“BKV-BPP Power” or “BKV-BPP Power Joint Venture” refers to BKV-BPP Power LLC, a Delaware limited liability company and the joint venture between BKV Corporation and BPPUS, in which we own a 50% interest.
“BKV-BPP Retail” refers to BKV-BPP Retail, LLC, a Delaware limited liability company and wholly owned subsidiary of the BKV-BPP Power Joint Venture.
“BKVerde” refers to BKVerde, LLC, a Delaware limited liability company and wholly owned subsidiary of BKV dCarbon Ventures.
“BNAC” refers to Banpu North America Corporation, a subsidiary of Banpu, our sponsor, and the majority stockholder of BKV Corporation.
“BPPUS” refers to Banpu Power US Corporation, a wholly owned subsidiary of Banpu Power and the owner of a 50% interest in the BKV-BPP Power Joint Venture and a 49% interest in the BKV-BPP Cotton Cove Joint Venture.
“bylaws” refers to the second amended and restated bylaws of BKV Corporation to be adopted in connection with the consummation of this offering.
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“Carbon Sequestered Gas” refers to a Scope 1, 2 and 3 carbon neutral natural gas product.
“certificate of incorporation” refers to the second amended and restated certificate of incorporation of BKV Corporation to be adopted in connection with the consummation of this offering.
“Code” means the Internal Revenue Code of 1986, as amended.
“Data Lake” refers to a centralized cloud, large data technology that stores all company data and enables dashboards, visualizations, and analytics from a variety of systems and inputs.
“Devon Barnett Acquisition” refers to our acquisition of more than 289,000 net acres, 3,850 producing operated wells and related upstream assets in the Barnett from Devon Energy Corporation, which closed in October 2020.
“ERCOT” refers to the Electric Reliability Council of Texas.
“ESG” refers to environmental, social and governance.
“Exxon Barnett Acquisition” refers to our acquisition of approximately 165,000 net acres, 2,100 operated wells and related natural gas upstream, midstream and other assets in the Barnett from XTO Energy, Inc. and Barnett Gathering LLC, subsidiaries of Exxon Mobil Corporation, which closed on June 30, 2022.
“FID” refers to final investment decision.
“GAAP” refers to generally accepted accounting principles in the United States.
“GHG” refers to greenhouse gases.
“governing documents” refers to our certificate of incorporation and our bylaws.
“High West” refers to High West Sequestration, LLC, a Louisiana limited liability company and wholly owned subsidiary of BKV dCarbon Ventures.
“HRCO” refers to a contract for the financial purchase and sale of power based on a floating price of natural gas at a predetermined location using a predetermined conversion factor, or heat rate, required to turn the fuel input into electricity.
“Kalnin Ventures” refers to Kalnin Ventures LLC, a Colorado limited liability company and wholly owned subsidiary of BKV Corporation.
“NEPA” refers to the Marcellus Shale in the Appalachian Basin of Northeast Pennsylvania.
“net zero” refers to the full elimination and/or offset of Scope 1, Scope 2 and/or Scope 3 emissions, as applicable, from our owned and operated upstream businesses.
“NGP” refers to natural gas processing.
“RBL Borrower” refers to BKV Upstream Midstream, LLC, a wholly owned subsidiary of BKV Corporation.
“RBL Credit Agreement” refers to that certain reserve-based lending agreement dated as of June 11, 2024, among BKV Corporation, the RBL Borrower, Citibank, N.A., as administrative agent, and the financial institutions party thereto.
“Responsibly Sourced Gas” or “RSG” refers to natural gas produced from a well which has gone through Project Canary’s TrustWell environmental assessment and verification process and has a current TrustWell rating.
“Ryder Scott” refers to Ryder Scott Company, L.P., independent petroleum engineers.
“SREC” refers to Solar Renewable Energy Credit, which represents a form of environmental attribute associated with solar energy generation, which can be marketed for financial gain to improve project
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economics or retired to offset the SREC owner’s Scope 2 emissions. For every 1,000 kilowatt-hours of electricity produced by an eligible solar facility, one renewable energy credit and one compliance premium is awarded. The combination of a renewable energy credit and a compliance premium is known as an SREC. For a solar facility to be credited with that SREC, the system must be certified and registered by state agencies.
“Temple I” refers to the combined gas turbine and steam turbine power plant located in Temple, Texas and owned by the BKV-BPP Power Joint Venture.
“Temple II” refers to a second combined gas turbine and steam turbine power plant located in Temple, Texas, which power plant sits on the same site as Temple I and is owned by the BKV-BPP Power Joint Venture.
“Temple Plants” refers to Temple I and Temple II, collectively.
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PROSPECTUS SUMMARY
This summary highlights certain information about us and this offering contained elsewhere in this prospectus, but it is not complete and does not contain all of the information you should consider before making an investment decision. In addition to this summary, you should read this entire prospectus carefully, including the sections titled “Risk Factors,” “— Summary Historical 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 are supported by 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 expect our owned and operated upstream and natural gas midstream businesses to achieve net zero Scope 1 and Scope 2 emissions by the early 2030s, and net zero Scope 1, 2 and 3 emissions by the late 2030s. We maintain a “closed-loop” approach to our net zero emissions goal through the operation of our four business lines. We are committed to vertically integrating portions of our business to reduce costs and improve overall commercial optimization of the full value chain. For instance, in the Barnett, our natural gas production is gathered and transported in part through our midstream systems and we commenced sequestration operations at our first CCUS project in November 2023. We expect our second CCUS project to commence sequestration activities in the first half of 2026 and are evaluating a robust backlog of actionable CCUS opportunities. We believe that our differentiated business model, net zero emissions focus, highly experienced management team and technology-driven approach to operating our business will enable us to create stockholder value.
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We understand the impact climate change has on our community, the world and future generations, which is why addressing these impacts in how energy is produced is a top priority. In particular, it is one of our core values, “Be One BKV,” to create a unified team with a shared vision to achieve our emission reduction and energy impact goals.
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Our Operations
Natural Gas Production
We are engaged in the acquisition, operation and development of natural gas and NGL properties primarily located in the Barnett Shale in the Fort Worth Basin of Texas (the “Barnett”) and in the Marcellus Shale in the Appalachian Basin of Northeastern Pennsylvania (“NEPA”). Our upstream assets are the core of our business and provide us with substantial Adjusted Free Cash Flow, which we expect will be sufficient to fund our upstream, midstream and power capital expenditure program while maintaining a conservative balance sheet. We have a balanced portfolio of low decline producing properties and undeveloped inventory, primarily in the Barnett. Additionally, our focus on operational efficiencies, access to BKV-owned and third-party midstream systems, and proximity to natural gas demand markets along the Gulf Coast and Northeast corridor allow us to generate high margins.
As of June 30, 2024, our total acreage position was approximately 479,000 net acres, 99% of which was held by production. For the six months ended June 30, 2024, our net daily production averaged 807.6 MMcfe/d, consisting of approximately 80% natural gas and approximately 20% NGLs. As of December 31, 2023, our total proved reserves of 4,094 Bcfe had an estimated 8.1% year-over-year average base decline rate over the next 10 years. As of December 31, 2023, we had more than 15 years of core development inventory, with attractive returns, based on a 1 to 1.5 rigs per year pace, including 540 gross drilling locations, of which 68 are proved locations, and 2,097 gross refracture (“refrac”) candidates, of which 375 are proved locations. For a discussion of how we identify drilling locations and refrac candidates, please see “Business — Our Operations — Natural Gas Production — Determination of Identified Drilling and Refracture Locations.” Based on current commodity prices, the capital investment required to hold production flat year-over-year is equal to less than approximately 60% of our Adjusted EBITDAX for the 2023 fiscal year. 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 165,000 net acres, 2,100 operated wells and related upstream, midstream and other assets in the Exxon Barnett Acquisition. As of June 30, 2024, our Barnett acreage position was approximately 460,000 net acres, which is approximately 99% held by production. Our average daily Barnett production of approximately 682.5 MMcfe/d for the six months ended June 30, 2024 consisted of approximately 76% natural gas and approximately 24% NGLs. We had an average working interest in our operated wells in the Barnett of approximately 96.9% as of December 31, 2023 and an Effective NRI in the Barnett of approximately 80.2%.
We are the largest natural gas producer by gross operated volume in the Barnett. Based on information published by the Texas Railroad Commission (“TRRC”), the chart below illustrates our gross operated production volumes in the Barnett as of January 2024, which represent approximately 29% of the total Barnett production, and nearly double than that of the next largest producer in the Barnett for the month of January 2024.
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We entered NEPA in 2016 and have subsequently scaled our position through 12 acquisitions. As of June 30, 2024, our acreage position was approximately 19,480 net acres, which is approximately 97.5% held by production. Our average net daily production of 125.2 MMcfe/d for the six months ended June 30, 2024 consisted entirely of natural gas. We had an average working interest in our operated wells in NEPA of 89.4%, as of December 31, 2023.
On June 14, 2024, we sold our wholly owned subsidiary, BKV Chaffee, which owned a non-operated interest in approximately 9,800 net acres and 116 gross (24.2 net) wells and approximately 122 Bcfe of proved reserves in NEPA, as well as our interest in the Repsol Oil & Gas operated midstream system, for a purchase price of $106.7 million, subject to adjustment. On June 28, 2024, our wholly owned subsidiary, BKV Chelsea, sold certain of its non-operated upstream assets, including its interest in approximately 6,800 net acres and 214 gross (15.4 net) wells and approximately 35 Bcfe of proved reserves in NEPA for a purchase price of $25.0 million, subject to adjustment.
In February 2023, we re-certified most of our production under the TrustWell environmental assessment program of Project Canary, an environmental certification and ESG data company. We achieved a Gold rating from Project Canary, the second highest rating a company can receive for its production, qualifying the certified portion of our natural gas production as Responsibly Sourced Gas (“RSG”). As part of its environmental assessment, Project Canary analyzes and certifies our production on a well by well basis. As of June 30, 2024, approximately 70% of our NEPA production and approximately 45% of our Barnett production was re-certified. We intend to continue an environmental assessment of substantially all of our existing production. In addition, we intend to advance the market for our produced gas beyond RSG and its current certification towards “Carbon Sequestered Gas”, a Scope 1, 2 and 3 carbon neutral natural gas product. We expect that production of Carbon Sequestered Gas will be achieved by bundling RSG with carbon credits sufficient to offset the estimated emissions associated with the production, gathering and boosting of such RSG, as well as the estimated emissions from its transmission, distribution (if applicable) and ultimate combustion, with the quantified emissions and the requisite volume of CCUS offsets being third-party certified. We have an agreement with a third party to establish the blockchain ledger and tokens; however, this process is dependent upon the development of the necessary technology by such third party. In addition, we expect to utilize the blockchain ledger and tokens with the American Carbon Registry, once that registry has been established. The carbon credits included in our Carbon Sequestered Gas will be generated by our CCUS projects, as described below in “— Path to Net Zero Emissions” and retired against
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our Scope 1 and/or Scope 3 emissions. We believe Carbon Sequestered Gas could potentially provide a decarbonized, certified and qualified fuel and retired credits bundle that is a differentiated and premium product.
In August 2023, BKV entered into a contract with ENGIE Energy Marketing NA, Inc, a subsidiary of global energy utility ENGIE S.A. (“ENGIE”), for the sale and purchase of up to 10,000 MMBtu/d of our Carbon Sequestered Gas. Additionally, in March 2024, BKV entered into a contract with Kiewit Infrastructure South Co., a subsidiary of Kiewit Corporation (“Kiewit”), for the sale and purchase of up to 100 MMBtu/d of our Carbon Sequestered Gas. The carbon credits included in our Carbon Sequestered Gas will be generated by our CCUS projects and will be third-party verified. Subject to completion of our certification process with the American Carbon Registry (see “— Carbon Capture, Utilization and Sequestration” below), we expect to begin delivery of Carbon Sequestered Gas by the end of 2024.
Natural Gas Midstream
Through our ownership in midstream systems, we are engaged in the gathering, processing and transportation of natural gas (which we refer to as our natural gas midstream business) that supports our upstream assets and third-party producers in the Barnett and NEPA. Our midstream assets improve our overall corporate returns by enhancing our margins and lowering our break-even operating costs while allowing us to manage the timing, development and optimization of production of our upstream assets. In the Barnett, during the six months ended June 30, 2024, approximately 193 MMcf/d of our gross production (approximately 22% 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. We own and operate approximately 16 miles of natural gas gathering pipelines, 14 miles of freshwater distribution pipelines and six gas compression units in NEPA. As part of our sale of BKV Chaffee, we sold our minority non-operated ownership interest in a Repsol Oil & Gas operated midstream system in NEPA on June 14, 2024.
Power Generation
We have a 50% ownership interest in the BKV-BPP Power Joint Venture, which owns the Temple Plants, modern combined cycle gas and steam turbine power plants located in the Electric Reliability Council of Texas (“ERCOT”) North Zone in Temple, Texas. The remaining 50% interest is owned by BPPUS, a wholly owned subsidiary of Banpu Power and an affiliate of our sponsor, Banpu. Temple I and Temple II have annual average power generation capacities of 752 MW and 747 MW, respectively, and each power plant delivers power to customers on the ERCOT power network in Texas. Temple I and Temple II have baseload design heat rates of approximately 6,904 Btu/kWh and 6,950 Btu/kWh, respectively, which are below the ERCOT Combined Cycle Gas Turbines (“CCGT”) average. The modern technology utilized at the Temple Plants enables them to respond to rapidly changing market signals in real time, ensuring the highest operational readiness during the time when electricity consumption peaks (in winter and summer), making the power plants well-suited to serve the various needs of the ERCOT market. We continue to explore potential additional acquisitions to expand our power generation business. We expect our power generation assets will be synergistic with our base upstream business and we leverage our existing organization to provide marketing, engineering, finance, accounting and other administrative services to the BKV-BPP Power Joint Venture for an annual fee plus expenses.
In addition, after receiving the necessary approvals from the Public Utility Commission of Texas (the “PUCT”) and ERCOT, the BKV-BPP Power Joint Venture recently launched a retail marketing business to sell electricity to commercial, industrial, and residential retail customers in Texas through its wholly owned subsidiary, BKV-BPP Retail, LLC (“BKV-BPP Retail”), under the brand name BKV Energy. Since its official launch in February 2023, BKV Energy has built a portfolio of over 57,000 customers and is licensed to serve throughout the deregulated portions of Texas.
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Carbon Capture, Utilization and Sequestration
Through our CCUS business, we aim to reduce man-made GHG emissions to the atmosphere by capturing CO2 emitted in connection with natural gas activities, whether from our own operations or third- party operations, as well as from other energy and industrial sources. Our process involves capturing CO2 before it is released into the atmosphere and then compressing the captured CO2 and transporting it via pipeline to sites where it can be injected into Underground Injection Control (“UIC”) wells for secure geologic sequestration. Additionally, we have engaged Project Canary to analyze and report the CO2e injection volumes and environmental attributes of our sequestration projects, and we are working with the American Carbon Registry to certify and register the environmental attributes associated with our CCUS projects as tradeable carbon credits. In the future, we may sell carbon credits associated with our CCUS projects to unrelated third parties outside of our value chain, which may negatively impact our net zero strategy, including by delaying or preventing our achievement of net zero.
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 since early 2021. The development of our CCUS business has progressed rapidly, supported by internal geology, engineering, operations, business development, land, regulatory and other professionals, along with academics and CCUS-focused partnerships. We believe that with a continued and timely execution of our business plans, the Barnett Zero Project could begin generating positive net income via tax credits in 2024. We expect to fund up to 50% of our CCUS business from a variety of external sources, which may include joint ventures, project-based equity partnerships and federal grants, with the remaining capital needs being funded with cash flows from operations. The projected timeline for commercial operations and the generation of positive CCUS business revenue and positive earnings depends, in part, on our ability to fund the anticipated capital requirements for the potential projects that we have identified and described below through external funding and revenues from our upstream business, as well as on our ability to receive our portion of the anticipated Section 45Q tax credits associated with these projects. We may not receive 100% of the Section 45Q tax credits associated with projects funded by third parties and, in such cases, will receive only a corresponding percentage of the anticipated Section 45Q tax credits associated with such projects.
We seek to execute CCUS projects with attractive standalone economics and the ability to sequester emissions from both our own operations and from third-party operations. For example, we plan to target CCUS projects with high concentration CO2 streams where revenue, taking into account tax incentives, less cash operating expense would generally be expected to be between $40 and $70 per metric ton of sequestered CO2e for the first six years of commercial operations for projects owned by BKV. Additionally, we are evaluating the feasibility of developing CCUS projects outside of the United States. We may also provide development and support services for third-party owned CCUS projects on a fee-for-service model, although such projects will not be included in our path to net zero. We are also evaluating potential third party investments in our CCUS business, which may accelerate the development of our CCUS projects; however, depending on the terms of such investment, this may impact the ultimate number of carbon credits we may receive from such projects.
As part of our “closed-loop” approach to our net zero emissions goal, we expect to apply a portion of the CO2 emissions that are sequestered through our CCUS business to offset GHG emissions from our owned and operated upstream and natural gas midstream businesses. We may not receive 100% of the environmental attributes associated with CCUS projects funded in whole or in part by third parties, and, in such cases, we expect to have the right to purchase such environmental attributes BKV would not otherwise receive. Ultimately, we will be able to apply only such portion of the sequestered emissions to offset our own GHG emissions that corresponds to the percentage of environmental attributes BKV receives or purchases. We expect our CCUS business to contribute in significant part to our goals to fully offset our Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses by the early 2030s, and our Scope 1, 2 and 3 emissions from our owned and operated upstream and natural gas midstream businesses by the late 2030s. See “— Path to Net Zero Emissions” below for a description of how we estimate our Scope 1, 2 and 3 annual emissions and how we expect our CCUS business to contribute to the offset of those emissions.
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CCUS Projects
Currently, we have one operational CCUS project and are pursuing sixteen additional potential CCUS projects that we believe are commercially viable based on economics supported by enhanced Section 45Q tax credits and that we believe can be completed by the late 2030s. We have entered into various letters of intent and definitive contracts that we expect to grant us carbon storage and sequestration rights on over 44,000 acres of leased pore space across seven distinct projects located in three states, with total reservoir storage capacity of over 1 billion metric tons of CO2e. We have filed applications to seek Class VI permits for two of these pore space locations, one of which is in the State of Louisiana. The EPA recognized our permit applications as being administratively complete in January 2024 and February 2024, respectively, and then transferred our permit application applicable to the Louisiana pore space location to the State of Louisiana, which assumed primacy for Class VI well permitting. The Louisiana Department of Energy and Natural Resources declared our permit application administratively complete in July 2024. The EPA expects to complete its technical review of our other permit application by September 2025. Our projected timeline for commercial operations of these sixteen projects depends in part on our ability to fund the capital requirements for these potential projects through external funding and revenues from our upstream business. Our timeline also depends on a regulatory environment that is favorable to our projects and their development. Our potential projects can be placed into six categories: (i) operational projects, (ii) projects that have reached FID, but are not yet operational, (iii) identified NGP projects under evaluation, (iv) identified industrial projects under evaluation, (v) identified ethanol projects under evaluation, and (vi) other potential projects that have been identified but not yet sufficiently evaluated. We have achieved notable milestones with respect to several of the seventeen projects within the first five categories, as more fully described below.
Project
|
| |
Status(1)
|
| |
Actual or Forecasted
Initiation of Sequestration Operations(2) |
| |
Forecasted Annual
Sequestration Volumes (Mtpy CO2e)(3) |
| |||
Barnett Zero
|
| |
Operating
|
| |
November 2023
|
| | | | 0.18 | | |
Cotton Cove
|
| |
FID
|
| |
1H 2026
|
| | | | 0.04 | | |
8 NGP Projects
|
| |
Pre-FID
|
| |
2025 – 2029
|
| | | | 2.68 | | |
3 Industrial Projects
|
| |
Pre-FID
|
| |
2026 – 2027
|
| | | | 11.15 | | |
4 Ethanol Projects
|
| |
Pre-FID
|
| |
2027 – 2029
|
| | | | 2.56 | | |
(1)
We have not secured external financing, reached FID or entered into the definitive agreements necessary to execute any of the pre-FID projects identified above.
(2)
Our projected timeline for commencement of sequestration operations at the Cotton Cove Project and all of the pre-FID projects identified above depends in part on our ability to fund the capital requirements for these potential projects through external funding and revenues from our upstream business, as well as a regulatory environment that is favorable to our projects and their development. See “Risk Factors — Risks Related to Our CCUS Business.”
(3)
We may not receive 100% of the environmental attributes associated with CCUS projects funded in whole or in part by third parties, and, in such cases, we expect to have the right to purchase such environmental attributes BKV would not otherwise receive. Ultimately, we will be able to apply only such portion of the sequestered emissions to offset our own GHG emissions that corresponds to the percentage of environmental attributes BKV receives or purchases.
Operational Projects
Barnett Zero Project. In November 2023, our first CCUS project, which we refer to as the Barnett Zero Project, commenced commercial sequestration of CO2 waste generated by EnLink’s Bridgeport natural gas processing plant and neighboring operations. In the Barnett Zero Project, EnLink transports our natural gas produced in the Barnett to its natural gas processing plant in Bridgeport, Texas, where the CO2 waste stream is captured, compressed and then disposed of and sequestered via our nearby injection well. The Barnett Zero Project is an NGP project that separates CO2 from substantially all of our EnLink-gathered
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natural gas production. We initially reached FID and entered into a definitive agreement with EnLink for the Barnett Zero Project in June 2022, subsequently drilled a Class II well that complies with standards applicable to Class VI wells, obtained EPA-approval of our Monitoring, Reporting and Verification Plan, as required by the EPA’s Greenhouse Gas Reporting Program, and commenced operations with first injection in November 2023. We expect the Barnett Zero Project to achieve an average sequestration rate of approximately 183,000 metric tons of CO2e per year and to require a total investment by us of approximately $36.0 million, of which $34.0 million has been invested as of December 31, 2023.
We intend to use the Barnett Zero Project as a prototype for modular NGP projects that can be repeated and quickly scaled. We are currently progressing eight NGP projects based on this model and anticipate that these projects will reach FID at various points in 2025 through 2029.
FID Projects
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 midstream assets to do so. We have multiple pore space opportunities for CO2 injection, and we estimate the Cotton Cove Project will geologically sequester up to approximately 40,000 metric tons of CO2 per year, and we expect to be entitled to use 100% of the environmental attributes associated with such volumes towards our net zero goals. The Cotton Cove Project is held through BKV-BPP Cotton Cove LLC (“BKV-BPP Cotton Cove” or the “BKV-BPP Cotton Cove Joint Venture”), a joint venture owned 51% by BKV dCarbon Ventures and 49% by BPPUS. We currently estimate the total investment required for the Cotton Cove Project to be approximately $17.6 million, of which we will be required to contribute approximately $9.0 million and under the terms of an agreement with BPPUS, we expect to be entitled to use 100% of the environmental attributes associated with such volumes towards our net zero goals. We are targeting commencement of CO2 sequestration activities in the first half of 2026, subject to our ability to secure all required permits, at which point we expect this project will be the second of our current modular line of identified potential NGP projects, in addition to the Barnett Zero Project. Additionally, BKV dCarbon Ventures will manage the BKV-BPP Cotton Cove Joint Venture and leverage our existing organization to provide marketing, engineering, finance, operations, project management, accounting and other administrative services to the BKV-BPP Cotton Cove Joint Venture, in each case for an annual fee plus expenses. For additional information about the BKV-BPP Cotton Cove Joint Venture, see “Certain Relationships and Related Party Transactions — BKV-BPP Cotton Cove Joint Venture — BKV-BPP Cotton Cove Limited Liability Company Agreement.”
We are also evaluating expansion of the Barnett Zero and Cotton Cove Projects to pilot, and then scale, post-combustion carbon capture technology that would allow us to sequester up to an additional approximately 250,000 metric tons per year of captured CO2e from low concentration emissions from within our natural gas midstream and/or other nearby processing operations. As part of this process, we intend to capture CO2e from sources such as compressor exhaust flues and utilize compressor waste heat to reduce energy requirements and cost.
NGP Projects
We have identified eight potential NGP projects that we anticipate will achieve FID and commence initial sequestration operations at various points in 2025 through 2029. If approved and implemented, we anticipate that these eight projects would sequester third-party emissions, require a total capital investment by us of approximately $440.0 million by December 31, 2029 and thereafter provide a combined forecasted annual sequestration volume of approximately 2.68 million metric tons per year of captured CO2e.
A significant portion of the carbon capture infrastructure necessary to execute these eight potential NGP projects already exists. For example, we entered into definitive agreements for pore space leasehold that would provide approximately 45 million metric tons of CO2e sequestration capacity for one project, and, in connection with our development of another project, entered into a definitive agreement with a local emitter for the transfer and purchase of the CO2 waste stream from its natural gas processing plant. Therefore, if approved at FID, and assuming we are able to execute definitive agreements on the terms and timeline we
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believe are obtainable and secure sufficient external funding, we expect these projects to start sequestration operations before December 31, 2029.
Industrial Projects
We are currently evaluating three potential medium to higher concentration industrial projects to sequester third-party emissions, which we anticipate will achieve FID and commence initial sequestration operations at various points in 2026 through 2027. If approved and implemented, these three projects would provide a combined forecasted annual sequestration volume of approximately 11.15 million metric tons per year of captured CO2e.
Pore space leaseholds have been secured for all three of these projects, including one covering approximately 21,000 acres of state-owned land in Louisiana, which project we refer to as the High West Project.
In August 2023, High West Sequestration, LLC (“High West”), a wholly owned subsidiary of BKV dCarbon Ventures, entered into a carbon sequestration agreement with the State of Louisiana to develop facilities and permanently sequester CO2 from local third-party emissions sources. The State of Louisiana granted High West the carbon storage and sequestration rights on approximately 21,000 acres of land in St. Charles and Jefferson Parishes. The acreage is in an ideal location for targeted carbon capture and sequestration efforts, with an estimated 22 Mtpy CO2e of potential capture and sequestration located within a 20 mile radius from various emissions points. In addition, the storage site has a large CO2 storage potential, estimated to be between 140 to 1,000 Mtpy CO2, subject to further evaluation, planning and development design decisions. Under the agreement, High West will dispose of CO2e waste from local third-party emissions sources through permanent sequestration via injection wells on the designated acreage. This project, which we refer to as the High West Project, is expected to reach FID by the end of 2024. BKV dCarbon Ventures engaged NuQuest Energy, LLC to provide CCUS marketing and development services for the High West Project.
We have filed applications to seek Class VI permits for two of these industrial projects, one of which is in the State of Louisiana. The EPA recognized our permit applications as being administratively complete in January 2024 and February 2024, respectively, and then transferred our permit application applicable to the Louisiana pore space location to the State of Louisiana, which assumed primacy for Class VI well permitting. The Louisiana Department of Energy and Natural Resources declared our permit application administratively complete in July 2024. The EPA expects to complete its technical review of our other permit application by September 2025. We also anticipate that a Class VI permit application for the third project will be submitted by early 2025. If each of these projects is approved at FID, and we are able to secure sufficient external financing and assuming definitive agreements are timely executed containing terms we believe are obtainable, we expect to initiate sequestration operations between 2026 and 2027. Verde CO2 has the option to purchase up to a 5% minority economic interest in two of these potential industrial projects and, to the extent it exercises such option, would be entitled to a pro rata share of the Section 45Q tax credits associated with the CCUS projects in which it invests.
Ethanol Projects
We have identified four potential ethanol projects that we anticipate will achieve FID and commence initial sequestration operations at various points during 2027 through 2029. If approved and implemented, we anticipate that these four projects would sequester third-party emissions, require a total capital investment by us of approximately $680 million by December 31, 2029, and thereafter provide a combined forecasted annual sequestration volume of approximately 2.56 million metric tons per year of captured CO2e.
If each of these projects is approved at FID and assuming we are able to execute definitive agreements on the terms and timeline we believe are obtainable and secure sufficient external funding, we expect to begin sequestration operations between 2027 and 2029.
In addition to these sixteen identified potential projects, we are currently evaluating more than ten early-stage project opportunities that are aligned with our high concentration strategy but are not yet sufficiently evaluated to determine potential sequestration volumes, geologic feasibility or timeline of completion. We
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also evaluate later-stage opportunistic CCUS project acquisition opportunities. In the event a potential project listed above is not progressed for any reason, including failure to FID, or additional funding provides for greater capacity to complete projects, we may further evaluate and develop one or more of these early-stage project opportunities.
Our CCUS business of capturing and sequestering emissions from our operations and from operations of third parties is a critical component of our “closed-loop” approach to achieving our goal of net zero Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses by the early 2030s and Scope 1, 2 and 3 emissions from our owned and operated upstream and natural gas midstream businesses by the late 2030s. We expect to continue to identify and evaluate additional CCUS projects and we believe that we will be able to complete a sufficient number of the above-described or other CCUS projects in order to meet our Scope 1, 2 and 3 emissions goals. See “— Path to Net Zero Emissions” for a more detailed description of how we anticipate reaching our Scope 1, 2 and 3 emissions goals.
However, we have not secured external financing, reached FID or entered into the definitive agreements necessary to execute any of the pre-FID projects identified above, and there can be no guarantee that we will be able to execute and operate any of the sixteen identified potential 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. There can be no assurance that any of the sixteen identified CCUS projects discussed above, the Barnett Zero Project or any other CCUS project will achieve the forecasted sequestration volumes, and we may not commence sequestration operations for any of the projects identified above by the anticipated timeframe, or at all. Furthermore, we may not receive 100% of the environmental attributes associated with CCUS projects funded in whole or in part by third parties, and, in such cases, we expect to have the right to purchase such environmental attributes BKV would not otherwise receive. Ultimately, we will be able to apply only such portion of the sequestered emissions to offset our own GHG emissions that corresponds to the percentage of environmental attributes BKV receives or purchases. While we may consider alternatives to offset our owned and operated upstream and natural gas midstream emissions (including the purchase of verified offset credits) in order to meet our Scope 1, 2 and 3 emissions goals, ultimately, we may not be able to achieve our goals of net zero Scope 1 and 2 emissions from our owned and operated upstream businesses and natural gas midstream by the early 2030s or net zero Scope 1, 2 and 3 emissions from our owned and operated upstream businesses and midstream businesses by the late 2030s.
We estimate the aggregate investment required to develop the seventeen identified actual and potential CCUS projects to be between approximately $1.3 – 1.8 billion between now and the end of 2030. We anticipate that some of these project costs will be borne by third-party investors in these projects, including owners of sources of CO2e, landowners and other stakeholders. In order to achieve the projected timeline for commercial operations of such projects, we expect to fund the anticipated cost of these CCUS projects with a combination of up to 50% from third party sources, which may include joint ventures, project-based equity partnerships and federal grants, with the remaining capital needs being funded with cash flows from operations. 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. Therefore, if sufficient external funding is not available, then we would expect to continue to develop our CCUS business from cash flows from operations on a less accelerated timeline, which may result in an inability to achieve our Scope 1, 2 and 3 emissions goals on the timeline we anticipate.
Our CCUS business and all of our CCUS projects are in the early stages of development. Although we commenced commercial operations with the initial injection of CO2 waste at the Barnett Zero Project on November 13, 2023, and have reached FID and entered into definitive agreements with respect to the Cotton Cove Project, we have not reached FID with respect to or entered into the definitive agreements necessary to execute any of the other fifteen potential projects identified above. We may not be able to reach agreements on terms acceptable to us or achieve our projected timeline for commercial operations for these projects. In addition, the development of our CCUS business is expected to require material capital investments, and the projected timeline for commercial operations depends on our ability to fund the anticipated capital requirements for the potential projects that we have identified through external funding and revenues from our upstream business. Furthermore, the commercial viability of our CCUS projects depends, in part, on obtaining necessary permits and other regulatory approvals and on our ability to receive our portion of
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the anticipated Section 45Q tax credits associated with these projects. In particular, we must meet certain wage and apprenticeship requirements in order to qualify for enhanced Section 45Q tax credits. For more information about the risks involved in our CCUS business, see “Risk Factors — Risks Related to Our CCUS Business.”
To help us achieve our goal of becoming a leader in CCUS, we established a steering committee that includes two engineers renowned for their work in the development of CCUS projects: Dr. Paitoon (P.T.) Tontiwachwuthikul (Professor of Industrial & Process Systems Engineering & Fellow, Canadian Academy of Engineering) and Dr. Malcolm A. Wilson (Program Director, CO2 Management, Office of Energy & Environment (OEE), Adjunct Professor of Engineering and Graduate Studies). These individuals are professors at the University of Regina, a leading carbon capture research institution, and each has been engaged in CCUS for over 30 years.
Path to Net Zero Emissions
We conducted an initial assessment of our annual Scope 1 and 2 emissions from our owned and upstream businesses as of December 31, 2021, and subsequently updated that assessment for the upstream and natural gas midstream businesses acquired through the Exxon Barnett Acquisition in 2022 to establish an emissions baseline of 2.49 Mtpy CO2e annual Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses as of December 31, 2021. Our assessments did not address our GHG emissions from our other business operations.
We have made progress in the reduction of our annual Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses since December 31, 2021. We estimate that our Scope 1 and 2 annual emissions from our owned and operated upstream and natural gas midstream businesses were approximately 1.9 Mtpy CO2e as of December 31, 2022 and 1.55 Mtpy CO2e as of December 31, 2023, reflecting a reduction of approximately 0.9 Mtpy CO2e from our baseline emissions assessment established as of December 31, 2021. This reduction is due primarily to the implementation of our “Pad of the Future” and leak detection and repair programs, which began in the fourth quarter of 2021 and occurred throughout 2022 and 2023. During this time frame, our “Pad of the Future” program has eliminated 0.52 Mtpy CO2e, or 21%, of our annual Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses, and improvements in our emission quantification methods and the implementation of site-level leak detection and repair programs have resulted in the elimination of an additional 0.42 Mtpy CO2e, or 17%, of our annual Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses. In total, this represents a 0.94 Mtpy CO2e or 38% reduction of our annual GHG emissions from our baseline emissions assessment established as of December 31, 2021.
Our emissions estimates presented in this prospectus are based on information with respect to our owned and operated upstream and natural gas midstream businesses in the Barnett and NEPA through fiscal year 2023 and reported by BKV pursuant to the Subpart C and Subpart W, as applicable, requirements of the federal Clean Air Act GHG reporting program regulations of the EPA. These estimates will be updated annually to reflect any changes in activity, inventory, production throughput and emissions reduction retrofits or equipment modifications.
We estimate that our annual Scope 3 emissions from our owned and operated upstream and natural gas midstream businesses were approximately 18.7 Mtpy CO2e as of December 31, 2023. These Scope 3 emissions are currently estimated in accordance with IPIECA’s “Sustainability reporting guidance for oil and gas industry,” dated March 2020. Specifically, Scope 3 emissions are estimated per the Greenhouse Gas Protocol’s “Corporate Value Chain (Scope 3) Accounting and Reporting Standard,” released in 2011, under Category 11 (Use of Sold Product). Scope 3 emissions estimated using source Category 11 represent the majority of Scope 3 emissions from our owned and operated upstream and natural gas midstream 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 uses 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 annual Scope 3 CO2e emissions are estimated at an approximated year-end net production volume of 942 MMcfe/d
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of natural gas (approximately 85% methane, 5% ethane and 10% other) and approximately 139.4 MBbls of NGLs (or approximately 2 MMcfe/d), as reported to the EPA for Subpart W. Our NGL constituents are estimated based on average constituent NGL barrel. Allocating the entire 944 MMcfe/d towards combustion as the end use, applying suitable combustion emission factors from the EPA, and using AR4 GWPs, Scope 3 annual emissions from our owned and operated upstream operations are estimated to be approximately 18.7 Mtpy CO2e. We currently engage third party consultants to develop and review our Scope 3 emissions estimates.
The charts below reflect (i) our estimated annual Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses as of December 31, 2023, and (ii) our estimated annual Scope 3 emissions from our owned and operated upstream and natural gas midstream businesses as of December 31, 2023. These two charts also reflect our intended path to net zero Scope 1 and 2 emissions by the early 2030s and net zero Scope 1, 2 and 3 emissions by the late 2030s, in each case, for our owned and operated upstream and natural gas midstream businesses. These charts do not address our GHG emissions from our other business operations. As part of our “closed-loop” approach to our emissions goals, we intend to achieve these goals through our “Pad of the Future” emissions reductions, reductions attributable to emissions monitoring and leak surveys, emissions offsets from the retirement of SRECs generated by the BKV-BPP Power Joint Venture’s planned solar facility and executing CCUS projects to sequester our and third-party emissions.
(1)
These emissions estimates are based solely on our owned and operated upstream and natural gas midstream businesses. These emissions estimates do not reflect our GHG emissions from our other business operations, namely our CCUS operations and our power generation business through the BKV-BPP Power Joint Venture.
(2)
Scope 1 calculated emissions are based on those reported to US EPA per Subpart W.
(3)
Emissions surveys accomplished per US EPA Subpart W to reduce emissions.
(4)
We achieved first injection of CO2 waste at the Barnett Zero Project in November 2023.
(5)
Retirement of the SRECs generated by the BKV-BPP Power Joint Venture’s planned 2.5 MW to 5 MW solar facility is expected to offset up to 32% of current scope 2 emissions. The BKV-BPP Power Joint Venture has constructed a 2.5 MW solar facility, which will soon be operational and is in the process of obtaining permits for the remaining 2.5 MW. BKV expects to purchase the SRECs generated by the solar facility or will purchase off of the market to offset Scope 2 emissions.
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(1)
These emissions estimates are based solely on our owned and operated upstream and natural gas midstream businesses. These emissions estimates do not reflect our GHG emissions from our other business operations, namely our CCUS operations and our power generation business through the BKV-BPP Power Joint Venture.
(2)
Scope 1 and 2 calculated emissions are based on 791 MMscf/d production volume for 2023 Subpart W in the Barnett and 151 MMscf/d production volume for 2023 Subpart W in NEPA.
(3)
Emissions surveys accomplished per US EPA Subpart W to reduce emissions.
(4)
We achieved first injection of CO2 waste at the Barnett Zero Project in November 2023.
(5)
Retirement of the SRECs generated by the BKV-BPP Power Joint Venture’s planned 2.5 MW to 5 MW solar facility is expected to offset up to 32% of current scope 2 emissions. The BKV-BPP Power Joint Venture has constructed a 2.5 MW solar facility, which will soon be operational and is in the process of obtaining permits for the remaining 2.5 MW. BKV expects to purchase the SRECs generated by the solar facility or will purchase off of the market to offset Scope 2 emissions.
(6)
Scope 3 calculated emissions are based on an estimated net production rate of approximately 944 MMcfe/d (approximately 944 MMscf/d of natural gas and 2 MMscfe/day of NGLs) as reported to US EPA for CY 2023 Subpart W.
(7)
Scope 3 calculated emissions are estimated assuming combustion-based usage of all produced natural gas and NGLs. Approximately 58% of NGLs are assumed to be combusted for fuel while 100% of all natural gas sold is assumed to be combusted for fuel. Scope 3 emissions estimation methodology is therefore considered to be conservative.
Planned Path to Net Zero (Scope 1 and 2)
Pad of the Future. Our “Pad of the Future” program implements pad level design improvements to reduce pad level usage of natural gas, reduce GHG emissions and maintain operational continuity. As of December 31, 2023, we had implemented elements of our “Pad of the Future” program on approximately 3,200 of our existing wells and we have successfully completed the implementation of the “Pad of the Future” program for our upstream owned and operated assets in NEPA. As a result, as compared to our 2021 baseline assessment, we have achieved a reduction in our estimated annual GHG emissions of approximately 0.53 Mtpy CO2e. 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 plan to implement elements of our “Pad of the Future” program on more than 6,000 of our existing wells (more than 16,500 pneumatic devices and 3,000 pneumatic pumps) by the end of 2027 for an aggregate estimated cost of approximately $35 to $40 million. Once this expansion is completed, we expect to
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eliminate approximately 1.0 Mtpy CO2e of the currently estimated Scope 1 annual emissions from our owned and operated upstream and natural gas midstream businesses.
Emissions Monitoring and Solar. Our leak detection and repair emissions monitoring program involves continuous ground-based instrument monitoring, satellite-based monitoring, aerial flyovers and on the ground leak detection and repair inspections. In addition, we expect to purchase the SRECs generated by the BKV-BPP Power Joint Venture’s planned 2.5 MW to 5 MW solar facility, which is scheduled to begin construction and generating power in 2024. The BKV-BPP Power Joint Venture has obtained permits for and is constructing 2.5 MW and is in the process of obtaining permits for the remaining 2.5 MW. Solar facilities may be subject to increasingly arduous regulatory requirements, including additional permitting requirements. For every 1,000 kilowatt-hours of electricity produced by an eligible solar facility, one SREC is awarded. For a solar facility to be credited with that SREC, the system must be certified and registered by state agencies. The BKV-BPP Power Joint Venture’s planned solar facility is expected to generate SRECs to offset up to 32% of current GHG emissions. The SRECs BKV expects to purchase and retire are reflected in the charts above as neutralizing a portion of our annual Scope 2 emissions from purchased energy for our owned and operated upstream and natural gas midstream business.
CCUS. Further, as discussed under “— Carbon Capture, Utilization and Sequestration” above, we believe that the Barnett Zero Project, together with the Cotton Cove Project and the eight NGP projects, three industrial projects and four ethanol projects for the capture and sequestration of third-party emissions that we have identified, have a combined annual forecasted sequestration volume of approximately 16.61 Mtpy CO2e by the end of 2029, which is greater than the approximately 0.87 Mtpy CO2e annual Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses that we currently estimate will remain after taking into account the expected emissions reductions and offsets from our “Pad of the Future” program, emissions monitoring and leak surveys and the retirement of SRECs generated by the BKV-BPP Power Joint Venture’s planned solar facility that we expect to purchase. Although we have not secured external financing, reached FID or entered into the definitive agreements necessary to execute any of the eight NGP projects, three industrial projects or four ethanol projects we have identified, we expect these projects to reach FID and commence sequestration operations by the end of 2029. A significant portion of the carbon capture infrastructure necessary to execute the NGP projects already exists and, as discussed above, we continue to accomplish important milestones consistent with our projected timeline. If approved at FID, and assuming we are able to execute definitive agreements on the terms and timeline we believe are obtainable and secure sufficient external funding, we expect these projects to start sequestration operations before December 31, 2029.
If we are unable to complete these fifteen projects and the Cotton Cove Project before December 31, 2029, or enter into commercial agreements in connection with these projects that result in BKV receiving less than 100% of the associated emissions offsets, carbon credits or other environmental attributes, we may still reach our Scope 1 and 2 emissions goals with less than all of these projects completed, as the annual forecasted sequestration volume of (i) the Barnett Zero Project is 183,000 metric tons of captured CO2e per year, (ii) the Cotton Cove Project is 40,000 metric tons of captured CO2e per year, (iii) the eight potential NGP projects is an aggregate 2.68 million metric tons of captured CO2e per year, (iv) the three potential industrial projects is an aggregate 11.15 million metric tons of captured CO2e per year and (v) the four potential ethanol projects is an aggregate 2.56 million metric tons of captured CO2e per year.
However, we have not secured external financing, reached FID or entered into the definitive agreements necessary to execute any of the pre-FID projects identified above, and there can be no guarantee that we will be able to execute and operate any of the sixteen identified potential 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. There can be no assurance that any of the potential projects we have identified or the Barnett Zero Project will achieve forecasted sequestration volumes, and we may not commence sequestration operations for any of the potential projects identified above by the anticipated timeframe, or at all. Furthermore, we may not receive 100% of the environmental attributes associated with CCUS projects funded in whole or in part by third parties, and, in such cases, we expect to have the right to purchase such environmental attributes BKV would not otherwise receive. Ultimately, we will be able to apply only such portion of the sequestered emissions to offset our own GHG emissions that corresponds to the percentage of environmental attributes BKV receives or purchases. While we may consider alternatives to offset our
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owned and operated upstream and natural gas midstream emissions (including the purchase of verified offset credits) in order to meet our Scope 1 and 2 emissions goals, ultimately, we may not be able to achieve our goals of net zero Scope 1 and 2 emissions from our owned and operated upstream businesses and natural gas midstream by the early 2030s.
Planned Path to Net Zero (Scope 1, 2 and 3)
We also aspire to offset the annual Scope 3 emissions impact of our owned and operated upstream and natural gas midstream businesses by the late 2030s, which we estimate to be approximately 18.7 Mtpy CO2e annually as of December 31, 2023. Our CCUS business of capturing and sequestering our and third-party emissions is a critical component to achieving this net zero goal. This aspiration to offset the Scope 3 emissions of our owned and operated upstream and natural gas midstream businesses by the late 2030s is limited to our Category 11 (Use of Sold Product) emissions, which we believe represents a significant portion of the overall Scope 3 emissions from our owned and operated upstream and natural gas midstream businesses. However, our Scope 3 emissions estimate does not include our GHG emissions from our other business operations, namely our CCUS and power generation businesses.
As discussed in “— Carbon Capture, Utilization and Sequestration,” above, we are currently operating the Barnett Zero Project and have identified sixteen potential CCUS projects that we believe are commercially viable and estimate would have a combined forecasted annual volume of carbon capture and sequestration of approximately 16 Mtpy CO2e, which represents approximately 79% of our current Scope 1, 2 and 3 annual emissions from our owned and operated upstream and natural gas midstream businesses, and represents approximately 82% of our current Scope 1, 2 and 3 annual emissions from our owned and operated upstream and natural gas midstream businesses after taking into account the expected emissions reductions and offsets from our “Pad of the Future” program, emissions monitoring and leak surveys and the retirement of SRECs generated by the BKV-BPP Power Joint Venture’s planned solar facility that we expect to purchase. In addition, we are currently evaluating more than ten early-stage project opportunities that are aligned with our high concentration strategy and have been identified, but are not yet sufficiently evaluated to determine potential sequestration volumes, geologic feasibility or timeline of completion. We also evaluate later-stage opportunistic CCUS project acquisition opportunities. In the event a potential project is not progressed for any reason, including failure to FID, or additional funding provides for greater capacity to complete projects, we may further evaluate and develop one or more of these early-stage project opportunities. We will continue to evaluate and identify potential CCUS project opportunities consistent with our goal of offsetting our annual Scope 1, 2 and 3 emissions from our owned and operated upstream and natural gas midstream businesses by the late 2030s. However, we may not receive 100% of the environmental attributes associated with CCUS projects funded in whole or in part by third parties, and, in such cases, we expect to have the right to purchase such environmental attributes BKV would not otherwise receive. Ultimately, we will be able to apply only such portion of the sequestered emissions to offset our own GHG emissions that corresponds to the percentage of environmental attributes BKV receives or purchases.
Large scale CCUS projects are subject to numerous risks and uncertainties, including securing third-party financing, reaching definitive agreements with third parties and obtaining necessary permits and other regulatory approvals, and we may be unable to execute on some or all of these projects, including the projects for which we have reached FID, on the timeline we anticipate, on terms acceptable to us or at all. There can be no guarantee that we will be able to execute and complete any of these identified CCUS projects and there can be no guarantee that we will be able to achieve our net zero Scope 1, 2 and 3 emissions goals. The projected timeline for commercial operations of our CCUS projects depends in part on our ability to fund the anticipated capital requirements for the potential projects that we have identified through up to 50% third party equity or debt funding together with revenues from our upstream business. If sufficient external funding is not available, then we would expect to continue to develop our CCUS business from cash flows from operations on a less accelerated timeline. If we are not able to complete CCUS projects having a sufficient forecasted volume of carbon capture to offset our Scope 1, 2 and 3 annual emissions on the timeline and upon terms that we believe are obtainable, we may not be able to achieve our goal of net zero Scope 1, 2 and 3 emissions from our owned and operated upstream and natural gas midstream businesses by the late 2030s.
In addition, our path to net zero solely addresses GHG emissions relating to our owned and operated upstream and natural gas midstream businesses and does not address GHG emissions from our other business
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operations, namely our CCUS and power generation businesses. Our power generation business is operated through the BKV-BPP Power Joint Venture, which owns the Temple Plants. Although we believe our current path to net zero will be sufficient to reduce emissions related to our existing owned and operated upstream and natural gas midstream businesses, the future growth or expansion of such businesses will result in additional GHG emissions. We believe our approach to reducing the emissions from our owned and operated upstream and natural gas midstream operations is repeatable and scalable. Through continued investment and expansion of our “Pad of the Future” program and our emissions and leak surveys, as well as additional CCUS and solar projects, we believe we will be able to offset any such additional emissions from our owned and operated upstream and natural gas midstream businesses resulting from our continued growth.
Business Strategy
Our strategy is to create value for our stockholders by managing and growing our integrated asset base and focusing on our net zero objectives. Our strategy has the following principal elements:
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Optimize the value of our core businesses. We utilize technology and data analysis to enhance our assets and operations, which we believe improves operational efficiencies, reduces our emissions and helps us realize our operational and financial goals as we continue to scale our business. For example, our “Pad of the Future” program, which includes conversion of natural gas-powered instrument pneumatics to compressed air or electric power instruments on existing pads, combined with emission and leak surveys, is expected to eliminate or reduce approximately 1.05 Mtpy CO2e of our annual GHG emissions by the end of 2027. Our “Pad of the Future” application also improves pad efficiencies and operating revenue. We have also improved pad efficiencies and reduced lease operating costs through improvements including leveraging of data analytics to coordinate the workforce, prioritize high-value activity, and assess individual well profitability; automating critical plunger set points; in-sourcing key services such as slick-line, value re-builds, compression overhaul, and location repair and maintenance; as well as entering water share arrangements to reduce disposal and trucking cost. Through these process improvements, we reduced our operating costs for our operated NEPA assets by 33.0% for the trailing twelve months ended June 30, 2024, as compared to the trailing twelve months ended March 31, 2019, which period represented the first year of our operatorship of the NEPA assets. Similarly, we reduced our operating costs for our Barnett assets by 12.8% for the trailing twelve months ended June 30, 2024, as compared to the trailing twelve months ended June 30, 2023, which period represented the first year of our operatorship of the Barnett assets acquired from the Exxon Barnett Acquisition and the Devon Barnett Acquisition combined. Additionally, our refrac and long lateral drill programs have allowed us to organically grow our reserves base. As of December 31, 2023, our Barnett refrac program has added 317 Bcfe of proved reserves since its inception in early 2021. As of December 31, 2023, our Barnett refrac program has an average of $0.57/Mcfe in finding and development costs with respect to proved reserves. This refrac program employs specifically designed perforating technology and a suite of innovative refrac techniques, as well as advanced refrac designs and diversion methods to maximize reserves recovery and economics from legacy Barnett wells. Our Barnett new well drilling program has added 645 Bcfe of proved reserves since our entry into the Barnett. By combining our reserves into a growing asset base with vertically integrated components, we believe we can enhance margins and create a “closed loop” emissions reduction strategy that reduces Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses and captures margin across the value chain.
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Grow through opportunistic, synergistic acquisitions. A significant element of our business strategy is gaining scale through accretive acquisitions. We have a track record of growth through acquisitions, which we believe have been at attractive valuations. Since 2016, we have completed 19 acquisitions resulting in approximately 69% compound annual growth rate of Adjusted EBITDAX as of June 30, 2024. We believe our business model, management team experience and application of technology enable us to quickly and efficiently integrate additional upstream, midstream, power and CCUS assets into our business.
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Maintain a disciplined financial strategy. We believe we can execute on our business plan and grow our business while continuing to generate substantial Adjusted Free Cash Flow. We target a Maintenance Reinvestment Rate of less than 45% and an Upstream Reinvestment Rate of less than
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50%. We are focused on our goal of maintaining a conservative financial profile, with a long-term Total Net Leverage Ratio target of 1.0x to 1.5x. Although we may allow our leverage ratio to exceed our target in connection with a strategic acquisition, we would seek to return our leverage level to between 1.0x and 1.5x as soon as reasonably possible thereafter through Adjusted Free Cash Flow and, if needed, reduced activity levels. To support the generation of future Adjusted Free Cash Flow, we have a policy of hedging approximately 25% to 60% of our forecasted production volumes over a given 12 to 48‑month period, subject to maintaining compliance with the hedging requirements in the RBL Credit Agreement. We believe our capital efficient project inventory, low-decline natural gas production and multiple, integrated business lines will provide consistent returns through varying business cycles. We intend to apply our cash flows to manage our indebtedness in line with our leverage target, fund our capital expenditure program, enhance stockholder value and execute opportunistic acquisitions across our four business lines. Adjusted EBITDAX is not a financial measure calculated in accordance with GAAP. See “— Summary Historical Financial Information — Non-GAAP Financial Measures” for a description of this measure and a reconciliation to the most directly comparable GAAP measure.
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Focus on our net zero objectives. We seek to apply our integrated business model, CCUS projects and carbon-negative initiatives to realize Scope 1 and 2 net zero emissions from our owned and operated upstream and natural gas midstream businesses by the early 2030s. We believe we can achieve this through reductions in and offsets to our owned and operated upstream and natural gas midstream emissions from our “Pad of the Future” emissions reductions program and emissions monitoring and leak surveys, the retirement of SRECs generated by the BKV-BPP Power Joint Venture’s planned solar facility and executing CCUS projects. We believe that carbon emissions within the United States can be reduced substantially through carbon capture on natural gas production, power plants, processing facilities and other energy and industrial infrastructure. As such, in addition to lowering emissions in our owned and operated upstream and natural gas midstream businesses, CCUS for third parties has become a focus of our business plan. We expect our CCUS projects to represent a meaningful portion of our budgeted capital expenditures going forward as we advance our long-term goal of offsetting Scope 3 emissions from our owned and operated upstream and natural gas midstream businesses.
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Encourage innovation. Our distinctive culture encourages innovation with a value-driven focus that feeds into our competitive advantage. For example, our emphasis on the efficient application of modern technology led to the development of our “Pad of the Future” program, our advancements in Barnett refracs and other operational improvements. We intend to continue to develop, retain and add to our already talented, experienced and forward-thinking employees. Our unified team and mantra of “Being a force for good” underpin our core values and provides us with confidence in our ability to successfully manage and grow our business.
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Deliver robust returns to stockholders. We intend to prioritize delivering strong returns to our stockholders through our focus on creating stockholder value. We believe our operational expertise in successfully drilling and refracturing wells, acquiring and integrating assets purchased at attractive valuations and maintaining financial discipline will underpin our ability to meet our stockholder return goals. Our integrated businesses and natural gas-weighted, low-decline PDP reserves collectively reduce our downside risk while providing asymmetric upside returns from the confluence of commodity price uplift potential, operational improvement and development opportunities, and future accretive acquisition opportunities. See “Risk Factors — Risks Related to the Offering and Our Common Stock.”
Competitive Strengths
We have a number of strengths that we believe will help us successfully execute our business strategy, including:
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Integrated asset base well positioned for sustainable growth. Our upstream, midstream and power asset bases reside in geographically concentrated areas with numerous asset acquisition opportunities in close proximity. Our proven ability to successfully negotiate, close and integrate these acquisition opportunities quickly and cost effectively will allow us to continue to grow our portfolio of assets
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synergistically. We believe that scale and the continued application of technological developments and operational excellence, combined with stable, low-decline production profiles, will continue to generate significant capital efficient development opportunities in the Barnett and NEPA.
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High quality, low decline assets serving key demand markets. Through a series of accretive acquisitions, we have established an extensive and largely contiguous acreage position in two key markets, the Barnett and NEPA. Our Barnett assets cover approximately 460,000 net acres, with an approximately 80.2% Effective NRI, and are located in close proximity to key Gulf Coast industrial and LNG demand centers. Our NEPA assets consist of approximately 19,480 net acres (after giving effect to the sales of BKV Chaffee and certain assets held by BKV Chelsea) 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 8.1% year-over-year average base decline rate over the next 10 years as of December 31, 2023. Additionally, we have an inventory of over 15 years of refrac and new drill locations within our core acreage that give us the flexibility to maintain or slightly grow current production levels, depending on the commodity cycle.
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Lower emissions energy production. We are focused on achieving Scope 1 and 2 net zero emissions from our owned and operated upstream and natural gas midstream businesses by the early 2030s. We believe we have a comprehensive ESG program, which is overseen and directed by an executive ESG steering committee. In February 2023, we re-certified most of our production under the TrustWell environmental assessment program of Project Canary, an environmental certification and ESG data company. We achieved a Gold rating from Project Canary, the second highest rating a company can receive for its production, qualifying the certified portion of our natural gas production as RSG. As part of its environmental assessment, Project Canary analyzes and certifies our production on a well by well basis. As of June 30, 2024, approximately 70% of our NEPA production and approximately 45% of our Barnett production was re-certified. We intend to continue an environmental assessment of substantially all of our existing production. In addition, we intend to advance the market for our produced gas beyond RSG and its current certification towards Carbon Sequestered Gas, a Scope 1, 2 and 3 carbon neutral natural gas product. We expect that production of Carbon Sequestered Gas will be achieved by bundling RSG with carbon credits sufficient to offset the estimated emissions associated with the production, gathering and boosting of such RSG, as well as the estimated emissions from its transmission, distribution (if applicable) and ultimate combustion, with the quantified emissions and the requisite volume of CCUS offsets being third-party certified. We have an agreement with a third party to establish the blockchain ledger and tokens; however, this process is dependent upon the development of the necessary technology by such third party. In addition, we expect to utilize the blockchain ledger and tokens with the American Carbon Registry, once that registry has been established. The carbon credits included in our Carbon Sequestered Gas will be generated by our CCUS projects, as described in “— Overview — Our Operations — Path to Net Zero Emissions,” and retired against our Scope 1 and/or Scope 3 emissions. We believe Carbon Sequestered Gas could potentially provide a decarbonized, certified and qualified fuel and retired credits bundle that is a differentiated and premium product. Additionally, we have a plan to achieve net zero Scope 1 and 2 emissions from our owned and operated upstream and natural gas midstream businesses by the early 2030s based on our “Pad of the Future” program, emissions monitoring and leak surveys and the retirement of SRECs generated by the BKV-BPP Power Joint Venture’s planned solar facility and executing CCUS projects. However, if we are not able to complete CCUS projects having sufficient sequestration volumes of CO2 on this timeline, we may consider alternatives to offset the Scope 1 and Scope 2 emissions from our owned and operated upstream and natural gas midstream businesses (including the purchase of verified offset credits from the BKV-BPP Power Joint Venture or third parties). Ultimately, we may not be able to achieve this goal, produce Carbon Sequestered Gas or obtain a premium on such gas (particularly to the extent there are any concerns regarding the type, ownership or quality of offsets or other environmental attributes used for our characterization of Carbon Sequestered Gas).
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Efficient use of capital. Our deep, high-graded inventory of refrac opportunities coupled with our inventory of new drill locations allow us to create meaningful additional cash flow with comparatively
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modest additional capital investments. We utilize operational improvements such as operational process and procurement efficiencies, use of existing field infrastructure, innovative and cost-effective refrac techniques and designs (including diversion methods), drilling long laterals in the Barnett, and optimizing available midstream capacity to further maximize our capital efficiency. Through our midstream, power and CCUS business lines, we are capturing margin across the value chain.
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Well capitalized and conservative balance sheet. Following the completion of this offering, we intend to continue to maintain a strong balance sheet and fund our upstream, midstream and power operations predominantly with internally generated cash flows. We believe that the low decline, predictable nature of our upstream production profile, combined with our hedging plan and reinvestment rate targets, will allow us to successfully meet our leverage goals.
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High caliber and proven management team. We maintain a highly experienced and knowledgeable management team with an average of over 25 years of experience among our senior management team. Our leadership team has significant experience managing integrated energy and power assets for large-scale enterprises, including companies such as PTT Exploration and Production Public Company Limited (“PTT Exploration”) and BP p.l.c. (“BP”). Furthermore, our sponsor, Banpu, one of Asia Pacific’s largest integrated energy companies, provides us with unique and valuable insights into optimizing our integrated energy business.
Recent Developments
Dispositions
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Sales of BKV Chaffee and BKV Chelsea Assets. On June 14, 2024, we sold our wholly owned subsidiary, BKV Chaffee, which owned a non-operated interest in approximately 9,800 net acres and 116 gross (24.2 net) wells and 122 Bcfe of proved reserves in NEPA, as well as our interest in the Repsol Oil & Gas operated midstream system, for a purchase price of $106.7 million, subject to adjustment. On June 28, 2024, our wholly owned subsidiary, BKV Chelsea, sold certain of its non-operated upstream assets, including its interest in approximately 6,800 net acres and 214 gross (15.4 net) wells and 35 Bcfe of proved reserves in NEPA for a purchase price of $25.0 million, subject to adjustment.
Credit Facilities
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Refinancing. On June 11, 2024, the amounts outstanding under the Term Loan Credit Agreement, the Revolving Credit Agreement and the SCB Credit Facility (each as defined herein) were paid off with proceeds from the loans under the RBL Credit Agreement and cash on hand. The Term Loan Credit Agreement, the Revolving Credit Agreement and the SCB Credit Facility were terminated concurrently with the repayment of the remaining amounts owed thereunder. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Loan Agreements and Credit Facilities” for additional information regarding our loan agreements and credit facilities.
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RBL Credit Agreement. On June 11, 2024, BKV Corporation, as guarantor, and the RBL Borrower, as borrower, entered into the RBL Credit Agreement, a reserve-based credit agreement with Citibank, N.A., as administrative agent, and the financial institutions party thereto. The RBL Credit Agreement has a maximum credit commitment of $1.5 billion. As of June 11, 2024, the RBL Credit Agreement has a borrowing base of $800.0 million and an elected commitment of $600.0 million. The RBL Credit Agreement includes a $50.0 million sublimit for the issuance of letters of credit. As of September 9, 2024, $390.0 million of revolving borrowings and $14.6 million of letters of credit were outstanding under the RBL Credit Agreement, leaving $195.4 million of available capacity thereunder for future borrowings and letters of credit. The borrowing base is subject to semi-annual redeterminations based upon the value of our oil and gas properties as determined in a reserve report. The reserve report will be dated as of January and July of each year with the January reserve report prepared by a third-party engineer and the July report prepared by our internal engineers. The borrowing base is also subject to reduction in connection with certain dispositions of assets. The RBL Credit Agreement requires that the RBL Borrower and its restricted
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subsidiaries provide a first-priority security interest in their oil and gas properties (such that those properties subject to the security interest represent at least 90% of PV-9 (as defined in the RBL Credit Agreement) of their borrowing base properties) and substantially all of the personal property assets, subject to customary exceptions, of BKV Corporation, the RBL Borrower, and its restricted subsidiaries that are guarantors thereunder. The RBL Credit Agreement is scheduled to mature on June 12, 2028. The RBL Credit Agreement includes usual and customary covenants for facilities of its type and size. The covenants cover matters such as mandatory reserve reports, the responsible operation and maintenance of properties, certifications of compliance and required disclosures to the lenders. It also places limitations on the incurrence by the RBL Borrower and its restricted subsidiaries of additional indebtedness and liens, declaring or making restricted payments (including dividends and distributions), making investments, designating unrestricted subsidiaries, operating outside the United States, entering into mergers, sales of assets outside the ordinary course of business, transactions with affiliates and limitations on the amount of commodity and interest rate hedges that can be put in place. Such limitations do not apply to BKV Corporation or, unless and until such time such entities become restricted subsidiaries pursuant to the RBL Credit Agreement, BKV dCarbon Ventures, LLC and BKV-BPP Power LLC. The RBL Credit Agreement also contains financial maintenance covenants requiring the RBL Borrower to maintain a net leverage ratio of no greater than 3.25 to 1.00 and a current ratio of at least 1.00 to 1.00. Amounts outstanding under the RBL Credit Agreement bear interest based upon SOFR or ABR (each as defined in the RBL Credit Agreement), as applicable, plus an additional margin which is based on the percentage of the borrowing base being utilized, ranging from 2.75% to 3.75% for SOFR loans and 1.75% to 2.75% for ABR loans. There is also a commitment fee of 0.50% on the undrawn commitments. Obligations under the RBL Credit Agreement may be prepaid without premium or penalty, other than customary breakage costs. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Loan Agreements and Credit Facilities” for additional information regarding the RBL Credit Agreement and the covenants contained therein.
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 23 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 29 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 31 years of international energy experience working with BP and Reliance Industries Limited.
BNAC, our majority stockholder, is an indirect, wholly owned subsidiary of Banpu, our ultimate parent company. Banpu is a multi-billion U.S. dollar market cap energy company publicly traded in Thailand. With 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, any person or group (other than Banpu and its controlled affiliates, excluding portfolio companies and operating companies) acquires 35% or more of our equity interests, or if any person or group acquires a greater percentage of our equity interests than are then held by Banpu and its controlled affiliates (excluding portfolio companies and operating companies of Banpu), such event will be an event of default under the RBL 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.
(1)
Consists of management, directors and other employee and non-employee stockholders.
The information in the chart above does not include 5,000,000 additional shares of our common stock reserved for awards pursuant to the 2024 Equity and Incentive Compensation Plan (the “2024 Plan”), including shares of common stock that may be issued upon vesting of equity awards that we expect
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to be granted in connection with this offering, or 500,000 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:
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being permitted to present only two years of audited financial statements and only two years of related “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this prospectus;
•
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 2029. However, if certain events occur prior to the end of such five-year period, including if we become a “large accelerated filer,” our gross revenues for any fiscal year equal or exceed $1.235 billion or we issue more than $1.0 billion of non-convertible debt in any three-year period, we will cease to be an emerging growth company prior to the end of such five-year period.
Controlled Company
We have applied to list our common stock on the NYSE under the symbol “BKV.” Upon completion of this offering, BNAC will hold approximately % of our total outstanding shares of common stock (or approximately % if the underwriters exercise in full their option to purchase additional shares), comprising more than 50% of the voting power of our outstanding common stock. As a result, we will be a “controlled company” within the meaning of the corporate governance rules of the NYSE. As a “controlled company,” we will be eligible to rely on exemptions from the obligation to comply with certain NYSE corporate governance requirements, including the requirements that:
•
a majority of our board of directors consist of independent directors;
22
•
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 four independent directors upon the closing of this offering.
While BNAC continues to control more than 50% of the voting power of our outstanding common stock, we qualify for, and intend to rely on, these exemptions. Accordingly, you will not have the same 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.
23
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 certain indebtedness, which may include some or all of the $50.0 million in aggregate principal amount outstanding under the BNAC A&R Loan Agreement and the outstanding revolving borrowings under the RBL Credit Agreement, for growth capital expenditures and for other general corporate purposes, which may include the expansion of our CCUS business. See “Use of Proceeds.”
Conflicts of Interest
Because affiliates of Citigroup Global Markets Inc., Barclays Capital Inc., KeyBanc Capital Markets Inc., Mizuho Securities USA LLC, Truist Securities, Inc., Citizens JMP Securities, LLC and SMBC Nikko Securities America, Inc. are lenders under our RBL Credit Agreement and will receive 5% or more of the net proceeds of this offering due to the repayment of borrowings under the RBL Credit Agreement, Citigroup Global Markets Inc., Barclays Capital Inc., KeyBanc Capital Markets Inc., Mizuho Securities USA LLC, Truist Securities, Inc., Citizens JMP Securities, LLC and SMBC Nikko Securities America, Inc., each an underwriter in this offering, are deemed to have a “conflict of interest” under Rule 5121 (“Rule 5121”) of the Financial Industry Regulatory Authority, Inc. (“FINRA”). Accordingly, this offering will be conducted in compliance with the requirements of Rule 5121, which requires, among other things, that a “qualified independent underwriter” participate in the preparation of, and exercise the usual standards of “due diligence” with respect to, the registration statement and this prospectus. Jefferies LLC has agreed to act as a qualified independent underwriter for this offering and to undertake the legal responsibilities and liabilities of an underwriter under the
24
Securities Act, specifically including those inherent in Section 11 thereof. Jefferies LLC will not receive any additional fees for serving as a qualified independent underwriter in connection with this offering. We have agreed to indemnify Jefferies LLC against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act. See “Use of Proceeds” and “Underwriting (Conflicts of Interest)” for additional information.
Dividend policy
We currently do not pay a fixed cash dividend to holders of our common stock, and certain of our debt agreements place certain restrictions on our ability to pay cash dividends to holders of our common stock. Our dividend policy is under consideration by our board of directors. Any future determination related to our dividend policy will be made at the sole discretion of our board of directors. See “Dividend Policy.”
Voting rights
Each share of common stock will entitle the holder to one vote per share. Generally, matters to be voted on by stockholders must be approved by a majority of the votes entitled to be cast at a meeting by holders of all shares of common stock present in person or represented by proxy.
In addition, pursuant to the stockholders’ agreement to be entered into upon the completion of this offering between BNAC and us (our “Stockholders’ Agreement”), for so long as BNAC and Banpu beneficially own 10% or more of our voting stock, BNAC will be entitled to designate for nomination to our board of directors a number of individuals approximately proportionate to such beneficial ownership, provided that (i) from the completion of this offering until the first anniversary of the completion of this offering, at least three board seats will not be BNAC designees, (ii) from and after the first anniversary of the completion of this offering until the first 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.”
25
Listing and stock exchange symbol
We have applied to list our common stock on the NYSE under the symbol “BKV.”
Reserved Share Program
At our request, Citigroup Global Markets Inc., a participating underwriter, has reserved for sale, at the initial public offering price, up to 5% of the shares of common stock being offered by this prospectus for sale to some of our directors, executive officers, employees, business associates and related persons at the public offering price. If these persons purchase reserved shares, it will reduce the number of shares of common stock available for sale to the general public. Any reserved shares that are not so purchased will be offered by the underwriters to the general public on the same terms as the other shares offered by this prospectus. These persons must commit to purchase no later than the close of business on the day following the date of this prospectus. Any participants purchasing such reserved common stock will be prohibited from selling such stock for a period equal to (i) 180 days after the date of this prospectus, in the case of our directors and executive officers, or (ii) 60 days after the date of this prospectus, in the case of our employees, business associates and related persons. See “Principal Stockholders” for more information.
The number of shares of common stock that will be outstanding immediately after the completion of this offering is based on shares of our common stock to be issued pursuant to this offering (assuming the underwriters do not exercise their option to purchase additional shares) and excludes 5,000,000 additional shares of our common stock reserved for awards pursuant to the 2024 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 500,000 shares of our common stock available for purchase by employees pursuant to the ESPP, which will become effective upon the completion of this offering.
Unless otherwise indicated, the information in this prospectus:
•
assumes the execution of our Stockholders’ Agreement, as further described under “Certain Relationships and Related Party Transactions”;
•
reflects the October 2023 one-for-two reverse stock split;
•
assumes the amendment and restatement of our existing certificate of incorporation and the amendment and restatement of our existing bylaws in connection with the consummation of the offering;
•
assumes an initial public offering price of $ per share of common stock (the midpoint of the price range set forth on the cover page of this prospectus);
•
assumes that the underwriters do not exercise their option to purchase additional shares of common stock; and
•
excludes shares of common stock that directors and executive officers may purchase through the reserved share program.
Risk Factors Summary
Investing in our common stock involves risks, including those highlighted in the section titled “Risk Factors” immediately following this prospectus summary, of which you should be aware before making a decision to invest in our common stock. These risks may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our common stock and a loss of all or part of your investment. These risks include, among others, the following:
26
Risks Related to Our Upstream Business and Industry
•
the volatility of natural gas and NGL prices due to factors beyond our control;
•
our reliance on a single third party for all of our natural gas marketing and another third party for substantially all of our natural gas and NGL midstream services with respect to the Barnett assets we acquired from Devon Energy;
•
our reserves estimates are based on assumptions that may prove to be inaccurate;
•
our ability to find or acquire additional natural gas and NGL reserves that are economically recoverable, including development of our proved undeveloped reserves and associated capital expenditures;
•
uncertainties in evaluating the expected benefits and potential liabilities of recoverable reserves;
•
risks and uncertainties related to drilling operations, which are high-risk and operationally complex;
•
the availability or cost of water, equipment, supplies, personnel and oilfield services;
•
our limited control over activities on properties we do not operate;
Risks Related to Our Power Generation Business
•
extreme weather, transmission congestion and changes to the regulatory environment;
•
the operation of our power generation business through a joint venture which we do not control;
•
risks and hazards related to the operation or maintenance of electric generation facilities, including disruption of the fuel supplies necessary to generate power at the Temple Plants;
•
the lack of long-term power sales agreements for the Temple Plants;
Risks Related to Our Retail Power Business
•
the operation of our retail power business through a joint venture which we do not control;
•
our ability to attract and retain customers in the competitive retail power marketplace;
•
market price risk and changes in law, regulation or market structure resulting in unanticipated costs;
•
our ability to maintain our retail electric provider certification;
Risks Related to Our CCUS Business
•
our ability to successfully pursue and develop our CCUS business, the associated material capital investments and any changes to financial and tax incentives;
Risks Related to Our Midstream Business
•
risks and hazards related to midstream operations as complex activities;
•
our dependence on our natural gas midstream system;
Risks Related to Our Business Generally
•
the geographical concentration of substantially all of our oil and gas and midstream properties;
•
the effect of a deterioration in general economic, business or industry conditions;
•
our ability to achieve our near term and long term net zero goals on our anticipated time frame;
•
our ability to generate cash flow to meet our debt obligations or fund our other liquidity needs;
•
events of default if we are unable to comply with restrictions in our debt agreements (including if after this offering, any person or group (other than Banpu and its controlled affiliates, excluding portfolio companies and operating companies) acquires 35% or more of our equity interests, or if any
27
person or group acquires a greater percentage of our equity interests than are then held by Banpu and its controlled affiliates (excluding portfolio companies and operating companies of Banpu);
•
risks related to our debt and debt agreements and hedging arrangements that expose us to risk of financial losses and counterparty credit risk;
•
our dependence, as a holding company, on our subsidiaries and our joint venture for cash;
•
operating hazards that could result in substantial losses or liabilities for which we may not have adequate insurance coverage;
•
our ability to make accretive acquisitions or successfully integrate acquired businesses or assets;
•
our substantial capital requirements and our ability to obtain financing or fund working capital needs;
•
the intense competition in the energy industry and our ability to compete with other companies;
•
cybersecurity or physical security threats or disruptions or loss of our information systems;
•
increased activism and negative investor sentiment regarding upstream activities and companies;
•
the loss of our executive officers and technical personnel and our ability to retain technical personnel;
•
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;
•
the effect of increased attention to ESG matters and environmental conservation measures;
•
reductions in demand for natural gas, NGL and oil;
•
risks related to climate change, including transitional, legal, political, financial and physical risks;
•
significant costs and liabilities related to environmental, health and safety laws and regulations;
•
potential tax law changes;
•
complex and evolving laws and regulations regarding privacy and data protection;
Risks Related to Our Relationship with Banpu and its Affiliates
•
the substantial influence of Banpu, our controlling stockholder, over us;
•
our historical reliance on Banpu for capital investments to fund our business operations;
•
we expect to be a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for and could rely on exemptions from certain corporate governance requirements;
•
conflicts of interest between Banpu and us or our other stockholders or conflicts of interest of our officers and/or directors as a result of their positions with, or ownership of common stock of, Banpu;
Risks Related to the Offering and Our Common Stock
•
our actual operating results and activities could differ materially from our estimates;
•
the impact of our lack of dividend payments on the market price of our common stock;
•
the costs of, and our ability to comply with, the requirements of being a public company;
•
we have identified material weaknesses in our internal control over financial reporting;
•
the lack of an existing market for our common stock;
•
provisions in our governing documents and Delaware law that could discourage acquisition bids or merger proposals; and
•
future sales of our common stock in the public market, or the perception that such sales may occur, could reduce our stock price.
28
Summary Historical Financial Information
The following table shows our summary historical consolidated financial information for the periods and as of the dates indicated. The summary historical consolidated financial information as of and for the six months ended June 30, 2024 and 2023 was derived from our unaudited historical condensed consolidated financial statements, included elsewhere in this prospectus. The summary historical consolidated financial information as of and for the years ended December 31, 2023, 2022 and 2021 was derived from our audited historical consolidated financial statements, included elsewhere in this prospectus.
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” included elsewhere in this prospectus, as well as our historical consolidated financial statements and related notes, and other financial information included in this prospectus. Historical results are not necessarily indicative of results that may be expected for any future period.
| | |
Six Months Ended
June 30, |
| |
Year Ended December 31,
|
| ||||||||||||||||||||||||
| | |
2024
|
| |
2023
|
| |
2023
|
| |
2022
|
| |
2021
|
| |||||||||||||||
| | |
(in thousands, except per share amounts)
|
| |||||||||||||||||||||||||||
Revenues and other operating income | | | | | | | | | | | | | | | | | | | | | | | | | | | |||||
Natural gas revenues
|
| | | $ | 179,175 | | | | | $ | 257,032 | | | | | $ | 509,846 | | | | | $ | 1,310,339 | | | | | $ | 597,050 | | |
NGL revenues
|
| | | | 84,632 | | | | | | 91,477 | | | | | | 187,860 | | | | | | 311,542 | | | | | | 225,135 | | |
Oil revenues
|
| | | | 3,734 | | | | | | 4,398 | | | | | | 8,445 | | | | | | 11,866 | | | | | | 7,560 | | |
Natural gas, NGL, and oil revenues
|
| | | | 267,541 | | | | | | 352,907 | | | | | | 706,151 | | | | | | 1,633,747 | | | | | | 829,745 | | |
Midstream revenues
|
| | | | 7,506 | | | | | | 8,428 | | | | | | 16,168 | | | | | | 12,676 | | | | | | 6,917 | | |
Derivative gains (losses), net
|
| | | | (11,165) | | | | | | 116,947 | | | | | | 238,743 | | | | | | (629,701) | | | | | | (383,847) | | |
Marketing revenues
|
| | | | 6,967 | | | | | | 4,732 | | | | | | 8,710 | | | | | | 11,001 | | | | | | 52,616 | | |
Gain on sale of assets
|
| | | | 6,784 | | | | | | 339 | | | | | | — | | | | | | — | | | | | | — | | |
Related party and other
|
| | | | 10,479 | | | | | | 3,314 | | | | | | 8,251 | | | | | | 2,799 | | | | | | 251 | | |
Total revenues and other operating income
|
| | | | 288,112 | | | | | | 486,667 | | | | | | 978,023 | | | | | | 1,030,522 | | | | | | 505,682 | | |
Operating expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Lease operating and workover
|
| | | | 68,640 | | | | | | 80,723 | | | | | | 150,647 | | | | | | 131,497 | | | | | | 86,831 | | |
Taxes other than income
|
| | | | 21,215 | | | | | | 41,496 | | | | | | 72,290 | | | | | | 114,668 | | | | | | 45,650 | | |
Gathering and transportation
|
| | | | 113,105 | | | | | | 120,586 | | | | | | 248,990 | | | | | | 208,758 | | | | | | 173,587 | | |
Depreciation, depletion, amortization, and accretion(1)
|
| | | | 111,479 | | | | | | 78,354 | | | | | | 223,370 | | | | | | 118,909 | | | | | | 92,277 | | |
General and administrative
|
| | | | 39,941 | | | | | | 52,488 | | | | | | 114,688 | | | | | | 148,559 | | | | | | 85,740 | | |
Other
|
| | | | 11,276 | | | | | | 8,483 | | | | | | 12,625 | | | | | | 3,567 | | | | | | 1,274 | | |
Total operating expenses
|
| | | | 365,656 | | | | | | 382,130 | | | | | | 822,610 | | | | | | 725,958 | | | | | | 485,359 | | |
Income (loss) from operations
|
| | | | (77,544) | | | | | | 104,537 | | | | | | 155,413 | | | | | | 304,564 | | | | | | 20,323 | | |
Other income (expense) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Bargain purchase gain
|
| | | | — | | | | | | — | | | | | | — | | | | | | 170,853 | | | | | | — | | |
Gain on settlement of litigation
|
| | | | — | | | | | | — | | | | | | — | | | | | | 16,866 | | | | | | — | | |
Gains (losses) on contingent consideration(2)
|
| | | | 6,070 | | | | | | 22,910 | | | | | | 38,375 | | | | | | 6,632 | | | | | | (194,968) | | |
Earnings (losses) from equity affiliate
|
| | | | (22,960) | | | | | | (14,275) | | | | | | 16,865 | | | | | | 8,493 | | | | | | 910 | | |
Loss on debt extinguishment
|
| | | | (13,877) | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Interest income
|
| | | | 3,404 | | | | | | 1,136 | | | | | | 3,138 | | | | | | 1,143 | | | | | | 8 | | |
Interest expense
|
| | | | (31,246) | | | | | | (34,377) | | | | | | (69,942) | | | | | | (26,322) | | | | | | — | | |
Interest expense, related party
|
| | | | (3,852) | | | | | | (3,083) | | | | | | (7,078) | | | | | | (10,846) | | | | | | (2,134) | | |
Other income
|
| | | | 350 | | | | | | 1,851 | | | | | | 8,372 | | | | | | 1,411 | | | | | | 872 | | |
Income (loss) before income taxes
|
| | | | (139,655) | | | | | | 78,699 | | | | | | 145,143 | | | | | | 472,794 | | | | | | (174,989) | | |
Income tax benefit (expense)
|
| | | | 41,373 | | | | | | (17,885) | | | | | | (28,225) | | | | | | (62,652) | | | | | | 40,526 | | |
Net income (loss) attributable to BKV Corporation
|
| | | | (98,282) | | | | | | 60,814 | | | | | | 116,918 | | | | | | 410,142 | | | | | | (134,463) | | |
29
| | |
Six Months Ended
June 30, |
| |
Year Ended December 31,
|
| ||||||||||||||||||||||||
| | |
2024
|
| |
2023
|
| |
2023
|
| |
2022
|
| |
2021
|
| |||||||||||||||
| | |
(in thousands, except per share amounts)
|
| |||||||||||||||||||||||||||
Less accretion of preferred stock to redemption
value |
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (3,745) | | |
Less preferred stock dividends
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (9,900) | | |
Less deemed dividend on redemption of preferred stock
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (22,606) | | |
Net income (loss) attributable to common stockholders
|
| | | | (98,282) | | | | | | 60,814 | | | | | | 116,918 | | | | | | 410,142 | | | | | | (170,714) | | |
Net income (loss) per common share(3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic
|
| | | $ | (1.48) | | | | | $ | 1.03 | | | | | $ | 1.93 | | | | | $ | 6.99 | | | | | $ | (2.92) | | |
Diluted
|
| | | $ | (1.48) | | | | | $ | 0.97 | | | | | $ | 1.82 | | | | | $ | 6.62 | | | | | $ | (2.92) | | |
Weighted average number of common shares outstanding(3)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic
|
| | | | 66,318 | | | | | | 58,779 | | | | | | 60,730 | | | | | | 58,659 | | | | | | 58,496 | | |
Diluted
|
| | | | 66,318 | | | | | | 62,434 | | | | | | 64,380 | | | | | | 61,990 | | | | | | 58,496 | | |
Balance sheet information (at period end): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents
|
| | | $ | 9,197 | | | | | $ | 22,421 | | | | | $ | 25,407 | | | | | $ | 153,128 | | | | | $ | 134,667 | | |
Restricted cash(4)
|
| | | $ | — | | | | | $ | — | | | | | $ | 139,662 | | | | | $ | — | | | | | $ | — | | |
Total natural gas properties, net
|
| | | $ | 1,911,235 | | | | | $ | 2,237,870 | | | | | $ | 2,125,442 | | | | | $ | 2,209,518 | | | | | $ | 1,176,117 | | |
Total assets
|
| | | $ | 2,247,510 | | | | | $ | 2,503,242 | | | | | $ | 2,683,146 | | | | | $ | 2,702,573 | | | | | $ | 1,620,828 | | |
Total liabilities
|
| | | $ | 858,480 | | | | | $ | 1,239,558 | | | | | $ | 1,197,979 | | | | | $ | 1,506,649 | | | | | $ | 865,889 | | |
Total mezzanine equity
|
| | | $ | 189,888 | | | | | $ | 142,149 | | | | | $ | 186,954 | | | | | $ | 151,883 | | | | | $ | 83,847 | | |
Total stockholders’ equity
|
| | | $ | 1,199,142 | | | | | $ | 1,121,535 | | | | | $ | 1,298,213 | | | | | $ | 1,044,041 | | | | | $ | 671,092 | | |
Statement of cash flows information | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net cash provided by operating activities
|
| | | $ | 9,782 | | | | | $ | 80,924 | | | | | $ | 123,076 | | | | | $ | 349,194 | | | | | $ | 358,133 | | |
Net cash provided by (used in) investing activities
|
| | | $ | 101,633 | | | | | $ | (128,606) | | | | | $ | (177,848) | | | | | $ | (865,566) | | | | | $ | (161,858) | | |
Net cash provided by (used in) financing activities
|
| | | $ | (267,287) | | | | | $ | (83,025) | | | | | $ | 66,713 | | | | | $ | 534,833 | | | | | $ | (79,053) | | |
Other financial data (unaudited)(5) | | | | | | | |||||||||||||||||||||||||
Adjusted EBITDAX
|
| | | $ | 108,837 | | | | | $ | 117,045 | | | | | $ | 251,158 | | | | | $ | 575,504 | | | | | $ | 281,024 | | |
Upstream capital expenditures (accrued)(6)
|
| | | $ | 25,528 | | | | | $ | 91,522 | | | | | $ | 107,544 | | | | | $ | 253,179 | | | | | $ | 77,634 | | |
Upstream Reinvestment Rate(6)
|
| | | | 23% | | | | | | 78% | | | | | | 43% | | | | | | 44% | | | | | | 28% | | |
Adjusted Free Cash Flow
|
| | | $ | 67,055 | | | | | $ | (11,389) | | | | | $ | 19,132 | | | | | $ | 169,213 | | | | | $ | 165,090 | | |
Adjusted Free Cash Flow Margin
|
| | | | 22% | | | | | | (3)% | | | | | | 3% | | | | | | 10% | | | | | | 19% | | |
Total Net Leverage Ratio
|
| | | | 1.84x | | | | | | 2.69x | | | | | | 1.95x | | | | | | 1.00x | | | | | | 0.11x | | |
(1)
Includes accretion of lease liabilities related to office space and compressor leases.
(2)
Represents contingent consideration liabilities as of the dates set forth above accruing as an earnout obligation under the terms of our purchase agreements with Devon Energy and ExxonMobil Corporation for the purchase of our 2020 Barnett Assets and 2022 Barnett Assets, respectively. Contingent consideration is stated at fair value on our condensed consolidated balance sheets, with changes in fair value recorded in the condensed consolidated statements of operations.
(3)
Per share data gives effect to the October 2023 one-for-two reverse stock split.
(4)
As of December 31, 2023, the restricted cash balance represents cash to fund our debt service reserve in accordance with the Term Loan Credit Agreement.
(5)
Adjusted EBITDAX, Adjusted Free Cash Flow, and Adjusted Free Cash Flow Margin 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 capital expenditures accrued for the development of natural gas properties during the period (excluding leasehold costs and
30
acquisitions) as a percentage of Adjusted EBITDAX for the same period, 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.
(6)
Upstream capital expenditures (accrued) for the six months ended June 30, 2024 includes $4.0 million of net cash not yet paid as of June 30, 2024 for capital expenditures incurred and accrued during the period. Upstream capital expenditures (accrued) for the six months ended June 30, 2023 and for the year ended December 31, 2023 does not include $21.6 million and $26.9 million, respectively, of net cash paid in 2023 for capital expenditures incurred and accrued during the year ended December 31, 2022. Upstream capital expenditures (accrued) for the years ended December 31, 2022 and 2021 includes $17.8 million and $13.7 million, respectively, of net cash paid in subsequent periods for capital expenditures incurred and accrued during the respective period presented. For a reconciliation of upstream capital expenditures (accrued) to cash flows used in development of natural gas properties in the condensed consolidated statements of cash flows, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Resources — Cash flows used in investing activities.”
Non-GAAP Financial Measures
Adjusted EBITDAX
We define Adjusted EBITDAX as net income (loss) attributable to BKV Corporation before (i) non-cash derivative gains (losses), (ii) depreciation, depletion, amortization and accretion, (iii) exploration and impairment expense, (iv) gains (losses) on contingent consideration liabilities, (v) interest expense, (vi) interest expense, related party, (vii) income tax benefit (expense), (viii) equity-based compensation expense, (ix) bargain purchase gains, (x) earnings or losses from equity affiliate, (xi) the portion of settlements paid (received) for early-terminated derivative contracts that relate to future periods and (xii) other nonrecurring transactions. Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by our management and external users of our consolidated financial statements, such as industry analysts, investors, lenders, rating agencies and others to more effectively evaluate our operating performance and results of operations from period to period and against our peers. We believe Adjusted EBITDAX is a useful performance measure because it allows us to effectively evaluate our operating performance and results of operations from period to period and against our peers, without regard to our financing methods, corporate form or capital structure.
We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) determined in accordance with GAAP. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax burden, as well as the historic costs of depreciable assets, none of which are reflected in Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Other companies, including other companies in our industry, may not use Adjusted EBITDAX or may calculate this measure differently than as presented in this prospectus, limiting its usefulness as a comparative measure.
The table below presents a reconciliation of Adjusted EBITDAX to net income, our most directly comparable GAAP financial measure for the periods indicated.
31
| | |
Six Months Ended
June 30, |
| |
Year Ended December 31,
|
| ||||||||||||||||||||||||
| | |
2024
|
| |
2023
|
| |
2023
|
| |
2022
|
| |
2021
|
| |||||||||||||||
| | |
(in thousands)
|
| |||||||||||||||||||||||||||
Net income (loss) attributable to BKV Corporation
|
| | | $ | (98,282) | | | | | $ | 60,814 | | | | | $ | 116,918 | | | | | $ | 410,142 | | | | | $ | (134,463) | | |
Unrealized derivative (gains)
losses |
| | | | 79,100 | | | | | | (46,245) | | | | | | (148,564) | | | | | | (58,815) | | | | | | 115,161 | | |
Forward month gas derivative settlement(1)
|
| | | | 83 | | | | | | (2,938) | | | | | | (9,807) | | | | | | (8,826) | | | | | | 15,406 | | |
Depreciation, depletion, amortization and accretion
|
| | | | 111,650 | | | | | | 79,026 | | | | | | 224,427 | | | | | | 130,038 | | | | | | 98,833 | | |
Exploration and impairment expense
|
| | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 34 | | |
Change in contingent consideration liabilities
|
| | | | (6,070) | | | | | | (22,910) | | | | | | (38,375) | | | | | | (6,632) | | | | | | 194,968 | | |
Interest expense
|
| | | | 31,246 | | | | | | 34,377 | | | | | | 69,942 | | | | | | 26,322 | | | | | | — | | |
Interest expense, related party
|
| | | | 3,852 | | | | | | 3,083 | | | | | | 7,078 | | | | | | 10,846 | | | | | | 2,134 | | |
Loss on debt extinguishment
|
| | | | 13,877 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
Income tax expense (benefit)
|
| | | | (41,373) | | | | | | 17,885 | | | | | | 28,225 | | | | | | 62,652 | | | | | | (40,526) | | |
Equity-based compensation
expense |
| | | | 2,145 | | | | | | 10,295 | | | | | | 25,756 | | | | | | 31,947 | | | | | | 30,387 | | |
Bargain purchase gain
|
| | | | — | | | | | | — | | | | | | — | | | | | | (170,853) | | | | | | — | | |
Gain on sales of non-operated interest in proved reserves
|
| | | | (5,451) | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | |
(Earnings) losses from equity affiliate
|
| | | | 22,960 | | | | | | 14,275 | | | | | | (16,865) | | | | | | (8,493) | | | | | | (910) | | |
Total settlements paid (received) for early-terminated derivative contracts during the
period(2) |
| | | | (13,250) | | | | | | (39,124) | | | | | | (46,701) | | | | | | 158,448 | | | | | | — | | |
Settlements (paid) received for early-terminated derivative contracts related to the period presented(3)
|
| | | | 8,350 | | | | | | 8,507 | | | | | | 39,124 | | | | | | (1,272) | | | | | | — | | |
Adjusted EBITDAX
|
| | | $ | 108,837 | | | | | $ | 117,045 | | | | | $ | 251,158 | | | | | $ | 575,504 | | | | | $ | 281,024 | | |
(1)
Natural gas derivative contracts settle and are realized in the month prior to the production covered by the contract. This adjustment removes the timing difference between the settlement date and the underlying production month that is hedged.
(2)
Reflects total cash settlements paid (received) during the period upon termination of certain natural gas commodity derivative swap and collar contracts prior to their contractual settlement dates.
(3)
When calculating Adjusted EBITDAX for purposes of evaluating our operating performance and results of operations, cash settlements (paid) received for early-terminated derivative contracts are “related to” the period that includes the underlying production month that was hedged. This adjustment removes the timing difference between the early termination date and the underlying production month that is hedged. The table below shows the portion of total cash settlements (paid) received for early-terminated derivative contracts related to the respective periods presented.
32
| | |
Six Months Ended
June 30, |
| |
Year Ended December 31,
|
| ||||||||||||||||||||||||
| | |
2024
|
| |
2023
|
| |
2023
|
| |
2022
|
| |
2021
|
| |||||||||||||||
Total cash settlements paid (received) for early-terminated derivative contracts during the period
|
| | | $ | (13,250) | | | | | $ | (39,124) | | | | | $ | (46,701) | | | | | $ | 158,448 | | | | | $ | — | | |
Cash settlements (paid) received for early-terminated
derivative contracts related to the period presented |
| | | | 8,350 | | | | | $ | 8,507 | | | | | | 39,124 | | | | | | (1,272) | | | | | | — | | |
Cash settlements paid (received) for early-terminated
derivative contracts related to future periods |
| | | $ | (4,900) | | | | | $ | (30,617) | | | | | $ | (7,577) | | | | | $ | 157,176 | | | | | $ | — | | |
Adjusted Free Cash Flow
We define Adjusted Free Cash Flow as net cash provided by (used in) operating activities, excluding cash paid for contingent consideration and changes in operating assets and liabilities, less total cash paid for capital expenditures (excluding leasehold costs and acquisitions).
Adjusted Free Cash Flow is not a measure of net cash flow provided by or used in operating activities as determined by GAAP. Adjusted Free Cash Flow is a supplemental non-GAAP financial measure that is used by our management and other external users of our financial statements, such as industry analysts, investors, lenders, rating agencies and others to assess our ability to internally fund our capital program, service or incur additional debt and to pay dividends. We believe Adjusted Free Cash Flow is a useful liquidity measure because it allows us and others to compare cash flow provided by operating activities across periods and to assess our ability to internally fund our capital program (including acquisitions), to reduce leverage, fund acquisitions and pay dividends to our stockholders. Adjusted Free Cash Flow should not be considered as an alternative to, or more meaningful than, net income (loss) or net cash provided by (used in) operating activities determined in accordance with GAAP. Other companies, including other companies in our industry, may not use Adjusted Free Cash Flow or may calculate this measure differently than as presented in this prospectus, limiting its usefulness as a comparative measure.
The table below presents our reconciliation of Adjusted Free Cash Flow to net cash provided by operating activities, our most directly comparable GAAP financial measure for the periods indicated.
| | |
Six Months Ended
June 30, |
| |
Year Ended December 31,
|
| ||||||||||||||||||||||||
| | |
2024
|
| |
2023
|
| |
2023
|
| |
2022
|
| |
2021
|
| |||||||||||||||
| | |
(in thousands)
|
| |||||||||||||||||||||||||||
Net cash provided by operating activities
|
| | | $ | 9,782 | | | | | $ | 80,924 | | | | | $ | 123,076 | | | | | $ | 349,194 | | | | | $ | 358,133 | | |
Cash paid for contingent consideration(1)
|
| | | | 20,000 | | | | | | 65,000 | | | | | | 65,000 | | | | | | 45,300 | | | | | | — | | |
Changes in operating assets and liabilities
|
| | | | 68,395 | | | | | | (32,008) | | | | | | 18,437 | | | | | | 22,816 | | | | | | (126,862) | | |
Cash paid for capital expenditures
|
| | | | (31,122) | | | | | | (125,305) | | | | | | (187,381) | | | | | | (248,097) | | | | | | (66,181) | | |
Adjusted Free Cash Flow(2)
|
| | | $ | 67,055 | | | | | $ | (11,389) | | | | | $ | 19,132 | | | | | $ | 169,213 | | | | | $ | 165,090 | | |
(1)
Cash paid for contingent consideration is included as a deduction to arrive at net cash provided by (used in) operating activities and therefore, is added back for the purpose of computing Adjusted Free Cash Flow.
(2)
The early termination of derivative contracts increased Adjusted Free Cash Flow by $13.3 million, $39.1 million, and $46.7 million during the six months ended June 30, 2024 and 2023, and for the year ended December 31, 2023, respectively, and decreased Adjusted Free Cash Flow by $158.4 million during the year ended December 31, 2022. In addition, Adjusted Free Cash Flow increased by $23.5 million for the six months ended June 30, 2024 due to the net premium received of $23.5 million from the sale of a call option.
33
Summary Reserves, Production and Operating Data
Ryder Scott, our independent petroleum engineers, prepared estimates of our natural gas, NGL and oil reserves as of December 31, 2023, 2022 and 2021. These reserves estimates were prepared in accordance with the rules and regulations of the SEC regarding oil and natural gas reserves reporting using an average price equal to the unweighted arithmetic average of hydrocarbon prices on the first day of each month within the 12-month period as adjusted for location and quality differentials, unless prices are defined by contractual arrangements, excluding escalations based on future conditions (“SEC Pricing”) (except for the table that provides our estimated reserves as of December 31, 2023 at “NYMEX strip pricing” using pricing based on NYMEX future prices as of market close on December 31, 2023). For more information about our reserves volumes and values, see “Business — Preparation of Reserves Estimates and Internal Controls” and Ryder Scott’s summary reserves reports, which are filed as exhibits to the registration statement of which this prospectus forms a part.
The following table provides our estimated proved reserves information prepared by Ryder Scott as of December 31, 2023, 2022 and 2021 and PV-10 Value and the standardized measure of discounted future net cash flows (the “Standardized Measure”) for each period. The decrease in our proved reserves and the PV-10 Value of those reserves as of December 31, 2023, as compared to December 31, 2022, is primarily due to lower commodity pricing. The increase in our proved reserves and the PV-10 Value of those reserves as of December 31, 2022, as compared to December 31, 2021, was primarily due to the Exxon Barnett Acquisition that we consummated on June 30, 2022. There are numerous uncertainties inherent in estimating quantities of natural gas, NGL and oil reserves and their values, including many factors beyond our control. See “Risk Factors — Risks Related to Our Upstream Business and Industry — Our estimated natural gas, NGL and oil reserves quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in the reserves estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.”
Estimated Reserves at SEC Pricing(1)
| | |
December 31,
|
| |||||||||||||||
| | |
2023
|
| |
2022
|
| |
2021
|
| |||||||||
Estimated proved developed reserves: | | | | | | | | | | | | | | | | | | | |
Natural gas (MMcf)
|
| | | | 2,443,072 | | | | | | 3,798,019 | | | | | | 2,494,925 | | |
Producing
|
| | | | 2,290,025 | | | | | | 3,468,896 | | | | | | 2,346,712 | | |
Non-producing
|
| | | | 153,047 | | | | | | 329,123 | | | | | | 148,213 | | |
Natural gas liquids (MBbls)
|
| | | | 156,399 | | | | | | 170,840 | | | | | | 151,433 | | |
Producing
|
| | | | 129,260 | | | | | | 157,585 | | | | | | 142,961 | | |
Non-producing
|
| | | | 27,139 | | | | | | 13,255 | | | | | | 8,472 | | |
Oil (MBbls)
|
| | | | 992 | | | | | | 1,111 | | | | | | 867 | | |
Producing
|
| | | | 802 | | | | | | 1,111 | | | | | | 867 | | |
Non-producing
|
| | | | 190 | | | | | | — | | | | | | — | | |
Total estimated proved developed reserves (MMcfe)
|
| | | | 3,387,418 | | | | | | 4,829,733 | | | | | | 3,408,725 | | |
Producing
|
| | | | 3,070,397 | | | | | | 4,421,072 | | | | | | 3,209,680 | | |
Non-producing
|
| | | | 317,021 | | | | | | 408,653 | | | | | | 199,045 | | |
Standardized Measure (millions)
|
| | | $ | 986 | | | | | $ | 5,809 | | | | | $ | 2,119 | | |
PV-10 (millions)(2)(3)
|
| | | $ | 1,151 | | | | | $ | 7,389 | | | | | $ | 2,672 | | |
34
| | |
December 31,
|
| |||||||||||||||
| | |
2023
|
| |
2022
|
| |
2021
|
| |||||||||
Estimated proved undeveloped reserves: | | | | | | | | | | | | | | | | | | | |
Natural gas (MMcf)
|
| | | | 539,423 | | | | | | 1,057,657 | | | | | | 950,358 | | |
Natural gas liquids (MBbls)
|
| | | | 27,766 | | | | | | 40,660 | | | | | | 13,722 | | |
Oil (MBbls)
|
| | | | 59 | | | | | | 758 | | | | | | 58 | | |
Total estimated proved undeveloped reserves (MMcfe)(4)(5)
|
| | | | 706,373 | | | | | | 1,306,157 | | | | | | 1,033,038 | | |
Standardized Measure (millions)
|
| | | $ | 48 | | | | | $ | 1,185 | | | | | $ | 295 | | |
PV-10 (millions)(2)(6)
|
| | | $ | 81 | | | | | $ | 1,566 | | | | | $ | 403 | | |
Estimated total proved reserves: | | | | | | | | | | | | | | | | | | | |
Natural gas (MMcf)
|
| | | | 2,982,495 | | | | | | 4,855,676 | | | | | | 3,445,283 | | |
Natural gas liquids (MBbls)
|
| | | | 184,165 | | | | | | 211,500 | | | | | | 165,155 | | |
Oil (MBbls)
|
| | | | 1,051 | | | | | | 1,869 | | | | | | 925 | | |
Total estimated proved reserves (MMcfe)
|
| | | | 4,093,791 | | | | | | 6,135,890 | | | | | | 4,441,763 | | |
Standardized Measure (millions)
|
| | | $ | 1,034 | | | | | $ | 6,994 | | | | | $ | 2,414 | | |
PV-10 (millions)(2)(7)
|
| | | $ | 1,232 | | | | | $ | 8,955 | | | | | $ | 3,075 | | |
(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 December 31, 2023 were $2.637 per MMBtu (Henry Hub), $78.22 per Bbl (WTI Cushing) and NGL pricing equal to 29.5% of WTI Cushing, (ii) at December 31, 2022 were $6.358 per MMBtu (Henry Hub), $93.67 per Bbl (WTI Cushing) and NGL pricing equal to 36.7% of WTI Cushing and (iii) at December 31, 2021 were $3.598 per MMBtu (Henry Hub), $66.56 per Bbl (WTI Cushing) and NGL pricing equal to 39.5% of WTI Cushing.
(2)
PV-10 refers to the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. PV-10 is not a financial measure calculated in accordance with GAAP because it does not include the effects of income taxes on future net revenues. PV-10 is derived from the Standardized Measure, which is the most directly comparable GAAP financial measure. Neither PV-10 nor Standardized Measure represent an estimate of the fair market value of our oil and natural gas properties. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and gas properties. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the Standardized Measure reported in accordance with GAAP, but rather should be considered in addition to the Standardized Measure.
(3)
The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated proved developed reserves as of December 31, 2023, 2022 and 2021:
| | |
December 31,
|
| |||||||||||||||
| | |
2023
|
| |
2022
|
| |
2021
|
| |||||||||
PV-10 (millions)
|
| | | $ | 1,151 | | | | | $ | 7,389 | | | | | $ | 2,672 | | |
Present value of future income taxes discounted at 10%
|
| | | | (165) | | | | | | (1,580) | | | | | | (553) | | |
Standardized Measure
|
| | | $ | 986 | | | | | $ | 5,809 | | | | | $ | 2,119 | | |
35
(4)
Proved undeveloped reserves as of December 31, 2023 are part of a development plan that has been adopted by management indicating that such locations are scheduled to be drilled within five years. Proved undeveloped reserves as of December 31, 2022 and 2021 were part of a development plan adopted by management indicating that such locations were scheduled to be drilled within five years of initial booking.
(5)
Sustained lower prices for oil and natural gas may cause us to forecast less capital to be available for development of our proved undeveloped reserves, which may cause us to decrease the amount of our proved undeveloped reserves we expect to develop within the allowed time frame. In addition, lower oil and natural gas prices may cause our proved undeveloped reserves to become uneconomic to develop, which would cause us to remove them from their respective reserves category.
(6)
The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated proved undeveloped reserves as of December 31, 2023, 2022 and 2021:
| | |
December 31,
|
| |||||||||||||||
| | |
2023
|
| |
2022
|
| |
2021
|
| |||||||||
PV-10 (millions)
|
| | | $ | 81 | | | | | $ | 1,566 | | | | | $ | 403 | | |
Present value of future income taxes discounted at 10%
|
| | | | (33) | | | | | | (381) | | | | | | (108) | | |
Standardized Measure
|
| | | $ | 48 | | | | | $ | 1,185 | | | | | $ | 295 | | |
(7)
The following table provides a reconciliation of the Standardized Measure to PV-10 with respect to estimated proved reserves as of December 31, 2023, 2022 and 2021:
| | |
December 31,
|
| |||||||||||||||
| | |
2023
|
| |
2022
|
| |
2021
|
| |||||||||
PV-10 (millions)
|
| | | $ | 1,232 | | | | | $ | 8,955 | | | | | $ | 3,074 | | |
Present value of future income taxes discounted at 10%
|
| | | | (198) | | | | | | (1,961) | | | | | | (661) | | |
Standardized Measure
|
| | | $ | 1,034 | | | | | $ | 6,994 | | | | | $ | 2,413 | | |
During the years ended December 31, 2023, 2022 and 2021, we incurred costs of approximately $37.7 million, $54.0 million and $7.2 million, respectively, to convert 31.9 Bcfe, 74.0 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 December 31, 2023, 2022 and 2021 are approximately $360.7 million, $1,089.6 million and $578.3 million, respectively, over the next five years, substantially all of which we expect to finance through cash flow from operations and/or borrowings under our RBL Credit Agreement. Our development programs through the year ended December 31, 2023 focused on refracturing under-stimulated wells and designing and drilling new wells in both our Barnett and NEPA assets. Our proved undeveloped reserves, as of December 31, 2023, are scheduled to be developed within five years of their initial disclosure. 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.”
Natural gas prices decreased significantly during 2023 and are projected to remain lower than the near-record high prices experienced in 2022. Due to our desire to be a prudent operator and exercise capital discipline in this pricing environment, subsequent to finalizing our reserve reports as of December 31, 2023, we decreased our capital expenditures budget for development of natural gas properties for 2024 to approximately $13.6 million from our original budget of approximately $74.6 million, which was the amount applied in connection with the preparation of the estimates of our reserves as of December 31, 2023. We estimate that this reduction in our 2024 capital expenditures would result in a decrease in our proved reserves, standardized measure value of proved reserves, and the PV-10 value of proved reserves as of December 31, 2023 by approximately 3.3%, 1.6%, and 2.0%, respectively. If the current lower natural gas commodity pricing environment extends beyond 2024, we will continue to maintain capital discipline and reflect corresponding capital expenditure changes in our estimated reserves. These changes would mainly impact proved undeveloped reserves and proved developed non-producing reserves, which collectively represent approximately 25% of our total estimated proved reserves as of December 31, 2023.
36
2023 Activity
During the year ended December 31, 2023, the Company’s proved reserves decreased by 2,042.1 Bcfe. The decrease in proved reserves was primarily attributable to decreased commodity pricing and changes in the Company’s drilling activity, which resulted in total downward revisions of 1,986.3 Bcfe. As discussed below, these decreases were partially offset by extensions and discoveries and improved recoveries experienced by the Company in 2023, which resulted in net increases to proved reserves of 227.8 Bcfe and 30.2 Bcfe, respectively. The Company produced 313.8 Bcfe during the year ended December 31, 2023.
Revisions of previous estimates primarily consisted of downward revisions to proved developed reserves and proved undeveloped reserves of 1,191.9 Bcfe and 273.1 Bcfe, respectively, as a result of lower average pricing during 2023 for natural gas, NGLs, and oil. Additional downward revisions were made to proved undeveloped reserves of 521.3 Bcfe due to the Company’s lower capital spend and the resulting reduction in drilling activity during 2023. Changes to the Company’s drilling schedule moved the development of 112.0 gross (104.6 net) locations in NEPA and the Barnett beyond the SEC requirement of developing PUDs five years from initial booking. These 112.0 gross (104.6 net) locations remain in the Company’s inventory of unproved locations to be developed outside of the next five years. The drilling schedule changes reflect the Company’s ongoing commitment to optimize the long-term plan to best develop its assets, maximize cash flow, and produce economic returns.
Extensions and discoveries primarily consisted of 226.5 Bcfe of proved undeveloped reserves, of which 197.8 Bcfe was attributable to 22.0 gross (21.2 net) locations recognized as a result of the Company’s optimized drilling program, which reduced costs and extended lateral lengths. In addition, 28.7 Bcfe was attributable to extensions related to 3.0 gross (1.1 net) locations in NEPA. Our unitization and combination of acreage with Repsol resulted in the three additional locations.
Improved recoveries consisted of 30.2 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, 2023.
Conversions of proved undeveloped reserves to proved developed reserves consisted of 31.9 Bcfe related to the completion of 22.0 gross (8.1 net) wells on proved undeveloped locations during the year ended December 31, 2023.
2022 Activity
During the year ended December 31, 2022, the Company’s proved reserves increased by 1,694.1 Bcfe. The increase in proved reserves was primarily due to the acquisition of the 2022 Barnett Assets. Other factors that contributed to the increase in proved reserves during 2022 included increasing commodity pricing, which improved economics, improved recoveries due to the application of restimulation technology to producing wells and the addition of NGL rich locations to the drilling schedule. The Company produced 279.5 Bcfe during the year ended December 31, 2022.
Revisions of previous estimates consisted of upward revisions to proved developed reserves of 182.9 Bcfe as a result of higher average pricing during 2022 for natural gas, NGLs and oil. An additional upward revision of 52.0 Bcfe was made to proved developed reserves for performance adjustments. Upward revisions were offset by downward revisions to proved undeveloped reserves of 246.0 Bcfe relating to 76.0 gross (53.1 net) locations in NEPA and the Barnett that were removed from the drilling schedule in exchange for locations with more favorable economics, as discussed in the following explanation of extensions and discoveries in 2022. Additional downward revisions of 67.3 Bcfe and 42.9 Bcfe were made to proved undeveloped reserves related to performance and increased development costs, respectively.
Extensions and discoveries primarily consisted of the addition of 389.5 Bcfe of proved undeveloped reserves from 71.0 gross (66.4 net) locations recognized as a result of our revised evaluation of properties acquired through our Devon Barnett Acquisition. The added locations are more rich in NGLs than the previously recognized locations that were removed from the 2021 drilling schedule, as discussed in the preceding explanation of revisions of previous estimates in 2022. Additional extensions consisted of proved undeveloped reserves of 85.8 Bcfe related to 27.0 gross (12.8 net) locations in NEPA and the Barnett that were recognized from acreage acquired in 2021 and as a result of the revised 2022 drilling plan. Extensions
37
related to proved developed reserves of 74.1 Bcfe consisted of 23.0 gross (13.0 net) newly drilled wells on locations previously classified as unproved.
Purchases of minerals in place consisted of 1,237.1 Bcfe and 227.9 Bcfe of proved developed and proved undeveloped reserves, respectively, from the Exxon Barnett Acquisition. The acquired reserves consisted of operated working interests in 2,289.0 gross (1,696.4 net) wells and 53.0 gross (48.7 net) undeveloped locations.
Improved recoveries consisted of 80.5 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, 2022.
Conversions of proved undeveloped reserves to proved developed reserves consisted of 73.9 Bcfe related to the completion of 19.0 gross (5.5 net) wells on proved undeveloped locations during the year ended December 31, 2022.
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 evaluation of properties acquired through our Devon Barnett Acquisition, 550.1 Bcfe of proved undeveloped reserves was recognized for 123.0 gross (94.8 net) locations added to the Company’s revised drilling schedule during 2021. Additional extensions consisted of proved undeveloped reserves of 162.5 Bcfe related to 13.0 gross (9.6 net) locations in NEPA recognized from acquired acreage and the revised 2021 drilling plan. Extensions related to proved developed reserves of 15.4 Bcfe consisted of 10.0 gross (3.0 net) newly drilled wells.
Purchases of minerals in place consisted of 17.7 Bcfe of proved developed reserves from the acquisition of additional working interests in 601.0 gross (14.6 net) wells and 1.8 Bcfe of proved undeveloped reserves from the acquisition of additional working interests in 18.0 gross (1.0 net) locations, each of which were in addition to the Company’s previously held working interests in wells or working interests in locations in the Barnett.
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.
Conversions of proved undeveloped reserves to proved developed reserves consisted of 19.4 Bcfe related to the completion of 4.0 gross (3.9 net) wells on proved undeveloped locations during the year ended December 31, 2021.
Estimated Reserves at NYMEX Strip Pricing
The following table provides our total estimated proved reserves information prepared by Ryder Scott as of December 31, 2023, using NYMEX strip prices as of market close on December 31, 2023 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 December 31, 2023. The historical 12-month pricing average in our December 31, 2023 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
38
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 December 31, 2023. 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. See “Risk Factors — Risks Related to Our Upstream Business and Industry — Our estimated natural gas, NGL and oil reserves quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in the reserves estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.”
| | |
December 31,
2023 |
| |||
Estimated proved developed reserves at NYMEX Strip Pricing: | | | | | | | |
Natural gas (MMcf)
|
| | | | 2,984,949 | | |
Producing
|
| | | | 2,791,791 | | |
Non-producing
|
| | | | 193,158 | | |
Natural gas liquids (MBbls)
|
| | | | 164,204 | | |
Producing
|
| | | | 134,689 | | |
Non-producing
|
| | | | 29,515 | | |
Oil (MBbls)
|
| | | | 1,046 | | |
Producing
|
| | | | 808 | | |
Non-producing
|
| | | | 238 | | |
Total estimated proved developed reserves (MMcfe)
|
| | | | 3,976,436 | | |
Producing
|
| | | | 3,604,773 | | |
Non-producing
|
| | | | 371,663 | | |
Standardized Measure (millions)
|
| | | $ | 1,651 | | |
PV-10 (millions)(1)
|
| | | $ | 2,015 | | |
Estimated proved undeveloped reserves at NYMEX Strip Pricing: | | | | | | | |
Natural gas (MMcf)
|
| | | | 790,838 | | |
Natural gas liquids (MBbls)
|
| | | | 30,500 | | |
Oil (MBbls)
|
| | | | 59 | | |
Total estimated proved undeveloped reserves (MMcfe)(2)(3)
|
| | | | 974,192 | | |
Standardized Measure (millions)
|
| | | $ | 244 | | |
PV-10 (millions)(4)
|
| | | $ | 335 | | |
Estimated total proved reserves at NYMEX Strip Pricing: | | | | | | | |
Natural gas (MMcf)
|
| | | | 3,775,787 | | |
Natural gas liquids (MBbls)
|
| | | | 194,704 | | |
Oil (MBbls)
|
| | | | 1,105 | | |
Total estimated proved reserves (MMcfe)
|
| | | | 4,950,628 | | |
Standardized Measure (millions)
|
| | | $ | 1,895 | | |
PV-10 (millions)(5)
|
| | | $ | 2,350 | | |
(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 December 31, 2023:
| | |
December 31,
2023 |
| |||
PV-10 (millions)
|
| | | $ | 2,015 | | |
Present value of future income taxes discounted at 10%
|
| | | | (364) | | |
Standardized Measure
|
| | | $ | 1,651 | | |
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(2)
Proved undeveloped reserves as of December 31, 2023 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 proved undeveloped reserves, which may cause us to decrease the amount of our proved undeveloped reserves we expect to develop within the allowed time frame. In addition, lower oil and natural gas prices may cause our proved undeveloped reserves to become uneconomic to develop, which would cause us to remove them from their respective reserves 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 December 31, 2023:
| | |
December 31,
2023 |
| |||
PV-10 (millions)
|
| | | $ | 335 | | |
Present value of future income taxes discounted at 10%
|
| | | | (91) | | |
Standardized Measure
|
| | | $ | 244 | | |
(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 December 31, 2023:
| | |
December 31,
2023 |
| |||
PV-10 (millions)
|
| | | $ | 2,350 | | |
Present value of future income taxes discounted at 10%
|
| | | | (455) | | |
Standardized Measure
|
| | | $ | 1,895 | | |
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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 or prospects. 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 capital expenditures and meet our debt service obligations.
Our revenues, operating results, available cash and the carrying value of our natural gas properties, as well as our ability to make capital expenditures (including the $36.0 million estimated total project cost of the Barnett Zero Project, the $9.0 million we expect to contribute to BKV-BPP Cotton Cove to fund our portion of the estimated total cost of the Cotton Cove Project and the $57.0 million (inclusive of funding to date of $26.0 million) we expect to invest in BKVerde before the end of 2025 in connection with our efforts to develop potential CCUS projects) and meet our debt service obligations and other financial commitments, depend significantly upon the prevailing market prices for natural gas and NGLs. According to the U.S. Energy Information Administration (the “EIA”), the historical high and low Henry Hub natural gas spot prices per MMBtu for the following periods were as follows: in 2021, high of $23.86 and low of $2.43; in 2022, high of $9.85 and low of $3.46; in 2023, high of $3.78 and low of $1.74; and for the six months ended June 30, 2024, high of $13.20 and low of $1.25.
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 conflicts between Russia and Ukraine and Israel and Hamas, 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 (including any variants thereof, “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;
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•
weather conditions and other natural disasters;
•
domestic and foreign governmental regulations, including environmental initiatives and taxation;
•
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 period from January 1, 2021 through June 30, 2024, the Henry Hub natural gas spot price reached a high of $23.86 per MMBtu on February 17, 2021 and a low of $1.25 per MMBtu on March 13, 2024. Henry Hub natural gas spot prices trended higher after the Russia-Ukraine conflict first commenced, rising from $4.78 per MMBtu on February 24, 2022 to a high of $9.85 per MMBtu on August 22, 2022, according to the EIA; however, such prices subsequently dropped to $3.52 per MMBtu on December 31, 2022, as a result of a warmer-than-normal winter, and then to a recent low of $1.25 per MMBtu on March 13, 2024 due to a combination of higher production and higher storage inventories given a mild winter. Prices continued to hover on average between $1.50 to $2.50 in the first half of 2024 with overall lower natural gas consumption and higher storage inventory levels during the 2023-2024 winter.
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 61% for the six months ended June 30, 2024 and for the year ended December 31, 2023, and 69% and 77%, for the years ended December 31, 2022 and 2021, respectively, of our total natural gas and NGL production 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.
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 and results of operations 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.
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Our estimated natural gas, NGL and oil reserves quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in the reserves estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.
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 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 reserves estimates. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas, NGL and oil attributable to any particular group of properties, the classifications of reserves based on risk of non-recovery and estimates of future net cash flows.
The present value of future net revenues from our proved natural gas, NGL and oil reserves, or PV-10, will not necessarily be the same as the current market value of our estimated proved natural gas, NGL and oil reserves.
You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated natural gas, NGL and oil reserves. We currently base the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months. Actual future net revenues from our natural gas, NGL and oil reserves will be affected by factors such as:
•
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.
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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 December 31, 2023, approximately 706.4 Bcfe, or 17.3%, of our total estimated proved reserves were undeveloped or behind pipe. The reserves data included in our reserves 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 may require us to revise 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 reserves estimates, which could have a material adverse effect on our financial condition, future cash flows and results of operations.
As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures, as compared to the completion cost of a vertical well and therefore may result in fewer wells being completed in any given year. The incremental required capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.
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.
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We periodically evaluate our unproved natural gas, NGL and oil properties to determine recoverability of our costs and could be required to recognize non-cash charges in the earnings of future periods.
As of June 30, 2024, we carried unproved natural gas, NGL and oil property costs of $10.5 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 reserves potential, identify liabilities associated with such properties or obtain protection from sellers against such liabilities.
Acquiring natural gas and NGL properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential liabilities, including environmental liabilities. Such assessments are inherently inexact and uncertain. For these reasons, the properties we have acquired or will acquire in the future may not produce as projected. Further, the annual decline rates of reserves are estimated decline rates, which could ultimately be materially different than actual annual decline rates. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. We perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
Our failure to correctly assess reservoir and infrastructure characteristics of the natural gas and NGL properties that we acquire or have acquired, or to identify material defects or liabilities associated with such properties, or actual decline rates that differ materially from estimated decline rates, could have a material adverse effect on our financial condition, results of operations and cash flows.
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 June 30, 2024, provided us with a network of approximately 1,193,000 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 June 30, 2024, provided BKV-BPP Power with a combined 200,000 MMBtu/d of firm transportation with Atmos and Energy Transfer and 2,812,500 MMBtu of firm storage with Energy Transfer. We are obligated under these arrangements to
45
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. As of June 30, 2024, our minimum aggregate required payments per year under firm gathering and transportation agreements are approximately $34.5 million for 2024, $68.2 million for 2025, $66.4 million for 2026, $58.6 million for 2027, $53.2 million for 2028 and $73.2 for 2029 and beyond. See “Business — Marketing and Differentials.”
If our anticipated production does not exceed the minimum quantities provided in the agreements, and we are unable to purchase natural gas and NGLs from third parties or release our capacity to other shippers, then our margins, results of operations and financial performance could be adversely affected.
Drilling for natural gas wells is a high-risk activity with many uncertainties that could adversely affect our business, financial condition or results of operations.
Drilling natural gas wells, including development wells, involves numerous risks, including the risk that we may not encounter commercially productive natural gas and NGL reserves (including “dry holes”). We must incur significant expenditures to drill and complete wells, the costs of which are often uncertain. It is possible that we will make substantial expenditures on drilling and not discover reserves in commercially viable quantities.
Specifically, we often are uncertain as to the future cost or timing of drilling, completing and operating wells, and our drilling operations and those of our third-party operators may be curtailed, delayed or canceled. The cost of our drilling, completing and well operations may increase and our results of operations and cash flows from such operations may be impacted, as a result of a variety of factors, including:
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unexpected drilling conditions;
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title problems;
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pressure or irregularities in formations;
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equipment failures or accidents;
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adverse weather conditions, such as winter storms, flooding and hurricanes, and changes in weather patterns;
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compliance with, or changes in, environmental laws and regulations relating to air emissions, hydraulic fracturing and disposal of produced water, drilling fluids and other wastes, laws and regulations imposing conditions and restrictions on drilling and completion operations and other laws and regulations, such as tax laws and regulations;
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the availability and timely issuance of required governmental permits and licenses; and
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the availability of, costs associated with, and terms of contractual arrangements for, properties, including mineral licenses and leases, pipelines, facilities and equipment to gather, process, compress, store, transport and market natural gas and NGLs and related commodities.
For instance, in our drilling operations across NEPA and the Barnett from time to time we experience certain issues and the occurrence of risks, including, for example, mechanical and instrument or tool failures, drilling difficulties associated with drilling in swelling clay or shales and unconsolidated formation, particularly in certain parts of our Barnett development acreage, wellbore instability and other geological hazards, loss of well control, loss of drilling fluids, inability to establish fluid circulation, loss of drill pipe, loss of casing integrity, stuck tools and drill pipes, insufficient cementing of casing, among other typical shale drilling challenges.
Our failure to recover our investment in wells, increases in the costs of our drilling operations or those of our third-party operators, and/or curtailments, delays or cancellations of our drilling operations or those of our third-party operators in each case due to any of the above factors or other factors, may materially and adversely affect our business, financial condition and results of operations.
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Drilling, completions, workover and hydraulic fracturing operations are operationally complex activities which present certain risks that could adversely affect our business, financial condition or results of operations.
In our drilling operations, from time to time we experience certain issues and encounter risks, including, for example, mechanical and instrument or tool failures; drilling difficulties associated with drilling in swelling clay or shales and unconsolidated formation, particularly in select parts of our Barnett development acreage; wellbore instability and other geological hazards; loss of well control and associated hydrocarbon release and/or natural gas clouds; loss of drilling fluids circulation; surface spills of various drilling or well fluids; subsurface collision with existing wells; proximity of adjacent water wells or aquifers; inability to establish drilling fluid circulation; loss or compromise of drill pipe or casing integrity; surface pumping operations and associated pressure and hydrocarbon hazards; stuck and lost-in-hole tools, drill pipe or casing; large drilling equipment and machinery including electrical hazards; insufficient cementing of casing causing unwanted casing pressure or fluid migration; surface overpressure events from large machinery (horsepower), equipment or well pressure; fines and violations related to relevant laws and regulations; fires and explosions; personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation and trenching and more; structural damage and collapse to large equipment and machinery; major damage or malfunction to key equipment or processes; in certain instances, close proximity of operations to residences and/or communities; among other typical shale basin drilling challenges and risks.
In our hydraulic fracturing, workover and completions activities, from time to time we experience certain issues and encounter risks, including, for example, mechanical and instrument or tool failures; loss of well control and associated hydrocarbon release and/or natural gas clouds; well kick or flowback during completion or fracturing operations; lost or stuck in hole wireline, coiled tubing or workover strings and tools; loss or compromise of workover string, tubing or casing integrity; large completions, wireline, coiled tubing and workover rig equipment and machinery including electrical hazards; insufficient cementing of casing causing unwanted casing pressure or fluid migration while fracturing or thereafter; proximity of adjacent water wells or aquifers and adjacent producing wells; surface spills of various fracturing, freshwater or well fluids or chemicals; surface pumping and flowback operations and associated pressure and hydrocarbon hazards; surface overpressure events from large machinery (horsepower), equipment or well pressure; fines and violations related to relevant laws and regulations; fires and explosions; personnel safety hazards such as working at heights, driving or equipment operation, energy isolation, excavation and trenching and more; structural damage and collapse to large equipment and machinery; major damage or malfunction to key equipment or processes; in certain instances, close proximity of operations to residences and/or communities; among other typical fracturing, workover and completion challenges and risks.
We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease or other interest in a specific mineral interest. The existence of a material title deficiency can render a lease or other interest worthless and can adversely affect our results of operations and financial condition. The failure of title on a lease, in a unit or any other mineral interest may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.
Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of factors, including commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling conditions, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals, urban growth and other factors. If
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commodity prices become depressed or decline materially from current levels, the number of locations would decrease as increasing numbers of locations would become uneconomic, and any such decrease may be significant. Even to the extent any locations remain capable of economic production, we may determine not to drill such locations until commodity prices recover. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce natural gas and NGLs from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acreage on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.
Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involves risks and uncertainties in their application.
To the extent we target emerging areas, the results of our horizontal drilling efforts in such areas will generally be more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which may be subject to well spacing, density and proration requirements, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, access to gathering systems, takeaway capacity constraints or otherwise, availability of drilling surface acreage, or commodity prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local landowners and other sources for use in our operations. Some areas in which we have operations have experienced drought conditions that could result in restrictions on water availability or use. Such drought conditions and water stress may become more frequent or intense as a result of climate change. If we are unable to obtain water to use in our operations from local sources or are unable to transport and store such water, we may be unable to economically produce natural gas and NGLs in the affected areas, which could have an adverse effect on our financial condition, results of operations and cash flows.
The unavailability or high cost of equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.
We utilize third-party services to maximize the efficiency of our operations. The cost of oilfield services typically fluctuates based on demand for those services. While we currently have excellent relationships with oilfield service companies, there is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages, quality or the high cost of equipment, supplies or personnel could delay or adversely affect our development and exploitation operations, which could have a material adverse effect on our business, financial condition or results of operations.
We have limited control over activities on properties we do not operate, which could reduce our production and revenues.
As of June 30, 2024, we operated approximately 97% of our net (78% of our gross) acreage. With respect to our natural gas midstream business, we do not operate the NEPA midstream entities, and in the
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Barnett, during the six months ended June 30, 2024, approximately 22% of our gross operated production volumes were gathered and processed by our owned and operated system. We have limited control over properties and midstream facilities which we do not operate or do not otherwise control operations. If we do not operate or otherwise control the properties and midstream facilities in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of wells in which we own a non-operating interest or an operator of midstream facilities in which we have an interest to adequately perform operations, an operator’s financial difficulties, including as a result of price volatility or an operator’s breach of the applicable agreements, could reduce our production and revenues. The success and timing of the drilling and development activities on properties operated by others, as well as the midstream activities with respect to our assets, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology.
Risks Related to Our Power Generation Business
We operate our power generation business through a joint venture which we do not control.
We and BPPUS each have a 50% interest in the BKV-BPP Power Joint Venture. For the six months ended June 30, 2024 and 2023, there were total losses in the BKV-BPP Power Joint Venture of $23.0 million and $14.3 million, respectively. For the years ended December 31, 2023, 2022 and 2021, our interest in the earnings on the BKV-BPP Power Joint Venture represented approximately 1.7%, 0.8% and 0.2% of our revenues, which includes derivative gains (losses), net, respectively.
In accordance with the terms of the Limited Liability Company Agreement of BKV-BPP Power (the “BKV-BPP Power LLC Agreement”), the BKV-BPP Power Joint Venture is managed by a board of managers (the “Power JV Board”) consisting of eight members, four of which are appointed by us and four of which are appointed by BPPUS. Consequently, BKV-BPP Power may not take certain material actions without the consent of BPPUS. For example, without the prior consent of BPPUS, the BKV-BPP Power Joint Venture may not:
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make distributions or determine the amount of cash to be distributed;
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make capital expenditures, including acquisitions; or
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incur indebtedness in an amount greater than $1,500,000.
See “Certain Relationships and Related Party Transactions — BKV-BPP Power Joint Venture — BKV-BPP Power Limited Liability Company Agreement.”
We face certain risks associated with shared control, and BPPUS may at any time have economic, business or legal interests or goals that are inconsistent with ours.
We may be required to make additional capital contributions to the BKV-BPP Power Joint Venture.
In addition, we may be required to make additional capital contributions to fund items approved in the annual budget or other matters approved by the Power JV Board. We do not control the timing or the amount which we may be required to contribute. If we fail to make additional capital contributions to BKV-BPP Power, as approved by the Power JV Board, such failure could be deemed an event of default under the BKV-BPP Power LLC Agreement. If an event of default occurs, the non-defaulting party will be entitled to (i) sell the assets of the joint venture and dissolve the joint venture on reasonable terms deemed acceptable to the Power JV Board, (ii) obtain specific performance of the non-defaulting party’s obligations, and/or (iii) exercise any other right or remedy provided in law or in equity. If we default on any obligation to make an additional capital contribution to BKV-BPP Power and any of these events were to occur, it could have a material adverse effect on the BKV-BPP Power Joint Venture and on our business, financial condition, results of operations and cash flows.
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Operation of electric generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The ongoing operation of the Temple Plants involves risks that include performance below expected levels of output or efficiency, as well as the unavailability of key equipment or breakdown or failure of equipment or processes (including an inability to obtain key equipment from Siemens natural gas generators and steam turbines and Benson heat recovery steam generators, which are used by the Temple Plants), due to wear and tear, latent defect, design error or operator error or force majeure events, among other things. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems, occur from time to time and are an inherent risk of the business. Unplanned outages typically increase operation and maintenance expenses and capital expenditures and may reduce revenue available to be distributed to BPPUS and us as a result of selling fewer megawatt hours or require us to incur significant costs as a result of obtaining replacement power from third parties in the open market to satisfy forward power sales obligations. Our inability to operate the BKV-BPP Power electric generation assets efficiently, manage capital expenditures and costs and generate distributions from the Temple Plants could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Maintenance, expansion and refurbishment of electric generation facilities involve significant risks that could result in unplanned power outages or reduced output.
The Temple Plants may require periodic upgrading and improvement. Any unexpected operational or mechanical failure, including failure associated with breakdowns and forced outages, could reduce the facility’s generating capacity below expected levels, reducing potential cash distributions to BPPUS and us. Unanticipated capital expenditures associated with maintaining, upgrading or repairing our facility may also reduce profitability.
If we make any major modifications to Temple I or Temple II, we may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under and determined pursuant to the new source review provisions of the Clean Air Act (“CAA”) at the time of such modifications. Any such modifications could likely result in substantial additional capital expenditures. We may also choose to repower, refurbish or upgrade our facility based on our assessment that such activity will provide adequate financial returns. Such facility requires time for development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices. These events could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations and cash flows.
The Temple Plants may operate, wholly or partially, without long-term power sales agreements.
The Temple Plants may operate without long-term power sales agreements for some or all of their generating capacity and output and therefore be exposed to market fluctuations. Without the benefit of long-term power sales agreements for the facility, we cannot be sure that the BKV-BPP Power Joint Venture will be able to sell any or all of the power generated by the facility at commercially attractive rates or that either facility will be able to operate profitably. This could lead to less predictable revenues, future impairments of either facility’s property, plant and equipment or the closing of the facility, resulting in economic losses and liabilities, which could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations and cash flows.
We do not currently supply our own natural gas directly to Temple I, Temple II or their firm natural gas storage service at the Bammel storage facility. We cannot assure you that we will be successful in the future in obtaining the commercial contracts necessary to facilitate direct delivery of our natural gas production to Temple I on commercially reasonable terms or at all.
We cannot assure you that we will succeed in any effort to establish midstream contracts that would allow us to supply our own natural gas directly to Temple I, Temple II or their firm natural gas storage
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service at the Bammel storage facility. Although the physical infrastructure exists to supply our own natural gas directly to the Temple Plants and the Bammel storage facility, our ability to utilize that infrastructure depends on whether we can successfully negotiate and enter into new midstream contracts on satisfactory terms or at all. If we fail to enter into such contracts on satisfactory terms or at all, we may be unable to achieve the synergistic cost savings we anticipated in connection with the BKV-BPP Power Joint Venture, which could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations and cash flows.
BKV-BPP Power may enter into financially settled Heat Rate Call Options (“HRCOs”) that may expose it to basis and buyback risk in its operations.
To reduce its exposure to fluctuations in the market price of electricity and natural gas, BKV-BPP Power may enter into financially settled HRCOs, which are contracts for the financial purchase and sale of power based on a floating price of natural gas at a predetermined location using a predetermined conversion factor, or heat rate, required to turn the fuel input into electricity. BKV-BPP Power is exposed to basis risk in its operations when its derivative contracts settle financially, and it delivers physical electricity on different terms. For example, if BKV-BPP Power enters into an HRCO, it hedges its electricity production based on an agreed price for that electricity, but physical electricity must be delivered to delivery points in the market it serves. BKV-BPP Power is exposed to basis risk between the hub price specified in the HRCO and the price that it receives for the sales of physical electricity. BKV-BPP Power attempts to hedge basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the quantities that it requires. BKV-BPP Power’s hedging activities do not provide it with protection for all of its basis risk and could result in economic losses and liabilities, which could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations and cash flows.
Additionally, by using derivative instruments to economically hedge exposure to changes in power prices, we could limit the benefit we would receive from increases in the power prices, which could have an adverse effect on our financial condition. For example, as of June 30, 2024, BKV-BPP Power had unrealized losses of $112.0 million on our derivative instruments as a result of increased power prices; of the $112.0 million, $59.5 million of these losses pertain to four open HRCOs. In the event BKV-BPP Power enters into an HRCO and is not able to satisfy its obligations, it must purchase power at prevailing market price to satisfy the HRCO. Likewise, increases in power pricing could limit the benefit we receive under HRCOs and may result in losses. Either such event could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations and cash flows.
Our costs, results of operations, financial condition and cash flows could be adversely impacted by the disruption of the fuel supplies necessary to generate power at Temple I or Temple II, whether as a result of failure of contractual counterparties, disruption in fuel delivery infrastructure or otherwise.
Delivery of natural gas to fuel the Temple Plants is dependent upon the infrastructure (including natural gas pipelines) available to serve such generation facilities as well as upon the continuing financial viability of contractual counterparties. As a result, the BKV-BPP Power Joint Venture is subject to the risks of disruptions or curtailments in the production of power at our generation facilities if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure. Any such disruptions or curtailments could have a material adverse effect on the BKV-BPP Power Joint Venture, and thus on our business, financial condition, results of operations and cash flows.
Risks Related to Our Retail Power Business
We operate our retail power business through a joint venture which we do not control.