S-1 1 d351316ds1.htm S-1 S-1
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As filed with the Securities and Exchange Commission on November 9, 2022.

Registration No. 333-            

 

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Bounty Minerals, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware

 

1311

 

88-2900183

(State or other jurisdiction of incorporation or organization)   (Primary Standard Industrial Classification Code Number)   (IRS Employer Identification Number)

777 Main Street, Suite 3400

Fort Worth, Texas 76102

(817) 332-2700

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

 

 

Tracie Palmer

Chief Executive Officer and President

777 Main Street, Suite 3400

Fort Worth, Texas 76102

(817) 332-2700

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

Copies to:

 

Sean T. Wheeler, P.C.

Debbie P. Yee, P.C.

Anne G. Peetz

Kirkland & Ellis LLP

609 Main Street, Suite 4700

Houston, Texas 77002

(713) 836-3600

 

Douglas E. McWilliams

Thomas G. Zentner III
Vinson & Elkins L.L.P.
845 Texas Avenue, Suite 4700
Houston, Texas 77002
(713) 758-2222

 

 

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after the effective date of this Registration Statement.

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

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

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

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

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

 

Large accelerated filer              Accelerated filer  
Non-accelerated filer      Smaller reporting company          
     Emerging growth company  

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  ☐

 

 

The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment that 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 this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 

 


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

 

SUBJECT TO COMPLETION, DATED NOVEMBER 9, 2022

            Shares

 

LOGO

Bounty Minerals, Inc.

Class A Common Stock

 

 

This is the initial public offering of our Class A common stock. We are selling                shares of Class A common stock.

Prior to this offering, there has been no public market for our Class A common stock. The initial public offering price of the Class A common stock is expected to be between $        and $        per share. We intend to apply to list our Class A common stock on the New York Stock Exchange (“NYSE”) under the symbol “BNTY.”

To the extent that the underwriters sell more than                shares of Class A common stock, the underwriters have the option to purchase, exercisable within 30 days from the date of this prospectus, up to an additional                shares from us at the public offering price less underwriting discounts and commissions.

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012 and, as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. See “Risk Factors” and “Summary—Emerging Growth Company.”

We have two classes of common stock: Class A common stock and Class B common stock. Upon completion of this offering and the related reorganization, holders of shares of our Class A common stock and Class B common stock will be entitled to one vote for each share of Class A common stock and Class B common stock, respectively, held of record on all matters on which stockholders are entitled to vote generally. See “Description of Capital Stock.” Upon consummation of this offering, our Existing Owners (as defined herein), will hold 100% of the shares of Class B common stock that will entitle them to         % of the combined voting power of our common stock (or         % if the underwriters exercise their option to purchase additional shares of Class A common stock in full). This offering is being conducted through what is commonly referred to as an “Up-C” structure. The Up-C structure provides the Existing Owners with the tax advantage of continuing to own interests in a pass-through structure and provides potential future tax benefits for us and the Existing Owners when they ultimately exchange their Bounty LLC Units (as defined herein) (together with its shares of Class B common stock) for shares of Class A common stock. See “Corporate Reorganization.”

Investing in our Class A common stock involves risks. See “Risk Factors” on page 31.

 

 

 

     Price to Public      Underwriting
Discounts and
Commissions (1)
     Proceeds to
Issuer
 

Per Share

   $        $        $    

Total

   $                    $                    $                

 

(1)

See “Underwriting” for additional information regarding underwriting compensation.

 

 

Delivery of the shares of Class A common stock will be made on or about                    , 2022.

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

 

 

 

RAYMOND JAMES    STIFEL

STEPHENS INC.

The date of this prospectus is                    , 2022.

 


Table of Contents

TABLE OF CONTENTS

 

     Page  

SUMMARY

     1  

RISK FACTORS

     31  

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

     66  

USE OF PROCEEDS

     68  

DIVIDEND POLICY

     69  

CAPITALIZATION

     70  

DILUTION

     72  

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

     74  

BUSINESS

     93  

MANAGEMENT

     125  

EXECUTIVE COMPENSATION

     130  

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     136  

CORPORATE REORGANIZATION

     138  

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     142  

DESCRIPTION OF CAPITAL STOCK

     145  

SHARES ELIGIBLE FOR FUTURE SALE

     151  

CERTAIN ERISA CONSIDERATIONS

     153  

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

     156  

UNDERWRITING

     161  

LEGAL MATTERS

     169  

EXPERTS

     169  

WHERE YOU CAN FIND MORE INFORMATION

     169  

INDEX TO FINANCIAL STATEMENTS

     F-1  

ANNEX A — GLOSSARY OF OIL AND NATURAL GAS TERMS

     A-1  

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on our behalf or the information to which we have referred you. Neither we nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the underwriters are offering to sell shares of Class A common stock and seeking offers to buy shares of Class A common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the Class A common stock. Our business, financial condition, results of operations and prospects may have changed since that date.

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.”

Through and including                , 2022 (25 days after the date of this prospectus), all dealers effecting transactions in our Class A common stock, whether or not participating in this offering,

 

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may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

Organizational Structure

This offering is being conducted through what is commonly referred to as an “Up-C” structure. Following this offering and the reorganization transactions described in “Summary—Corporate Reorganization,” Bounty Minerals, Inc. (“Bounty Minerals”) will be a holding company whose sole material asset will consist of a                 % interest in Bounty Minerals Holdings LLC (“Bounty LLC”). Bounty LLC will continue to wholly own all of our operating assets. After the consummation of the transactions contemplated by this prospectus, Bounty Minerals will be the sole managing member of Bounty LLC and will be responsible for all operational, management and administrative decisions relating to Bounty LLC’s business. See “Summary—Corporate Reorganization” and “Corporate Reorganization” for more information on this structure.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. These sources include reports entitled: Natural Gas Weekly Update, dated May 2022 (the “May 2022 EIA Update”), Natural Gas Weekly Update, dated March 2022 (the “March 2022 EIA Update”), the Annual Energy Outlook 2022, dated March 2022 (the “2022 AEO”), Today in Energy, dated December 2017 (the “2017 EIA Statistics”), Today in Energy, dated April 2022 (the “2022 EIA Statistics”), U.S. Liquefaction Capacity, dated June 2022 (the “EIA Liquefaction Report”), U.S. Crude Oil and Natural Gas Proved Reserves, Year-end 2020, dated January 2022 (the “EIA Reserves Report”), by the Energy Information Administration (the “EIA”), a report entitled 2022 Annual Report by the International Group of Liquified Natural Gas Importers, dated November 2021 (the “GIIGNL Annual Report”), a report entitled Climate Change Indicators, dated August 2022 (the “EPA Emissions Report”), by the Environmental Protection Agency (“EPA”), an article entitled “Appalachia Still has some growth potential with record-high capital efficiency” by Rystad Energy, dated April 2021 (the “Rystad Report”), and Encyclopedia Britannica and a report entitled S&P Commodity Insights, dated June 2022 (the “S&P IRR Report”), by S&P Global Platts Analytics. Although we believe these third-party sources are reliable as of their respective dates, neither we nor the underwriters have independently verified the accuracy or completeness of this information. Some data is also based on our good faith estimates. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

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 us or an endorsement or sponsorship by or of us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the TM, SM or ® 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 right of the applicable licensor to these trademarks, service marks and trade names.

 

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SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary does not contain all of the information that you should consider before investing in our Class A common stock. You should read the entire prospectus carefully, including the historical financial statements and the notes to those financial statements, before investing in our Class A common stock. The information presented in this prospectus assumes, unless otherwise indicated, (i) an initial public offering price of $             per share (the midpoint of the price range set forth on the cover of this prospectus), (ii) that the underwriters’ option to purchase additional shares of Class A common stock is not exercised and (iii) that no shares are purchased under the Directed Share Program (as defined below). You should read “Risk Factors” for information about important risks that you should consider before buying our Class A common stock.

Bounty Minerals, Inc., the issuer in this offering (together with its wholly owned subsidiaries, “Bounty Minerals”), is a holding company formed to own an interest in, and act as the sole managing member of, Bounty Minerals Holdings LLC (“Bounty LLC”). Upon the consummation of this offering, Bounty Minerals’ sole material asset will be the Bounty LLC Units (as defined below) purchased from Bounty LLC with the net proceeds from this offering. Bounty Minerals will operate and control all of the business and affairs of Bounty LLC and, through Bounty LLC and its subsidiaries, conduct our business. Accordingly, our historical financial statements are those of Bounty LLC, which we refer to herein as our “predecessor.”

Unless indicated otherwise or the context otherwise requires, references in this prospectus to the “Company,” “us,” “we” or “our” (i) for periods prior to completion of this offering, refer to the assets and operations (including reserves, production and acreage) of Bounty LLC, and (ii) for periods after completion of this offering, refer to the assets and operations (including reserves, production and acreage) of Bounty Minerals and its subsidiaries, including Bounty LLC and its subsidiaries. This prospectus includes certain terms commonly used in the oil and natural gas industry, which are defined elsewhere in this prospectus in the “Glossary of Oil and Natural Gas Terms” contained in Annex A to this prospectus.

The estimates of our proved, probable and possible reserves as of June 30, 2022 and December 31, 2021 and 2020 have been prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”), our independent reserve engineers. Summaries of CG&A’s reports are included as exhibits to the registration statement of which this prospectus forms a part.

Our Company

We own, acquire and manage mineral interests in the Appalachian Basin with the objective of growing cash flow from our existing portfolio for distribution to stockholders. Our initial target area was guided by a strong technical team that identified the areas of the basin we believe have the highest potential economics, enabling us to acquire our current holdings of approximately 65,000 net mineral acres. Our focus has been on acquiring primarily non-producing minerals in developing shale plays, which has allowed us to deliver significant organic production and cash flow growth as operators have increasingly developed the core of the basin. We expect this to continue as only 17% of our existing portfolio by identified net proved, probable and possible (“3P”) locations have been developed as of June 30, 2022, which does not include the additional resource potential in our stacked pay areas. Our assets are exclusively mineral interests, which entitle us to the right to receive a share of recurring revenues from production without being

 

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subject to development capital requirements, operating expenses, or maintenance capital requirements. Mineral ownership results in higher cash flow margins than any other portion of the energy sector by providing exposure to commodity prices and minimizing operating expense while limiting exposure to service and development cost inflation.

We are a natural gas-focused minerals company. For the six months ended June 30, 2022, the production from our mineral acreage position was substantially all natural gas and NGLs, with total production associated with our mineral interests totaling 7.7 Bcfe, comprised of 76% natural gas, 20% NGLs and 4% oil. For the three months ended June 30, 2022, total production associated with our mineral interests was 4.2 Bcfe, comprised of 76% natural gas, 20% NGLs and 4% oil. We plan to accomplish our objectives of growing cash flow and paying quarterly dividends by utilizing cash flow from the current and continued development of our acreage. We intend to further grow our acreage position by selectively targeting additional accretive acquisitions using the same technical, land and legal rigor our team has historically applied to acquisition opportunities.

Our History

Our team has a long history of buying mineral interests in top-tier prospective acreage throughout the United States. We were formed in 2012 with the objective of acquiring primarily non-producing mineral interests in the Appalachian Basin. We believe our team has a demonstrated and proven competitive advantage to technically identify, source, evaluate, negotiate, acquire and manage mineral and royalty interests in high quality areas of the Appalachian Basin. We acquired all of our approximately 65,000 net mineral acres through more than 1,200 transactions covering three states and 30 counties. The substantial majority of our acreage is subject to a lease, and of that leased acreage, we have had the opportunity to directly negotiate leases on over 21,000 net mineral acres, generating over $101 million of lease bonus income from our inception to June 30, 2022. The members of our executive team, including our Executive Chairman, have an average of 30 years of oil and gas experience, including prior leadership experience in the management of, and value creation within, minerals, upstream and midstream assets. We utilize geology and engineering consultants with an average of over 43 years of experience in the Appalachian Basin, with extensive subsurface expertise including vertical well logs and performance analysis, to help us identify and evaluate potential acquisition opportunities. We believe we have earned a positive reputation for building relationships through our negotiations with mineral owners, evaluating and analyzing title, navigating legal complexities and consistently and efficiently closing deals. Over the last five years, we have also actively engaged with the legislatures of Pennsylvania, West Virginia and Ohio to advocate for the passage of laws to both protect mineral owners and promote development. This process has allowed us to develop mutually beneficial relationships with operators and land owners, which are key to our continued success.

Our experience and expertise has enabled us to aggregate a considerable inventory of non-producing acreage ahead of development activity. In 2017, our primary allocation of capital shifted from acquisition and resource capture to returning capital to our stockholders. While our capital allocation strategy shifted, our production grew by over 33% on a Mcfe basis from 2019 to 2021, demonstrating our ability to grow production without the need for additional significant

 

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capital investment in acquisitions due to our inventory remaining largely ahead of development activity. The graphic below compares our net acres acquired by year to our total net production over time:

 

LOGO

In addition to our production growth, our royalty revenue has increased substantially since 2019. We generated $25.7 million in royalty revenue in the fourth quarter of 2021 compared to $12.4 million in the fourth quarter of 2019, representing an increase of more than 107%.

Our Focus on the Appalachian Basin

We target the Southwestern portion of the Appalachian Basin in the tri-state area covering Ohio, West Virginia and Southwestern Pennsylvania, focusing on the highly-attractive, dry gas and liquids-rich portions of the play with stacked pay potential in three separate zones that provide favorable economics. While dry gas is the predominant resource in the Marcellus, Utica and Upper Devonian Shales, each of the Marcellus and the Utica shales have liquids-rich reserves located in the western portion of the play with dry gas reserves in the eastern portion. The geologic characteristics of the Appalachian Basin are mature and well-understood and we believe the continuous nature of the hydrocarbons in our targeted area of the basin provide for more consistent and a higher probability of development of our acreage. We have achieved organic production growth and increased cash flow by following emerging well results and targeting undeveloped areas with the best underlying geology where we expect operators will continue development activity and complete new wells to offset declines and grow production. The Southwestern portion of the Appalachian Basin, where we primarily target and own minerals, has grown from approximately 1,700 horizontal producing wells in 2012 to more than 10,600 horizontal producing wells as of March 31, 2022.

Our production growth has significantly outpaced the broader Appalachian Basin. Per the May 2022 EIA Update, dry natural gas production from the shale formations of Appalachia has been growing since 2006, with production in the region reaching 33.6 Bcf/d in December 2021. Since 2019, the production growth of the Appalachian Basin as a whole has averaged a 3% compound annual growth rate (“CAGR”) according to the May 2022 EIA Update, while increased development of our portfolio over the same period has resulted in organic gas production growth at a materially higher 10% CAGR. The graphic below compares our dry gas production growth from 2019 to 2021 to the dry gas production growth of the Appalachian Basin as a whole during the same period.

 

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Bounty vs. Appalachia Dry Gas Production Growth

 

LOGO

As of June 30, 2022, CG&A estimated only 17% of our existing portfolio by identified net 3P locations was currently developed. The graphic below compares our annual production (Mcfe/d) to the percentage of our acreage that was developed from 2013 to 2021:

Total Annual Production vs % Developed by Year

 

LOGO

Our focus on Appalachia is also unique among public mineral companies, who either have limited or no exposure to the Appalachian Basin. As such, we believe we offer a unique opportunity to public investors looking to participate in the growth of the largest and most economic natural gas basin in the United States.

 

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Future Development

Our minerals are leased to some of the top operators in Southwest Appalachia, who have significant inventory of future locations and DUCs, as well as a substantial portion of current active rigs in the basin. In the preceding two years, 79% of our acreage has been within five miles of an active rig, and 61% of our mineral acreage was within three miles of an active rig. In 2021, there were a total of 636 completions within counties in which we own mineral interests, of which 25% were located on our acreage. As of June 30, 2022, 39% of current active rigs in Southwest Appalachia were developing units on our acreage position. This increased activity on our acreage and proximity to rig activity further demonstrates the likelihood of future development and the potential for continued development. According to Enverus production data, as of August 10, 2022, 32 of the top 100 wells in Southwest Appalachia were on our acreage, and our mineral position was operated by all of the top ten operators in our portion of the basin, based on 2021 gross operated production. These operators make up approximately 79% of our total leased acreage position and, since 2020, have completed approximately 84% of the total wells within the counties in which we own mineral interests. Five of our top operators are companies whose capital budgets are deployed solely in Appalachia.

As operators continue to develop the substantial leased inventory of horizontal drilling locations on our acreage, we expect this development activity to support our production and cash flow from the undeveloped mineral acreage in our portfolio. We divide our horizontal well inventory into six categories based on the development stage of the well or prospective well: (i) producing wells (“PDP”), (ii) completed wells on which we are awaiting receipt of revenue from operators (“producing awaiting revenues” or “PARs”), (iii) drilled but uncompleted wells (“DUCs”), (iv) prospective wells that have been granted drilling permits (“permitted wells”), (v) additional drilling locations inside current Bounty drilling spacing units (“DSUs”), and (vi) additional drilling locations in DSUs that we anticipate will be formed in the future based on our assumptions described below. PARs, DUCs and permitted wells, which we collectively refer to as our “activity wells,” provide near-term visibility on production activity in areas where we own interests, as we have historically found that activity wells are likely to be converted into producing wells under a short time horizon. We refer to additional drilling locations inside current Bounty DSUs and additional drilling locations on DSUs that we anticipate will be formed in the future, as our “additional locations.”

The table below reflects our current gross and net horizontal producing wells, activity wells and additional locations as of June 30, 2022 across our DSU acreage by state and play, consistent with our 3P reserve report prepared by CG&A.

 

State

  PDP     PARs(1)     DUCs     Permitted
Wells
    LOCs Inside
Existing Unit
    Remaining
LOCs
    Total  

Ohio

    494       18       33       17       95       835       1,492  

Pennsylvania

    253       6       27       24       39       675       1,024  

West Virginia

    505       42       36       81       106       1,901       2,671  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Gross Location Count

    1,252       66       96       122       240       3,411       5,187  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Net Location Count(2)

    11.04       0.50       0.81       1.81       2.40       48.12       64.68  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

PARs are completed wells on which we are awaiting receipt of revenue from operators. Producing wells that are temporarily shut-in due to nearby operational activity are included in the PAR category. On average, Bounty receives first payment on production three months after first production with the first revenue payment normally covering several months of production.

(2)

Reflects the assumed number of locations in which we would own a 100% net revenue interest determined by multiplying our total gross locations included in our DSU acreage by our anticipated average net revenue interest across our DSU acreage.

 

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Play Name

  PDP     PARs(1)     DUCs     Permitted
Wells
    LOCs Inside
Existing Unit
    Remaining
LOCs
    Total  

Marcellus

    725       40       56       84       124       1,856       2,885  

Utica Point Pleasant

    516       26       40       38       112       1,250       1,982  

Upper Devonian

    11       —       —       —       4       305       320  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Gross Location Count

    1,252       66       96       122       240       3,411       5,187  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Net Location Count(2)

    11.04       0.50       0.81       1.81       2.40       48.12       64.68  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

PARs are completed wells on which we are awaiting receipt of revenue from operators. Producing wells that are temporarily shut-in due to nearby operational activity are included in the PAR category. On average, Bounty receives first payment on production three months after first production with the first revenue payment normally covering several months of production.

(2)

Reflects the assumed number of locations in which we would own a 100% net revenue interest determined by multiplying our total gross locations included in our DSU acreage by our anticipated average net revenue interest across our DSU acreage.

Our net mineral acreage is typically incorporated into larger DSUs, which are areas designated as a unit by agreement, field spacing rules, unit designation, or otherwise combined with other acreage pursuant to an administrative permit or order. We estimate and refer to this combined acreage, whether or not formally designated as a drilling spacing unit, as “DSU acreage” and to any DSU acreage in which we are entitled to participate or expect to be entitled to participate as a result of our mineral interests as our “DSU acres.” As of June 30, 2022, we had approximately 1,131,827 gross DSU acres. When our acreage is incorporated into a DSU acreage position, we participate in production from such acreage with our net revenue interest diluted on a proportional basis due to the incorporation of additional acreage in the DSU. Our additional locations represent locations on our DSU acreage that we have identified based on CG&A’s analysis of proved horizons and on publicly available information regarding existing operator spacing and development plans. In order to identify our additional locations, we undertake a four-step analysis to make determinations with respect to likely development programs, prospective zones, prospective well density per zone and, ultimately, the number of additional locations that exist on our DSU acreage. First, we analyze our acreage on a tract-by-tract basis, based upon what we believe to be the most likely development scenario for that tract. This is based on our review of offset or surrounding well geometry and/or well geometry that directly intersects our individual tracts. Second, each tract is assigned prospective zones based on a variety of factors, including geologic data, offset well results and industry activity. Third, we perform a prospective well density per zone analysis, which requires evaluation of (i) what we believe to be the most likely well spacing assumptions based on industry disclosure, third-party research and other publicly available data and (ii) offset activity data from producing wells, permitted wells and DUCs. Finally, for each prospective zone, we determine the number of producing wells, DUCs and permitted wells currently in existence and then assign additional locations to that tract based on our well spacing assumptions.

When we analyze and incorporate spacing assumptions, our methodology centers around several assumptions including inter-lateral well spacing, lateral length, unit setbacks, wellbore orientation and assumed DSU acreage. We generally estimate our DSU acreage based upon the drainage pattern each wellbore meeting the above spacing assumptions can withstand due to existing development within the area, and not to exceed a 1,280-acre threshold. Our current average DSU acreage for additional locations based on this framework is 770 acres. Our additional locations assume (i) in the Utica Formation, a 1,000 foot inter-lateral spacing and (ii) in the Marcellus and Upper Devonian Formations, a 750 foot inter-lateral spacing.

 

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Our additional horizontal well inventory contains a range of lateral lengths, the substantial majority of which are from 10,500 feet to 11,500 feet. The lateral length assumptions used for our additional locations in our inventory is based on historical activity in the area around each location. Operators have continued to drill longer lateral wells that are expected to yield higher economics. As such, our assumptions about lateral lengths may change in the future in-line with these developments which may contribute to decreases in horizontal locations. Additionally, it may be possible, through further down spacing and targeting of additional zones, to increase horizontal locations.

We believe there are significant opportunities to continue acquiring non-producing mineral acreage in the Appalachian Basin. We also anticipate that continued improvement in drilling and completion techniques may expand the economic viability of new core areas. The historical production, pricing, and differential data from our acreage on over 1,250 gross PDP wells and 11.04 net PDP wells in our current portfolio provides valuable information within each of our type curve areas for future acquisition economics and provides visibility to production and cash flow growth opportunities. With the help of CG&A, we have developed 17 individual type curves within our core areas that we use to evaluate potential acquisitions. In addition to our technical knowledge, over ten years of experience in the Appalachian Basin has given us the ability to leverage our familiarity of the regulatory environment, and unique title nuances to identify and evaluate opportunities that will supplement our organic development. We intend to capitalize on our reputation and relationships with landowners and operators to access distinct acquisition opportunities.

Key Operators

Our portfolio of assets provides exposure to a diverse group of top-tier producers, many of which operate solely in Appalachia and are able to deploy all of their capital within the basin. At current activity levels, the top operators in our portfolio have over a decade of premium inventory, which we believe will continue to drive future cash flow in the basin. As of June 30, 2022, these active operators were operating 26 rigs of the 31 total active rigs (84%) in Southwest Appalachia. The graphics below show our operator breakdown by controlled leased acreage as well as the rig count of Southwest Appalachia operators as of June 30, 2022.

 

Bounty Operator Exposure by Acreage

 

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Operators across Southwest Appalachia have continued to increase productivity per well by increasing lateral lengths and implementing more effective completion techniques, which directly benefit our mineral interests. These technical enhancements drive down well breakeven costs, which increase the number of economic drilling locations underlying our acreage and in the Appalachian Basin as a whole. Lower breakeven costs allow for continued development in low price environments. For example, production in Southwest Appalachia stayed relatively consistent during the low commodity price environment in 2020. Each additional hydrocarbon recovered increases our cash flow, and we realize the benefit of these improvements without incurring any related capital expense. Furthermore, additional economic locations within the Appalachian Basin contribute to greater potential acquisition targets.

Due to certain enhanced pricing provisions in our leases that we have opportunistically negotiated, covering over 21,000 net mineral acres, we also benefit from the strategies that some of our top operators employ to capitalize on higher commodity prices. In particular, given that United States exports for LNG will grow at a 4.6% CAGR from 2020 through 2040 according to the 2022 AEO, several of our top producers, including Antero Resources Corporation, Range Resources Corporation, Southwestern Energy Company and EQT Corporation, have either begun or announced an intention to market natural gas directly to LNG facilities to realize premium pricing relative to Henry Hub. Under a substantial majority of our negotiated leases, our pricing provisions provide that our proceeds will be based on a percentage of the gross price of the first sale of the commodity to a non-affiliate of the operator, as opposed to the industry standard percentage of the current in-basin spot price, which for 2021 averaged approximately $0.62 below the Henry Hub spot price, whereas Bounty’s average differential was approximately $0.16 below Henry Hub spot price. According to the “EIA Liquefaction Report,” the United States is currently a leading exporter of LNG, with more than 80 MTPA of liquefaction capacity, or approximately 18% of global liquefaction capacity per the GIIGNL Annual Report. We believe that the increased global demand for LNG from a multitude of different regions for a myriad of uses will encourage the continued development of the Appalachian Basin, which is comprised of the most economic shale plays as of June 2022, and contains 50% of the United States’ remaining, recoverable shale gas reserves per the EIA Reserves Report.

We expect our current and future mineral acreage to be developed by our operators, who we believe will continue to deploy the most modern drilling and completion technologies, have access to capital and continually negotiate contracts that improve pricing.

Our Mineral Interests

As of June 30, 2022, our high quality portfolio solely consisted of mineral interests and we intend to continue to primarily acquire mineral interests. We believe that mineral interests have the highest and best value for our stockholders and provide the best long-term results, as they represent a perpetual right to the economic value of minerals produced from the land. Mineral interests are real property interests and grant ownership of the natural gas, NGLs and crude oil underlying a tract of land and the rights to explore for, drill for and produce natural gas, NGLs and crude oil on that land or to lease those exploration and development rights to a third party. When we lease those rights, usually for a one to five-year term, we typically receive an upfront cash payment, known as a lease bonus, and we retain a mineral royalty, which entitles us to a percentage of production or revenue from production free of lease operating expenses. A lessee can extend the lease beyond the initial lease term with continuous drilling, production or other operating activities or through negotiated contractual lease extension options. When production and drilling cease, the lease terminates, allowing us to lease the exploration and development rights to another party and receive another lease bonus.

Bounty’s focus on non-producing mineral acreage has created the opportunity for us to acquire a significant amount of acreage initially not subject to a lease. As a result, Bounty has had the opportunity to directly negotiate leases with operators to secure favorable terms that enhance pricing, minimize

 

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post-production expenses, and encourage more rapid development of our minerals. Of our approximately 65,000 net mineral acres, we have negotiated leases directly with operators on over 21,000 net mineral acres and generated over $101 million of lease bonus from inception to June 30, 2022. Historically, this income has been reinvested to acquire additional minerals. We have also been able to modify existing leases on almost 700 net mineral acres prior to production being established. Amendments to existing leases allow Bounty the opportunity to negotiate some of these same advantageous lease terms. Since inception, we have been able to enhance margins by raising the average royalty rate in our portfolio by 14% through negotiating new leases and amending current leases on approximately one-third of our total acreage. In addition, as of June 30, 2022, we had approximately 14,500 core net mineral acres that are not currently subject to a lease. As operators continue to establish and complete new DSUs through leasing within the core of Southwest Appalachia, we believe this provides us with the ability to continue to generate revenue both through the potential for initial lease bonus payments and enhanced royalty rate and pricing provisions, as demonstrated through the over 1,450 acres leased first half of 2022 generating approximately $4.5 million in new lease bonus income.

We generate a substantial portion of our revenues and cash flows from our mineral interests when natural gas, NGLs and oil are produced from our acreage and sold by the applicable operators and other working interest owners. Our royalty revenue generated from these mineral and royalty interests was approximately $50.2 million for the six months ended June 30, 2022 and $69.2 million for the year ended December 31, 2021. Approximately 90% of royalty revenue during the first half of 2022 was derived from the sale of natural gas and NGLs.

Unlike traditional oil and gas operators who must acquire large contiguous blocks of acreage to drill horizontal wells, targeting mineral ownership gives us the flexibility to acquire smaller blocks of acreage throughout the most economic areas of Southwest Appalachia. As a mineral interest owner, we make the initial investment to capture these interests but do not incur any development capital or lease operating expense associated with the development and extraction of the minerals. This insulates much of our company from service and material cost inflation, unlike operating companies, midstream companies and refineries. Additionally, ownership of mineral interests provides exposure to commodity prices, including natural gas, NGLs and oil. In order to maintain this uncapped exposure for our investors, we do not currently employ any commodity hedges. Our G&A has been consistently low relative to our revenues representing approximately 8% of revenue for the twelve months ended December 31, 2021. As our production has increased, our G&A continues to decline on a cost per unit of production basis as evidenced in the chart below.

 

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These advantages and minimized cost structure result in higher cash margins and free cash flow, allowing us to allocate a higher percentage of revenue to both distributions and re-investment opportunities compared to traditional exploration and production companies.

Mineral Ownership Summary

Currently, our mineral interests are entirely in the Appalachian Basin, which we believe is one of the premier unconventional natural gas producing regions in the United States. According to Enverus production data, as of August 10, 2022, 32 of the top 100 wells in Southwest Appalachia were on our acreage, and our mineral position was operated by all of the top ten operators in Southwest Appalachia, based on 2021 gross operated production. Our mineral acreage position is located in the most active states in Appalachia based on number of active horizontal wells. The table below summarizes our current mineral assets by state as of June 30, 2022.

 

     Leased Acreage      Unleased Acreage      Grand Total  

Ohio

     18,091        6,692     

Pennsylvania

     10,374        2,976     

West Virginia

     21,575        4,822     
  

 

 

    

 

 

    

Total

     50,040        14,490        64,530  
  

 

 

    

 

 

    

 

 

 

As set forth above, as of June 30, 2022, our interests covered approximately 65,000 net mineral acres, which the substantial majority have been leased to exploration and production (“E&P”) operators and other working interest owners with us retaining an average 16.3% royalty. Typically, within the mineral and royalty industry, owners standardize ownership of net royalty acres (“NRAs”) to a 12.5%, or a 1/8th, royalty interest, representing the number of equivalent acres earning a 12.5% royalty. When adjusted to a 1/8th royalty, our mineral interests represent approximately 65,300 NRAs, or approximately 8,200 NRAs on a 100% basis. The table below sets forth our weighted average royalty, as well as the NRAs adjusted to a 1/8th royalty and on a 100% basis, for our leased acreage.

 

     Net Mineral
Acres
     Weighted
Average Royalty
    NRAs (1/8
Basis)(1)(3)
     NRAs (100%
Basis)(2)(3)
 

Leased Acreage

          

Ohio

     18,091        16.4     23,777        2,972  

Pennsylvania

     10,374        15.3     12,692        1,587  

West Virginia

     21,575        16.7     28,825        3,603  

Leased Acreage Total

     50,040        16.3     65,294        8,162  
  

 

 

      

 

 

    

 

 

 

 

(1)

Standardized to a 1/8th Royalty (The hypothetical number of acres in which an owner owns a standardized 12.5%, or 1/8th, royalty interest based on the actual number of net mineral acres in which such owner has an interest and the average royalty interest such owner has in such net mineral acres. For example, an owner who has a 25%, or 1/4th, royalty interest in 100 net mineral acres would hypothetically own 200 NRAs on a 1/8th basis (100 multiplied by 25% divided by 12.5%)).

(2)

Standardized to a 100% Royalty (The hypothetical number of acres in which an owner owns a standardized 100% royalty interest based on the actual number of net mineral acres in which such owner has an interest and the average royalty interest such owner has in such net mineral acres. For example, an owner who has a 25%, or 1/4th, royalty interest in 100 net mineral acres would hypothetically own 25 NRAs on a 100% basis (100 multiplied by 25%)).

(3)

May not sum or recalculate due to rounding.

 

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Strategies

Our primary objective is to create stockholder value and maximize stockholder returns. We intend to accomplish these goals by executing the following strategies:

 

   

Utilizing the continued development of our portfolio to increase cash returns to stockholders while maintaining a conservative capital structure. Following this offering and subject to the determination of our Board of Directors, we initially expect to return capital to our stockholders through quarterly dividends. We expect Bounty LLC to initially pay quarterly distributions to us and the Existing Owners equal to 100% of (i) cash available for distribution and (ii) cash from lease bonus income, and that we, in turn, will pay quarterly dividends equal to the amount received from Bounty LLC net of cash taxes. See “Dividend Policy” for more information on the factors that could impact our expectations for our quarterly dividends and the factors our Board of Directors will consider in determining the frequency and amounts of dividends that we expect to pay. Only 17% of our existing portfolio by identified net 3P locations is currently developed, which does not include the additional resource potential underlying our minerals, made up of the Utica and Upper Devonian shales that lie above and below the Marcellus in stacked pay areas of our portfolio. As such, we believe that we have a significant amount of continued development built into our current portfolio and that such development will enable us to increase cash returns to stockholders over time. Further, because we have no debt, we believe that we will be able to continue to grow cash returns while also maintaining a conservative capital structure.

 

   

Actively managing our mineral acreage to capitalize on its continued development. We intend to maximize the revenues generated from our current portfolio of mineral interests by utilizing our team’s experience in the Appalachian Basin. For example, because we diligently review operator activity and payments, we are able to ensure that our operators are in compliance with their lease obligations and that the payments are timely, accurately disbursed and commensurate with our royalty percentage. Additionally, we have a history of directly negotiating new leases or amending current leases with favorable terms that enhance pricing, minimize post-production expenses and encourage our operators to more rapidly develop our minerals.

 

   

Providing exposure to commodity prices with protection from service and material cost inflation. As a mineral interest owner, we do not incur any development or lease operating expense associated with the development and extraction of the minerals. This insulates much of our company from service cost inflation unlike operating companies, midstream companies and refiners. Additionally, our business provides uncapped exposure to commodity prices as we do not currently have any commodity hedges in place. These advantages result in higher cash margins and free cash flow as a percentage of revenue, allowing us to allocate a higher percentage of our revenue to both distributions and re-investment opportunities as compared to traditional exploration and production companies.

 

   

Targeting accretive non-producing acreage in the core economic areas of the Appalachian Basin. While additional production and cash flow in our portfolio is initially expected to be generated from our already captured position in Southwest Appalachia, we intend to continue focusing our acquisition efforts in areas with the greatest economic and development potential. With over a decade of future drilling locations indicated by the top operators in the Appalachian Basin, we believe there are significant opportunities to target non-producing acreage. We plan to focus our acquisition efforts in these areas by

 

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continuing to follow technical results. The historical production, pricing and differential data provided to us on over 1,250 PDP wells in our current portfolio provides additional guidance within each of our type curve areas for future acquisition opportunities. We intend to primarily acquire mineral interests, and not target ORRIs or non-operated working interests. We believe mineral interests provide the highest and best value for our stockholders and the best long-term results, as they represent a perpetual right to the economic value of minerals produced from the land.

Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and to achieve our primary business objectives:

 

   

Natural gas is the preferred hydrocarbon to facilitate the energy transition, and the top operators on our mineral acreage have strong commitment to ESG. Natural gas is a clean-burning energy source with emissions far below that of oil and coal, two competing carbon-based energy sources. Per the EPA Emissions Report, the increasing use of natural gas in lieu of coal and oil has been partly responsible for the decline in United States greenhouse gas emissions from electricity generation since 1990. Methane also serves as a reliable secondary fuel that can supplement weather dependent clean energy sources, such as wind and solar power, to ensure electric grid reliability. The top operators on our acreage position have all made public commitments to environmental stewardship and to produce natural gas in a safer and cleaner manner than overseas competitors. Per the Rystad Report, Appalachia had the lowest scope 1 carbon dioxide (“CO2”) emissions of all United States onshore basins in 2020. Of the public operators on our acreage, all have incorporated an environmental, social and governance (“ESG”) metric into their management compensation structure, which we believe further incentivizes ethical development. With all of our acreage situated in the most economic area of the Appalachian Basin, we are primed to benefit as carbon pressures mount and transition to cleaner fuels accelerates.

 

   

Our undeveloped acreage provides exposure to natural gas demand growth. Natural gas is vital to the world economy and is used as a source of energy for electric power generation, a transport fuel and as a chemical feedstock, among a multitude of other uses. The 2022 AEO forecasts United States natural gas consumption to grow from 30.24 Tcf in 2021 to 34.01 Tcf by 2050. Adding to the growing domestic consumption of natural gas, LNG exports set a record high in 2021, averaging 9.7 Bcf/d and a 50% growth rate from 2020, according to the March 2022 EIA Update. The growing demand for natural gas will require an increasing number of wells drilled in Appalachia as the basin contains 50% of the United States’ remaining, recoverable shale gas reserves per the EIA Reserves Report. Appalachia continues to have superior drilling economics relative to other gas resource plays within the United States, as evidenced by the increase in active rigs in the basin over prior years. Our acreage is in the top producing areas within Appalachia with only 17% of our acreage by identified net 3P locations currently developed and in receipt of revenue. Natural gas and natural gas liquids comprised 96% of our current production and 98% of our 3P reserves as of June 30, 2022. We expect future growth in natural gas demand will support the continued growth of our cash flows and distributions.

 

   

Our acreage is concentrated in the premier natural gas basin in the United States with exposure to multiple pay zones. Appalachia is one of the premier natural gas regions in the world with over 33.6 Bcf/d of natural gas production as of December 2021, representing more than one-third of total United States dry gas production per the May 2022 EIA

 

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Update. There are currently three primary prospective pay zones in Southwest Appalachia, the Marcellus, Utica and Upper Devonian formations. Although the Marcellus and Utica formations are the most recent shale discoveries, the development of the Appalachian Basin over the past several years has significantly reduced the risk associated with the core areas of each play. The Southwestern portion of the Appalachian Basin, where our acreage is concentrated, is known for being predominantly dry gas; however, there is also exposure to liquids-rich natural gas and oil in both the Marcellus and Utica formations. Targeting acreage in the more liquids-rich areas of the Appalachian Basin in addition to the dry gas areas has allowed us to capitalize on commodity price fluctuations that drive operator economics and development plans.

 

   

Portfolio of high-quality operators developing our position. As of June 30, 2022, we owned approximately 65,000 net mineral acres and had an interest in greater than 1,250 wells across 610 DSUs in the core of Appalachia. Our mineral acreage is situated within all of the top ten producing counties in Southwest Appalachia based on total gross 2021 production. At current activity levels, the top operators in our portfolio have over a decade of premium inventory left, which we believe will drive future cash flow. Our premier operators, including Antero Resources Corporation, Ascent Resources Utica Holdings, LLC, CNX Resources Corporation, EQT Corporation, Gulfport Energy Corporation, Range Resources Corporation and Southwestern Energy Company, have continued to increase productivity per well by increasing lateral lengths and implementing more effective completion techniques. These technical enhancements directly benefit our mineral interests, as each additional hydrocarbon recovered increases our cash flow. Most importantly, we realize the benefit of these improvements without any of the capital expense. Furthermore, the enhancement in drilling efficiency further benefits us by increasing the number of economic drilling locations underlying our acreage and the Appalachian Basin as a whole. We expect our mineral acreage to be converted from undeveloped to producing by our operators who deploy the most modern drilling and completion technologies, have access to capital and are environmentally focused.

 

   

Experienced and proven management team. The members of our executive team, including our Executive Chairman, have an average of 30 years of oil and gas experience, including prior leadership experience in the management of, and value creation within, minerals, upstream and midstream assets. As a result, the executive team has significant breadth and experience in understanding and driving value creation through all stages of oil and gas asset life-cycle maturation. Our team has a long history of buying mineral interests in high-quality prospective acreage throughout the United States, most notably in Appalachia with the acquisition of approximately 65,000 net mineral acres through more than 1,200 transactions. We believe we have a demonstrated and proven competitive advantage in our ability to technically identify, source, evaluate, negotiate, acquire and manage mineral and royalty interests in high-quality acreage positions.

Corporate Reorganization

Bounty Minerals was incorporated as a Delaware corporation in June 2022. Our management and our other investors (collectively, the “Existing Owners”) own all of the membership interests in Bounty LLC.

Following this offering and the reorganization transactions described below (our “corporate reorganization”), Bounty Minerals will be a holding company whose sole material asset will

 

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consist of a         % interest in Bounty LLC. Bounty LLC will continue to wholly own all of our operating assets. After the consummation of the transactions contemplated by this prospectus, Bounty Minerals will be the sole managing member of Bounty LLC and will be responsible for all operational, management and administrative decisions relating to Bounty LLC’s business.

In connection with this offering,

 

   

all of the outstanding membership interests in Bounty LLC will be converted into a single class of common units in Bounty LLC, which we refer to in this prospectus as “Bounty LLC Units” (the “LLC unit conversion”);

 

   

Bounty Minerals will issue              shares of Class A common stock to purchasers in this offering in exchange for the proceeds of this offering;

 

   

each Existing Owner will receive a number of shares of Class B common stock equal to the number of Bounty LLC Units held by such Existing Owner, following this offering;

 

   

Bounty Minerals will contribute, directly or indirectly, the net proceeds of this offering to Bounty LLC in exchange for an additional number of Bounty LLC Units such that Bounty Minerals holds, directly or indirectly, a total number of Bounty LLC Units equal to the number of shares of Class A common stock outstanding following this offering; and

 

   

Bounty LLC intends to use a portion of the net proceeds to purchase                 Bounty LLC Units, together with an equal number of shares of Class B common stock, from certain owners of Bounty LLC Units.

After giving effect to these transactions and this offering and assuming the underwriters’ option to purchase additional shares is not exercised:

 

   

the Existing Owners will own all of our Class B common stock, representing         % total voting power of our capital stock;

 

   

investors in this offering will own                  shares of our Class A common stock, or 100% of our Class A common stock, representing         % total voting power of our capital stock;

 

   

Bounty Minerals will own an approximate         % interest in Bounty LLC; and

 

   

the Existing Owners will own an approximate         % interest in Bounty LLC.

If the underwriters’ option to purchase additional shares is exercised in full:

 

   

the Existing Owners will own all of our Class B common stock, representing         % total voting power of our capital stock;

 

   

investors in this offering will own                  shares of our Class A common stock, or 100% of our Class A common stock, representing         % total voting power of our capital stock;

 

   

Bounty Minerals will own an approximate         % interest in Bounty LLC; and

 

   

the Existing Owners will own an approximate         % interest in Bounty LLC.

Each share of Class B common stock has no economic rights but entitles its holder to one vote on all matters to be voted on by stockholders generally. Holders of Class A common stock and Class B common stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. We do not intend to list our Class B common stock on any exchange.

 

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Following this offering, under the Amended and Restated Limited Liability Company Agreement of Bounty LLC (the “Bounty LLC Agreement”), each Existing Owner will, subject to certain limitations, have the right (the “Redemption Right”) to cause Bounty LLC to acquire all or a portion of its Bounty LLC Units for, at Bounty LLC’s election, (i) shares of our Class A common stock at a redemption ratio of one share of Class A common stock for each Bounty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, we (instead of Bounty LLC) will have the right (the “Call Right”) to, for administrative convenience, acquire each tendered Bounty LLC Unit directly from the redeeming Existing Owner for, at our election, (x) one share of Class A common stock or (y) an equivalent amount of cash. Our decision to make a cash payment upon an Existing Owner’s redemption election will be made by our independent directors (within the meaning of the NYSE listing rules and Section 10A-3 of the Securities Act of 1933, as amended (the “Securities Act”)). Such independent directors will determine whether to issue shares of Class A common stock or cash based on facts in existence at the time of the decision, which we expect would include the relative value of the Class A common stock (including trading prices for the Class A common stock at the time), the cash purchase price, the availability of other sources of liquidity (such as an issuance of preferred stock) to acquire the Bounty LLC Units and alternative uses for such cash.

In connection with any redemption of Bounty LLC Units pursuant to the Redemption Right or acquisition pursuant to our Call Right, the corresponding number of shares of Class B common stock will be cancelled. See “Certain Relationships and Related Party Transactions—Bounty LLC Agreement.” The Existing Owners will have the right, under certain circumstances, to cause us to register the offer and resale of their shares of Class A common stock. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

The following diagram indicates our corporate structure immediately preceding this offering and the transactions related thereto:

 

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The following diagram indicates our simplified ownership structure immediately following this offering and the transactions related thereto (assuming that the underwriters’ option to purchase additional shares is not exercised):

 

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(1)

Our Existing Owners will own, in the aggregate, approximately 100% of our Class B common stock and approximately     % of the Bounty LLC Units.

We have granted the underwriters a 30-day option to purchase up to an aggregate of                  additional shares of Class A common stock. Any net proceeds received from the exercise of this option will be contributed to Bounty LLC in exchange for additional Bounty LLC Units, and Bounty LLC intends to use such net proceeds to purchase Bounty LLC Units, together with an

 

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equal number of shares of Class B common stock, from certain owners of Bounty LLC Units and to fund future acquisitions of mineral interests.

Emerging Growth Company

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act (“JOBS Act”). For as long as we are an emerging growth company, unlike other public companies that do not meet those qualifications, we are not required to:

 

   

provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of SOX;

 

   

provide more than two years of audited financial statements and related management’s discussion and analysis of financial condition and results of operations in a registration statement on Form S-1;

 

   

comply with any new requirements adopted by PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

 

   

provide certain disclosure regarding executive compensation required of larger public companies or hold stockholder advisory votes on executive compensation required by the Dodd-Frank Act; or

 

   

obtain stockholder approval of any golden parachute payments not previously approved.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. This permits an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We are choosing to take advantage of this extended transition period and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for private companies.

We will cease to be an “emerging growth company” upon the earliest of: (i) when we have $1.07 billion or more in annual revenues; (ii) when we issue more than $1.0 billion of non-convertible debt over a three-year period; (iii) the last day of the fiscal year following the fifth anniversary of our initial public offering; or (iv) when we have qualified as a “large accelerated filer,” which refers to when we (w) will have an aggregate worldwide market value of voting and non-voting shares of common equity securities held by our non-affiliates of $700 million or more, as of the last business day of our most recently completed second fiscal quarter, (x) have been subject to the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), for a period of at least 12 calendar months, (y) have filed at least one annual report pursuant to Section 13(a) or 15(d) of the Exchange Act, and (z) will no longer be eligible to use the requirements for “smaller reporting companies,” as defined in the Exchange Act, for our annual and quarterly reports.

 

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Principal Executive Offices

Our principal executive offices are located at 777 Main Street, Suite 3400, Fort Worth, Texas 76102, and our telephone number at that address is (817) 332-2700.

Our website address is www.bountyminerals.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this prospectus.

Risk Factors

An investment in our Class A common stock involves risks. You should carefully consider the following considerations, the risks described in “Risk Factors” and the other information in this prospectus, before deciding whether to invest in our Class A common stock. In particular, the following considerations 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 Class A common stock and a loss of all or part of your investment.

Risks Related to Our Business

 

   

A substantial majority of our revenues from the natural gas, NGLs and oil producing activities of our operators are derived from royalty payments that are based on the price at which natural gas, NGLs and oil produced from the acreage underlying our interests are sold. Prices of natural gas, NGLs and oil are volatile due to factors beyond our control. A substantial or extended decline in commodity prices may adversely affect our business, financial condition, results of operations and cash flows.

 

   

All of our properties are located in the Appalachian Basin, making us vulnerable to risks associated with operating in a single geographic area.

 

   

If any operators of our properties suspend our right to receive royalty payments due to title or other issues, our business, financial condition, results of operations and cash flows may be adversely affected.

 

   

We depend on various unaffiliated operators for all of the exploration, development and production on the properties underlying our mineral interests. A significant portion of our revenue is derived from royalty payments made by these operators. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate the wells on our acreage could have an adverse effect on our results of operations and cash flows.

 

   

Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

 

   

We rely on our operators, third parties and government databases for information regarding our assets and, to the extent that information is incorrect, incomplete or lost, our financial and operational information and projections may be incorrect.

 

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We rely on a small number of key individuals whose absence or loss could adversely affect our business.

Risks Related to Our Industry

 

   

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take write-downs of the carrying values of our properties.

 

   

The marketability of natural gas, NGLs and oil production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our operators control. Any limitation in the availability of those facilities could interfere with our operators’ ability to market our operators’ production and could harm our business.

 

   

Drilling for and producing natural gas, NGLs and oil are high-risk activities with many uncertainties that may materially adversely affect our business, financial condition, results of operations and cash flows.

 

   

Conservation measures, technological advances, increased attention to ESG matters and prolonged negative investor sentiment toward natural gas and oil focused companies could materially reduce demand for natural gas, NGLs and oil, availability of capital and adversely affect our results of operations and the trading market for shares of our Class A common stock.

Risks Related to Environmental and Regulatory Matters

 

   

Natural gas, NGLs and oil operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for our operators, and failure to comply could result in our operators incurring significant liabilities, either of which may impact our operators’ willingness to develop our interests.

 

   

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause our operators to incur increased costs, additional operating restrictions or delays and fewer potential drilling locations.

 

   

Legislation or regulatory initiatives intended to address seismic activity could restrict our operators’ drilling and production activities, as well as our operators’ ability to dispose of produced water gathered from such activities, which could have a material adverse effect on their future business, which in turn could have a material adverse effect on our business.

Risks Related to this Offering and Our Class A Common Stock

 

   

We are a holding company. Our sole material asset after completion of this offering will be our equity interest in Bounty LLC and we are accordingly dependent upon distributions from Bounty LLC to pay taxes, cover our corporate and other overhead expenses and pay any dividends on our Class A common stock.

 

   

We will incur increased costs as a result of operating as a public company, including the cost of compliance with securities laws, and our management will be required to devote substantial time to compliance efforts.

 

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We will limit the liability of, and indemnify, our directors and officers.

 

   

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

 

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The Offering

 

Issuer

Bounty Minerals, Inc.

 

Class A common stock offered by us

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

 

Option to purchase additional shares

We have granted the underwriters a 30-day option to purchase up to an aggregate of                 additional shares of our Class A common stock to the extent the underwriters sell more than             shares of Class A common stock in this offering.

 

Class A common stock outstanding immediately after this offering

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

 

Class B common stock outstanding immediately after this offering

            shares (             shares if the underwriters’ option to purchase additional shares is exercised in full) or one share for each Bounty LLC Unit held by the Existing Owners immediately following this offering. Class B shares are non-economic. In connection with any redemption of Bounty LLC Units pursuant to the Redemption Right or acquisition pursuant to our Call Right, the corresponding number of shares of Class B common stock will be cancelled.

 

Voting power of Class A common stock after giving effect to this offering

        % (or         % if the underwriters’ option to purchase additional shares is exercised in full).

 

Voting power of Class B common stock after giving effect to this offering

        % (or         % if the underwriters’ option to purchase additional shares is exercised in full). Upon completion of this offering, the Existing Owners will initially own         shares of Class B common stock, representing approximately         % of the voting power of the Company.

 

Voting rights

Each share of our Class A common stock entitles its holder to one vote on all matters to be voted on by stockholders generally. Each share of our Class B common stock entitles its holder to one vote on all matters to be voted on by stockholders generally. Holders of our Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or

 

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approval, except as otherwise required by applicable law or by our amended and restated certificate of incorporation. See “Description of Capital Stock.”

 

Use of proceeds

We expect to receive approximately $         million of net proceeds, based upon the assumed initial public offering price of $         per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses payable by us. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $         million.

 

  We intend to contribute all of the net proceeds from this offering to Bounty LLC in exchange for Bounty LLC Units. Bounty LLC intends to use approximately $         of the net proceeds from this offering to purchase          Bounty LLC Units, together with an equal number of shares of Class B common stock, from certain owners of Bounty LLC Units (the “Exchanging Members”) (at a purchase price per unit and share of Class B common stock based on the midpoint of the estimated price range set forth on the cover page of this prospectus, net of underwriting discounts and commissions) and approximately $         of the net proceeds from this offering to fund future acquisitions of mineral interests; however, it currently does not have any specific acquisitions planned. Please read “Use of Proceeds.”

 

  If the underwriters exercise their option to purchase additional shares of Class A common stock in full, the additional net proceeds to us will be approximately $         million (based on an assumed initial offering price of $         per share, the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts. We intend to contribute all of the net proceeds to Bounty LLC in exchange for an additional number of Bounty LLC Units equal to the number of shares of Class A Common Stock issued pursuant to the underwriters’ option. Bounty LLC intends to use approximately $         million of the net proceeds from our sale of additional shares to purchase Bounty LLC Units, together with an equal number of shares of Class B common stock, from the Exchanging Members (at a purchase price per unit and share of Class B common stock, based on the midpoint of the estimated price range set forth on the cover page of this prospectus, net of underwriting discounts and commissions) and approximately $         million of net proceeds to fund future acquisitions of mineral interests. Please read “Use of Proceeds.”

 

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Dividend policy

We expect to pay quarterly dividends on our Class A common stock in amounts determined from time to time by our board of directors. However, the declaration and payment of any dividends will be at the sole discretion of our board of directors, which may change our dividend policy at any time. Our payment of dividends may vary from quarter to quarter, may be significantly reduced or may be eliminated entirely. Future dividend levels will depend on the earnings of our subsidiaries, including Bounty LLC, their financial condition, cash requirements, regulatory restrictions, any restrictions in financing agreements and other factors deemed relevant by the board. Please read “Dividend Policy.”

 

Redemption rights of Existing Owners

Under the Bounty LLC Agreement, each Existing Owner will, subject to certain limitations, have the right, pursuant to the Redemption Right, to cause Bounty LLC to acquire all or a portion of its Bounty LLC Units for, at Bounty LLC’s election, (i) shares of our Class A common stock at a redemption ratio of one share of Class A common stock for each Bounty LLC Unit redeemed, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions, or (ii) an equivalent amount of cash. Alternatively, upon the exercise of the Redemption Right, we (instead of Bounty LLC) will have the right, pursuant to the Call Right, to acquire each tendered Bounty LLC Unit directly from the redeeming Existing Owner for, at our election, (x) one share of Class A common stock or (y) an equivalent amount of cash. Our decision to cause Bounty LLC to make a cash payment or to effect a direct exchange upon an Existing Owner’s redemption election will be made by our independent directors (within the meaning of the NYSE listing rules and Section 10A-3 of the Securities Act). In connection with any redemption of Bounty LLC Units pursuant to the Redemption Right or acquisition pursuant our Call Right, the corresponding number of shares of Class B common stock will be cancelled. See “Certain Relationships and Related Party Transactions—Bounty LLC Agreement.”

 

Directed share program

The underwriters have reserved for sale at the initial public offering price up to         % of the Class A common stock being offered by this prospectus for sale to our employees, executive officers, directors, business associates and related persons who have expressed an interest in purchasing Class A common stock in this offering. We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of shares available to the general public.

 

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The sales of shares pursuant to the directed share program will be made by             , an underwriter of this offering. Please read “Underwriting.”

 

Listing and trading symbol

We intend to apply to list our Class A common stock on the NYSE under the symbol “BNTY.”

 

Risk factors

You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our Class A common stock.

Unless indicated otherwise, information regarding outstanding shares of our Class A common stock does not include (i) shares of Class A common stock reserved for issuance pursuant to our LTIP (as defined in “Executive Compensation—Long-Term Incentive Plan”) or (ii) the grants of equity awards to certain of our directors, officers and employees upon consummation of this offering (as described in “Executive Compensation”).

 

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Summary Historical and Pro Forma Financial Data

Bounty Minerals was formed in June 2022 and has limited historical financial operating results. The following table shows summary historical consolidated financial data, for the periods and as of the dates indicated, of our accounting predecessor, Bounty LLC, and summary pro forma financial data for Bounty Minerals. The summary historical consolidated financial data of our predecessor as of and for the six months ended June 30, 2022 and 2021 and the years ended December 31, 2021 and 2020 were derived from the unaudited and audited historical consolidated financial statements of our predecessor included elsewhere in this prospectus.

The summary unaudited pro forma statement of operations and balance sheet data as of and for the six months ended June 30, 2022 has been prepared to give pro forma effect to (i) our corporate reorganization and (ii) this offering and the application of the net proceeds therefrom as if each had been completed on January 1, 2021, in the case of the statement of operations data, and on June 30, 2022, in the case of the balance sheet data. The summary unaudited pro forma statement of operations for the year ended December 31, 2021, has been prepared to give pro forma effect to (i) our corporate reorganization and (ii) this offering and the application of the net proceeds therefrom as if each had been completed on January 1, 2021. This information is subject to and gives effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The summary unaudited pro forma financial data is presented for informational purposes only, should not be considered indicative of actual results of operations that would have been achieved had such transactions been consummated on the dates indicated and does not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

For a detailed discussion of the summary historical financial data contained in the following table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table should also be read in conjunction with “Use of Proceeds” and the historical financial statements of Bounty LLC and the pro forma financial statements of Bounty Minerals included elsewhere in this prospectus. Among other things, the historical and pro forma financial statements include more detailed information regarding the basis of presentation for the information in the following table.

 

    Predecessor
Historical
    Bounty Minerals
Pro Forma
 
    Six Months Ended June 30,     Year Ended December 31,     Six Months
Ended June 30,
    Year Ended
December 31,
 
          2022                 2021                 2021                 2020                 2022           2021  
    (unaudited)                 (unaudited)  
    (In thousands, except per share data)  

Statement of Operations Data:

           

Revenue:

           

Oil and gas royalty

  $ 50,239     $ 23,347     $ 69,218     $ 26,606     $           $                

Lease bonus

    13,369       3,673       5,215       3,024      
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenue

    63,607       27,020       74,433       29,630      
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Expense:

           

Royalty deductions (1)

    4,318       3,452       8,637       4,987      

County and other taxes

    291       183       411       326      

Acquisition and land costs

    2       1,640       1,686       274      

Depletion and depreciation

    5,985       6,591       12,788       11,692      

 

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    Predecessor
Historical
    Bounty Minerals
Pro Forma
 
    Six Months Ended June 30,     Year Ended December 31,     Six Months
Ended June 30,
    Year Ended
December 31,
 
          2022                 2021                 2021                 2020                 2022           2021  
    (unaudited)                 (unaudited)  
    (In thousands, except per share data)  

Share-based compensation

                           

General and administrative

    4,017       3,056       5,915       6,532      
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expense

    14,613       14,922       29,436       23,811      
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income from operations

  $ 48,995     $ 12,098     $ 44,996     $ 5,819     $       $    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other income (expense):

           

Other income

    1,026       1       2       175      

Interest expense

                      (57    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income, net

    1,026       1       2       117      
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income before income tax expense

  $ 50,020     $ 12,099     $ 44,998     $ 5,936     $               $    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income tax expense

                           

Net Income

  $ 50,020     $ 12,099     $ 44,998     $ 5,936     $       $    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Non-controlling interest

           

Net income attributable to Class A common stockholders

           

Net income per share attributable to Class A common stockholders:

           

Basic

           

Diluted

           

Weighted-average number of shares:

           

Basic

           

Diluted

           

Other Financial Data:

           

Adjusted EBITDA (2)

  $ 54,981     $ 18,831     $ 57,926     $ 17,511     $       $                

Adjusted EBITDA ex lease bonus (2)

    41,612       16,582       54,135       14,487      

Cash available for distribution(2)

    41,612       16,582       54,135       14,430      

Balance Sheet Data:

           

Cash and cash equivalents

  $ 27,571     $ 9,243     $ 13,556     $ 10,262     $       $                

Total assets

    473,931       454,872       462,308       458,078      

Total liabilities

    5,685       2,554       2,090       358      

Total liabilities and members’ equity

    473,931       454,872       462,308       458,078      

 

(1)

Royalty deductions include the Company’s share of expenses for transportation, gathering, compression, processing and severance taxes.

(2)

Please read “—Non-GAAP Financial Measures” below for the definitions of Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution and a reconciliation of Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution to our most directly comparable financial measure, calculated and presented in accordance with generally accepted accounting principles in the United States (“GAAP”).

 

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Non-GAAP Financial Measures

Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution are non-GAAP supplemental financial measures used by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets and their ability to sustain dividends over the long term without regard to financing methods, capital structure or historical cost basis.

We and Bounty LLC define Adjusted EBITDA as net income (loss) before interest expense, taxes and depreciation, depletion and amortization, less other income, gain or loss on sale of oil and gas properties, stock-based compensation expense and adjusted for certain other non-cash items. We and Bounty LLC define Adjusted EBITDA ex lease bonus as Adjusted EBITDA further adjusted to eliminate the impacts of lease bonus revenue we receive due to the unpredictability of timing and magnitude of the revenue. We and Bounty LLC define cash available for distribution as Adjusted EBITDA ex lease bonus less interest expense and cash taxes.

Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution do not represent and should not be considered alternatives to, or more meaningful than, net income, income from operations, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of our financial performance. Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution have important limitations as analytical tools because they exclude some but not all items that affect net income, the most directly comparable GAAP financial measure. Our and Bounty LLC’s computation of Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution may differ from computations of similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution to the most directly comparable GAAP financial measure for the periods indicated.

 

    Predecessor
Historical
    Bounty Minerals
Pro Forma
 
    Six Months
Ended
June 30,
    Year Ended
December 31,
    Six Months
Ended
June 30,
    Year Ended
December 31,
 
    2022     2021           2021               2020           2022     2021  
                            (unaudited)        
    (in thousands)  

Reconciliation of Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution to net income:

           

Net income

  $ 50,020     $ 12,099     $ 44,998     $ 5,936     $                   $                

Add:

           

Interest expense

                      57      

Taxes

                           

Depreciation and depletion

    5,985       6,591       12,788       11,692      

Other non-cash items (1)

    2       142       142        

Less:

           

Other income, net

    1,026       1       2       175      

Gain on sale of oil and gas properties

                           

Stock-based compensation expense

                           
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 54,981     $ 18,831     $ 57,926     $ 17,511     $       $    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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    Predecessor
Historical
    Bounty Minerals
Pro Forma
 
    Six Months
Ended
June 30,
    Year Ended
December 31,
    Six Months
Ended
June 30,
    Year Ended
December 31,
 
    2022     2021           2021               2020           2022     2021  
                            (unaudited)        
    (in thousands)  

Less:

           

Cash lease bonus

    13,369       2,249       3,791       3,024      
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA ex lease bonus

  $ 41,612     $ 16,582     $ 54,135     $ 14,487     $       $    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Less:

           

Interest expense

                      57      

Cash Taxes

                           
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash available for distribution

  $ 41,612     $ 16,582     $ 54,135     $ 14,430     $       $    
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

Includes a contingent liability for title disputes and the non-cash portion of lease bonus income paid as mineral interests in 2021. See Note 4—Acquisitions to our consolidated financial statements for the years ended December 31, 2021 and 2020 included elsewhere in this prospectus. Includes non-cash rent expense in 2022.

 

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Summary Reserve Data

The following table sets forth estimates of our net proved, probable and possible natural gas, NGLs and oil reserves as of June 30, 2022 and December 31, 2021 based on reserve reports prepared by CG&A. The reserve reports were prepared in accordance with the rules and regulations of the SEC. You should refer to “Risk Factors,” “Business—Natural Gas, NGLs and Oil Data—Proved, Probable and Possible Reserves,” “Business—Natural Gas, NGLs and Oil Production Prices and Costs—Production and Price History,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and notes thereto included herein in evaluating the material presented below. The following table provides our estimated proved, probable and possible reserves as of June 30, 2022 and December 31, 2021 using the provisions of the SEC rule regarding reserve estimation regarding a historical twelve-month pricing average applied prospectively.

 

     June 30, 2022 (1)      December 31, 2021 (2)  

Estimated proved developed reserves:

     

Natural gas (MMcf)

     81,833        81,961  

NGLs (MBbls)

     3,960        3,875  

Oil (MBbls)

     441        490  
  

 

 

    

 

 

 

Total (MMcfe) (3)

     108,238        108,151  

Estimated proved undeveloped reserves:

     

Natural gas (MMcf)

     67,831        71,786  

NGLs (MBbls)

     3,006        1,894  

Oil (MBbls)

     364        374  
  

 

 

    

 

 

 

Total (MMcfe) (3)

     88,050        85,394  

Estimated proved reserves:

     

Natural gas (MMcf)

     149,665        153,746  

NGLs (MBbls)

     6,966        5,769  

Oil (MBbls)

     805        863  
  

 

 

    

 

 

 

Total (MMcfe) (3)

     196,288        193,538  

Estimated probable reserves (4):

     

Natural gas (MMcf)

     413,699        390,431  

NGLs (MBbls)

     14,282        14,417  

Oil (MBbls)

     2,394        2,209  
  

 

 

    

 

 

 

Total (MMcfe) (3)

     513,757        490,187  

Estimated possible reserves (4):

     

Natural gas (MMcf)

     224,989        242,490  

NGLs (MBbls)

     5,791        6,379  

Oil (MBbls)

     731        706  
  

 

 

    

 

 

 

Total (MMcfe) (3)

     264,122        285,000  

Natural Gas and Oil Prices:

     

Natural gas—Henry Hub spot price per MMBtu

   $ 5.13      $ 3.598  

Oil—WTI posted price per Bbl

   $ 85.78      $ 66.56  

 

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(1)

Our estimated net proved, probable and possible reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For gas volumes, the average Henry Hub spot price of $5.134 per MMBtu as of June 30, 2022 was adjusted for local basis differential, treating cost, transportation, gas shrinkage and gas heating value (BTU content). For NGLs and oil volumes, the average West Texas Intermediate posted price of $85.78 per barrel as of June 30, 2022 was adjusted for local basis differential, treating cost, transportation and/or crude quality and gravity corrections. All economic factors were held constant throughout the lives of the properties in accordance with SEC guidelines. The average adjusted product prices weighted by production over the remaining lives of the proved properties were $4.685 per Mcf of gas, $35.58 per barrel of NGLs and $77.00 per barrel of oil as of June 30, 2022.

(2)

Our estimated net proved, probable and possible reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For gas volumes, the average Henry Hub spot price of $3.598 per MMBtu as of December 31, 2021 was adjusted for local basis differential, treating cost, transportation, gas shrinkage and gas heating value (BTU content). For NGLs and oil volumes, the average West Texas Intermediate posted price of $66.56 per barrel as of December 31, 2021 was adjusted for local basis differential, treating cost, transportation and/or crude quality and gravity corrections. All economic factors were held constant throughout the lives of the properties in accordance with SEC guidelines. The average adjusted product prices weighted by production over the remaining lives of the proved properties were $2.71 per Mcf of gas, $23.84 per barrel of NGLs and $55.19 per barrel of oil as of December 31, 2021.

(3)

We present our total production on an Mcfe basis, calculated at the rate of one barrel per six Mcf based upon the relative energy content. This is an energy content correlation and does not reflect the price or value relationship between oil and natural gas.

(4)

All of our estimated probable and possible reserves are classified as undeveloped. Please see “Business—Natural Gas, NGLs and Oil Data—Proved, Probable and Possible Reserves—Estimation of Possible Reserves” for a description of the uncertainties associated with, and the inherently imprecise nature of, our estimated probable and possible reserves.

 

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RISK FACTORS

Investing in our Class A common stock involves risks. You should carefully consider the information in this prospectus, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” and the following risks before making an investment decision. The trading price of our Class A common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to Our Business

A substantial majority of our revenues are derived from royalty payments that are based on the price at which natural gas, NGLs and oil produced from the acreage underlying our interests are sold. Prices of natural gas, NGLs and oil are volatile due to factors beyond our control. A substantial or extended decline in commodity prices may adversely affect our business, financial condition, results of operations and cash flows.

Our revenues, operating results, cash available for distribution and the carrying value of our mineral interests depend significantly upon the prevailing prices for natural gas, NGLs and oil. Historically, natural gas, NGLs and oil prices and their applicable basis differentials have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

 

   

general market conditions, including fluctuations in commodity prices and macroeconomic trends;

 

   

the domestic and worldwide supply of and demand for natural gas, NGLs and oil;

 

   

the level of prices and market expectations about future prices of natural gas, NGLs and oil;

 

   

the level of global natural gas, NGLs and oil exploration and production;

 

   

the cost of exploring for, developing, producing and delivering natural gas, NGLs and oil;

 

   

the price and quantity of foreign imports and U.S. exports of natural gas, NGLs and oil;

 

   

the level of U.S. domestic production;

 

   

changes in U.S. energy policy;

 

   

political and economic conditions in natural gas, NGLs and oil producing regions, including the Middle East, Africa, South America and Russia;

 

   

global or national health concerns, including the outbreak of an illness pandemic (like COVID-19), which may reduce demand for natural gas, NGLs and oil due to reduced global or national economic activity;

 

   

the ability of members of the Organization of Petroleum Exporting Countries and other oil exporting nations to agree to and maintain price and production controls;

 

   

the ability of Iran and Russia to increase the export of oil and natural gas upon the relaxation of international sanctions;

 

   

speculative trading in natural gas, NGLs and oil derivative contracts;

 

   

the level of consumer product demand;

 

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weather conditions and other natural disasters, such as flooding and winter storms, the frequency and impact of which could be increased by the effects of climate change;

 

   

risks associated with operating drilling rights;

 

   

technological advances affecting energy consumption, energy storage and energy supply;

 

   

domestic and foreign governmental regulations and taxes;

 

   

the continued threat of terrorism and the impact of military and other action, including the military conflict in Ukraine and economic sanctions such as those imposed by the U.S. on oil and natural gas exports from Iran and Russia;

 

   

the proximity, cost, availability and capacity of natural gas, NGLs and oil pipelines and other transportation facilities;

 

   

the price and availability of alternative fuels; and

 

   

overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, NGLs and oil price movements with any certainty. For example, during the past five years, the Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. In addition, the market price for natural gas historically fluctuates between producing basins relative to NYMEX Henry Hub. Because our production and reserves predominantly consist of natural gas (approximately 76% of our production for the six months ended June 30, 2022, and 81% of our 3P reserves as of June 30, 2022), changes in natural gas prices have significantly greater impact on our financial results than oil prices. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, which adds further volatility to the pricing of NGLs.

Any substantial decline in the price of natural gas, NGLs and oil or prolonged period of low commodity prices will materially adversely affect our business, financial condition, results of operations and cash flows. In addition, natural gas, NGLs and oil prices may reduce the amount of natural gas, NGLs and oil that can be produced economically by our operators, which may reduce our operators’ willingness to develop our properties. This may result in our having to make substantial downward adjustments to our estimated proved, probable and possible reserves, which could negatively impact our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, the successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our natural gas and oil properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce natural gas, NGLs or oil in commercially paying quantities. We may choose to use various derivative instruments in the future in connection with anticipated natural gas, NGLs and oil sales to minimize the impact of commodity price fluctuations. However, we cannot hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.

 

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All of our properties are located in the Appalachian Basin, making us vulnerable to risks associated with operating in a single geographic area.

All of our properties are located in the Appalachian Basin in West Virginia, Pennsylvania and Ohio. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by, and costs associated with, governmental regulation, political activities, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations, natural disasters, adverse weather conditions, including water shortages or drought related conditions, plant closures for scheduled maintenance or interruption of the processing or transportation of natural gas, NGLs and oil. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic natural gas producing areas such as the Appalachian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

If any operators of our properties suspend our right to receive royalty payments due to title or other issues, our business, financial condition, results of operations and cash flows may be adversely affected.

We depend in part on acquisitions to grow our reserves, production and cash generated from operations. In connection with these acquisitions, record title to mineral interests are conveyed to us or our subsidiaries by asset assignment, and we or our subsidiaries become the record owner of these interests. Upon such a change in ownership of mineral interests, and at regular intervals pursuant to routine audit procedures at each of our operators otherwise at its discretion, the operator of the underlying property has the right to investigate and verify the title and ownership of mineral interests with respect to the properties it operates. If any title or ownership issues are not resolved to its reasonable satisfaction in accordance with customary industry standards, the operator may suspend payment of the related royalty. If an operator of our properties is not satisfied with the documentation we provide to validate our ownership, it may place our royalty payment in suspense until such issues are resolved, at which time we would receive in full the payments that would have been made during the suspension period, without interest. Certain of our operators impose significant documentation requirements for title transfer and may keep royalty payments in suspense for significant periods of time. During the time that an operator puts our assets in pay suspense, we would not receive the applicable mineral or royalty payment owed to us from sales of the underlying natural gas, NGLs or oil related to such mineral interest.

Title to the properties in which we have an interest may be impaired by title defects.

We are not required to, and under certain circumstances we may elect not to, incur the expense of retaining lawyers to examine the title to our royalty and mineral interests. In such cases, we would rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before acquiring a specific royalty or mineral interest. Leases in the Appalachian Basin, and particularly leases involving oil and gas properties, are particularly vulnerable to title deficiencies due to the long history of land ownership in the area, resulting in extensive and complex chains of title. The existence of a material title deficiency can render an interest worthless and can materially adversely affect our business results of operations, financial condition and cash flows. No assurance can be given that we will not suffer a monetary loss from title defects or title failure.

 

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We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments.

We may experience delays in receiving royalty payments from our operators, including as a result of delayed division orders received by our operators. A failure on the part of the operators to make royalty payments typically gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time.

We depend on various unaffiliated operators for all of the exploration, development and production on the properties underlying our mineral interests. A significant amount of our revenue is derived from royalty payments and lease bonus payments made by these operators. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate the wells on our acreage could have an adverse effect on our results of operations and cash flows.

Our assets consist of mineral interests. Because we depend on third-party operators for all of the exploration, development and production on our properties, we have little to no control over the operations related to our properties. For example, we cannot control whether an operator chooses to develop a property or the success of drilling and development activities of the properties which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. When we evaluate acquisition opportunities and the likelihood of the successful and complete development of our properties, we consider which companies we expect to operate our properties. Historically, many of our properties have been operated by active, well-capitalized operators that have expressed their intent to execute multi-year development programs. There is no guarantee, however, that such operators will become or remain the operators on our properties or that their development plans will not change. For the six months ended June 30, 2022, we received revenue from more than 80 operators, four of which accounted for more than 25% of such revenues. The failure of our operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues. In particular, partly in response to the significant decrease in prices for gas in 2020, many of our operators substantially reduced their planned development activities and capital expenditures in late 2020 and early 2021. The number of new wells drilled in many of our focus areas decreased in early 2021, and such slower development pace may occur again in the future. Additionally, certain investors of many oil and gas operators have requested operators adopt initiatives to return capital to investors, which could also reduce the capital available to our operators for investment in exploration, development and production activities. Our operators may further reduce capital expenditures devoted to exploration, development and production on our properties in the future, which could negatively impact revenues we receive.

If production on our acreage interests decreases due to decreased development activities, as a result of a low commodity price environment, limited availability of development capital, an increase in the capital costs required for drilling activities by our operators, production-related difficulties or otherwise, our results of operations may be adversely affected. Our operators are often not obligated to undertake any development activities other than those required to maintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to their reasonable discretion (subject to certain implied obligations to develop imposed by the laws of some states). Our operators could determine to drill

 

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and complete fewer wells on our acreage than is currently expected. The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that are largely outside of our control, including:

 

   

the capital costs required for drilling activities by our operators, which could be significantly more than anticipated;

 

   

the ability of our operators to access capital;

 

   

prevailing commodity prices;

 

   

the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;

 

   

the availability of storage for hydrocarbons,

 

   

the operators’ expertise, operating efficiency and financial resources;

 

   

approval of other participants in drilling wells;

 

   

the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;

 

   

the selection of technology;

 

   

the selection of counterparties for the marketing and sale of production; and

 

   

the rate of production of the reserves.

The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our results of operations and cash flows. Sustained reductions in production by the operators on our properties may also adversely affect our results of operations and cash flows. Additionally, if an operator were to experience financial difficulty, the operator might not be able to pay its royalty payments or continue its operations, which could have a material adverse impact on our cash flows.

Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.

Even if we make acquisitions that we believe will increase our cash generated from operations, these acquisitions may nevertheless result in a decrease in our cash flows. Any acquisition involves potential risks, including, among other things:

 

   

the validity of our assumptions about estimated proved, probable and possible reserves, future production and volume and timing of future production, prices, revenues, capital expenditures, the operating expenses and costs our operators would incur to develop the minerals;

 

   

a decrease in our liquidity by using a significant portion of our cash generated from operations or incurring debt to finance acquisitions;

 

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a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;

 

   

the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;

 

   

mistaken assumptions about the overall cost of equity or debt;

 

   

our inability to obtain satisfactory title to the assets we acquire;

 

   

an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; and

 

   

the occurrence of other significant changes, such as impairment of natural gas and oil properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

The ability of our operators to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availability of capital, construction of and limitations on access to infrastructure, inclement weather, regulatory changes and approvals, natural gas, NGLs and oil prices, costs, drilling results and the availability of water. Further, our operators’ identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable our operators to know conclusively prior to drilling whether natural gas, NGLs or oil will be present or, if present, whether natural gas, NGLs or oil will be present in sufficient quantities to be economically viable. Even if sufficient amounts of natural gas or oil exist, our operators may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If our operators drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business as well as ours.

There is no guarantee that the conclusions our operators draw from available data from the wells on our acreage, more fully explored locations or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Additionally, actual production from wells may be less than expected. Because of these uncertainties, we do not know if the potential drilling locations our operators have identified will ever be drilled or if our operators will be able to produce natural gas, NGLs or oil from these or any other potential drilling locations. As such, the actual drilling activities of our operators may materially differ from those presently identified, which could adversely affect our business, results of operation and cash flows.

Finally, the potential drilling locations we have identified are based on the geologic and other data available to us and our interpretation of such data. As a result, our operators may have reached different conclusions about the potential drilling locations on our properties, and our operators control the ultimate decision as to where and when a well is drilled.

 

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We rely on our operators, third parties and government databases for information regarding our assets and, to the extent that information is incorrect, incomplete or lost, our financial and operational information and projections may be incorrect.

As an owner of mineral interests, we rely on the operators of our properties to notify us of information regarding production on our properties in a timely and complete manner, as well as the accuracy of information obtained from third parties and government databases. We use this information to evaluate our operations and cash flows, as well as to predict our expected production and possible future locations. To the extent we do not timely receive this information or the information is incomplete or incorrect, our results may be incorrect and our ability to project potential growth may be materially adversely affected. Furthermore, to the extent we have to update any publicly disclosed results or projections made in reliance on this incorrect or incomplete information, investors could lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock. If any of such third-party or government databases or systems were to fail for any reason, including as a result of a cyber-attack, possible consequences include loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any of the foregoing consequences could material adversely affect our business.

Acquisitions and our operators’ development of our leases will require substantial capital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.

The natural gas and oil industry is capital intensive. We make and may continue to make substantial capital expenditures in connection with the acquisition of mineral and royalty interests. To date, we have financed capital expenditures with funding from capital contributions and cash generated by operations.

In the future, we may need capital in excess of the amounts we retain in our business. Furthermore, we cannot assure you that we will be able to access other external capital on terms favorable to us or at all. For example, our ability to secure financing in the capital markets on terms favorable to us may be adversely impacted. Additionally, our ability to secure financing or access the capital markets could be adversely affected if financial institutions and institutional lenders elect not to provide funding for fossil fuel energy companies in connection with the adoption of sustainable lending initiatives or are required to adopt policies that have the effect of reducing the funding available to the fossil fuel sector. If we are unable to fund our capital requirements, we may be unable to complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our results of operation and free cash flow.

Most of our operators are also dependent on the availability of external debt, equity financing sources and operating cash flows to maintain their drilling programs. If those financing sources are not available to the operators on favorable terms or at all, then we expect the development of our properties to be adversely affected. If the development of our properties is adversely affected, then revenues from our mineral interests may decline.

Our reserves may not ultimately be developed or produced by the operators of our properties or may take longer to develop than anticipated.

As of June 30, 2022, only 108,238 MMcfe of our total estimated reserves were proved developed reserves. The remaining 88,050 MMcfe, 513,757 MMcfe and 264,122 MMcfe of our total estimated reserves were PUDs, probable undeveloped reserves and possible undeveloped reserves,

 

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respectively, and may not be ultimately developed or produced by the operators of our properties. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations by the operators of our properties. The reserve data included in the reserve report of our independent petroleum engineer assume that substantial capital expenditures by the operators of our properties are required to develop such reserves. We use publicly available information to assess the estimated costs of development of these reserves and the scheduled development plans of our operators. We cannot be certain that the estimated costs of the development of these reserves are accurate, that our operators will develop the properties underlying our royalties as scheduled or that the results of such development will be as estimated. The development of such reserves may take longer as a result of a variety of factors, including, for example, unexpected drilling conditions, lack of proximity to and shortage of capacity of transportation facilities, equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services and compliance with governmental requirements, and may require higher levels of capital expenditures from the operators than we anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases or continued volatility in commodity prices will reduce the future net revenues of our estimated undeveloped reserves and may result in some projects becoming uneconomical for the operators of our properties. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as undeveloped reserves.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as our operators pursue their drilling programs. Moreover, we may be required to write-down our proved undeveloped reserves if those wells are not drilled within the required five-year timeframe. Furthermore, we make our determinations about their estimated drilling schedules from any development provisions in the relevant lease agreement and the historical drilling activity, rig locations, production data and permit trends, as well as investor presentations and other public statements of the operators of our properties. Although we believe that our approach in making such determinations is conservative, the accuracy of any such determination is inherently uncertain and subject to a number of assumptions and factors outside of our control. A reduction in the expected number of wells to be drilled on our acreage by our operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on our results of operations. In particular, partly in response to the significant decrease in prices for oil in 2020, many of our operators substantially reduced their development activities and capital expenditures in 2021. The number of new wells drilled in many of our focus areas decreased in 2021, and such slower development pace may occur again in the future. Any significant variance between our estimates and the actual drilling schedules of our operators may require us to write-down our proved undeveloped reserves.

The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.

We face risks related to the outbreak of illness, pandemics and public health crises, including the COVID-19 pandemic. The effects of the COVID-19 pandemic, including travel bans, prohibitions on group events and gatherings, shutdowns of certain businesses, curfews, shelter-in-place orders and recommendations to practice social distancing in addition to other actions taken by both businesses and governments, resulted in a significant and swift reduction in international and U.S. economic activity.

 

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Since the beginning of 2021, the distribution of COVID-19 vaccines progressed and many government-imposed restrictions were relaxed or rescinded. However, we continue to monitor the effects of the pandemic on our operations. As a result of the ongoing COVID-19 pandemic, our operations, and those of our operators, have and may continue to experience delays or disruptions and temporary suspensions of operations. In addition, our results of operations and financial condition have been and may continue to be adversely affected by the ongoing COVID-19 pandemic.

The extent to which our operating and financial results are affected by COVID-19 will depend on various factors and consequences beyond our control, such as the emergence of more contagious and harmful variants of the COVID-19 virus, the duration and scope of the pandemic, additional actions by businesses and governments in response to the pandemic, and the speed and effectiveness of responses to combat the virus. COVID-19, and the volatile regional and global economic conditions stemming from the pandemic, could also aggravate the other risk factors that we identify herein. While the effects of the COVID-19 pandemic have lessened recently in the United States, we cannot predict the duration or future effects of the pandemic, or more contagious and harmful variants of the COVID-19 virus, and such effects may materially adversely affect our results of operations and financial condition in a manner that is not currently known to us or that we do not currently consider to present significant risks to our operations.

Inflation could adversely impact our operators’ ability to control costs, including their operating expenses and capital costs.

Although inflation in the United States has been relatively low in recent years, it rose significantly beginning in the second half of 2021. This is primarily believed to be the result of the economic impact from global armed conflict and the COVID-19 pandemic, including the effects of global supply chain disruptions, strong economic recovery and associated widespread demands for goods and government stimulus packages, among other factors. Global, industry-wide supply chain disruptions caused by the armed conflict involving Russia and Ukraine and the COVID-19 pandemic have resulted in shortages in labor, materials and services. Such shortages have resulted in inflationary cost increases for labor, materials and services and could continue to cause costs to increase as well as scarcity of certain products and raw materials. To the extent elevated inflation remains, our operators may experience further cost increases for their labor and operations, including oilfield services and equipment. An increase in natural gas and oil prices may cause the costs of materials and services to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent our operators are unable to recover higher costs through higher commodity prices and revenues or otherwise mitigate the impact of such costs on their business, would negatively impact our operators’ business, financial condition and results of operations.

We do not currently have in place, nor do we plan to enter into in the near future, hedging arrangements with respect to the natural gas, NGLs and oil production from our properties, and we will be exposed to the impact of decreases in the price of natural gas, NGLs and oil.

We do not currently have in place, nor do plan to enter into, hedging arrangements to establish, in advance, a price for the sale of the natural gas, NGLs and oil produced from our properties. As a result, although we may realize the benefit of any short-term increase in the price of natural gas, NGLs and oil, we will not be protected against decreases in the price or prolonged periods of low commodity prices, which, in combination with substantially all of our properties being located solely in the Appalachian Basin, could materially adversely affect our business, results of operation and cash available for distribution. If we enter into hedging arrangements in the future, it may limit our ability to realize the benefit of rising prices and may result in hedging losses.

 

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Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

It is not possible to measure underground accumulation of natural gas, NGLs or oil in an exact way. Natural gas, NGLs and oil reserve engineering is not an exact science and requires subjective estimates of underground accumulations of natural gas, NGLs and oil and assumptions concerning future natural gas, NGLs and oil prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved, probable and possible reserves, projections of future production rates and the timing of development expenditures may turn out to be incorrect. Estimates of our proved, probable and possible reserves and related valuations as of June 30, 2022, December 31, 2021 and 2020 were prepared by CG&A. CG&A, an independent petroleum engineering firm, conducted a detailed review of all of our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production and changes in prices. In estimating our reserves, we and our reserve engineers make certain assumptions that may prove to be incorrect, including assumptions regarding future oil and natural gas prices, production levels and operating and development costs. In addition, certain assumptions regarding future natural gas, NGLs and oil prices, production levels and operating and development costs may prove incorrect. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and future cash generated from operations. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas, NGLs and oil that are ultimately recovered being different from our reserve estimates. Estimates of probable and possible reserves are inherently imprecise. Due to a variety of factors, probable and possible undeveloped reserves are less likely to be recovered then proved undeveloped reserves.

Furthermore, the present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board, we base the estimated discounted future net cash flows from our proved reserves on the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows 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 and oil industry in general.

We rely on a small number of key individuals whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of individuals. We rely on members of our executive management team for their knowledge of natural gas and oil industry, relationships within the industry and experience in identifying, evaluating and completing acquisitions, especially in the Appalachian Basin. The loss of their services, and the inability to recruit or retain key personnel, could adversely affect our business. In

 

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particular, the loss of the services of one or more members of our executive team could disrupt our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.

In addition, the success of our operations will depend, in part, on our ability to identify, attract, develop and retain experienced personnel. There is competition within our industry for experienced technical personnel and certain other professionals, which could increase the costs associated with identifying, attracting and retaining such personnel. Other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. If we cannot identify, attract, develop and retain our technical and professional personnel or attract additional experienced technical and professional personnel, our ability to compete in our industry could be harmed.

We utilize a small number of consultants to assist in the review and evaluation of our properties and potential acquisitions, and assist in our preparation of internal reserve estimates.

In connection with the operation of our business, we contract and engage a small number of consultants to assist with the review and evaluation of our properties, as well as potential properties pursuant to our acquisition strategy, and assist in our preparation of internal reserve estimates. In accordance with their duties, such consultants have access to publicly available data such as (i) historical operating data and estimates, including production volumes, marketing of products, operating and capital expenditures, environmental and other liabilities, effects of regulatory changes and the number of producing wells and acreage, (ii) geological data relating to reserves, as well as related projections regarding production, operating expenses and capital expenses used in connection with the preparation of the reserve report and (iii) forward-looking information and estimates relating to production and drilling plans. While we request material information from our consultants to conduct our operations, we do not control the preparation of this information and rely on our consultants to provide accurate and timely information. If we were to lose the services of any one of these consultants, we may be unable to replace them with other providers in a timely manner or on favorable terms, which could increase our costs, interrupt or delay our operations, and adversely affect our results of operations and financial position.

Our future success depends on replacing reserves through acquisitions and the exploration and development activities of our operators.

Producing natural gas and oil wells, and associated NGLs, are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our natural gas, NGLs and oil reserves and our operators’ production thereof and our cash flows are highly dependent on the successful development and exploitation of our current reserves and our ability to successfully acquire additional reserves that are economically recoverable. Moreover, the production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to find, acquire or develop additional reserves to replace the current and future production of our properties at economically acceptable terms. Aside from acquisitions, we have little to no control over the exploration and development of our properties. Furthermore, acquiring natural gas, NGLs and oil properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties and facilities, including through third-party inspections, but such a review will not necessarily reveal all existing or potential problems and through such

 

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review we may not physically inspect every well or pipeline. If we are not able to adequately replace or grow our natural gas, NGLs and oil reserves, our business, financial condition and results of operations would be adversely affected.

Acreage must be drilled before lease expiration, generally within one to five years, in order to hold the acreage by production. Our operators’ failure to drill sufficient wells to hold acreage may result in the deferral of prospective drilling opportunities.

Leases on natural gas and oil properties typically have a term of one to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. In addition, even if production or drilling is established during such primary term, if production or drilling ceases on the leased property, the lease typically terminates, subject to certain exceptions.

Any reduction in our operators’ drilling programs, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the expiration of existing leases. If the lease governing any of our mineral interests expires or terminates, all mineral rights revert back to us and we will have to seek new lessees to explore and develop such mineral interests and we may be unable to do so on as favorable terms or in a timely manner, which could materially and adversely affect the growth of our financial condition, results of operations and cash flows.

Operating hazards and uninsured risks may result in substantial losses to our operators, and any losses could adversely affect our results of operations and cash flows.

The operations of our operators will be subject to all of the hazards and operating risks associated with drilling for and production of natural gas, NGLs and oil, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, NGLs and oil, and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as NGLs and oil spills, natural gas leaks and ruptures or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to our operators due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

We and our operators are subject to cybersecurity attacks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.

The oil and gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The United States government has issued public warnings that indicate that energy assets might be specific targets of cybersecurity threats. For example, on April 29, 2021, Colonial Pipeline Co. suffered a cyber incident that resulted in fuel shortages across the east coast of the United States. We regularly enter into transactions directly with individual mineral and royalty interest owners, who may have less sophisticated electronic systems or networks and may be more vulnerable to cyber-attacks. Our technologies, systems and networks, and those of our operators, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cybersecurity risks may not be sufficient. In addition,

 

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our efforts to monitor, mitigate and manage these evolving risks may result in increased capital and operating costs, but there can be no assurance that such efforts will be sufficient to prevent attacks or breaches from occurring. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist activities and other armed conflicts involving the United States or other countries (including the armed conflict between Russia and Ukraine) may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for natural gas, NGLs and oil, potentially putting downward pressure on demand for our operators’ services and causing a reduction in our revenues. Natural gas, NGLs and oil related facilities, including those of our operators, could be direct targets of terrorist attacks, and, if infrastructure integral to our operators is destroyed or damaged, they may experience a significant disruption in their operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash flows. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

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

Like many minerals companies, we may from time to time be involved in various legal and other proceedings, including without limitation title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

Risks Related to Our Industry

 

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, production data, economics and other factors, and the continuing evaluation of development plans, we may be required to write down the carrying value of our properties. The Company evaluates the carrying amount of its proved natural gas, NGLs and oil properties for impairment whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of

 

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proved reserves, future commodity prices, future production estimates and a commensurate discount rate. Because estimated undiscounted future cash flows have exceeded the carrying value of the Company’s proved properties to date, it has not been necessary for the Company to estimate the fair value of its properties under GAAP for successful efforts accounting. As a result, the Company has not recorded any impairment expenses associated with its proved properties. The Company did not record any impairment during the six months ended June 30, 2022, or for the year ended December 31, 2021. The risk that we will be required to recognize impairments of our natural gas, NGLs and oil properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period. We may incur impairment charges in the future, which could materially adversely affect our results of operations for the periods in which such charges are taken.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs for our operators related to developing and operating our properties.

The natural gas and oil industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly water and sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, our operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. If our operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. In addition, they may not have long-term contracts securing the use of their rigs. Shortages of drilling rigs, equipment, raw materials, supplies, personnel, trucking services, tubulars, hydraulic fracturing and completion services and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, results of operations and cash flows.

The marketability of natural gas, NGLs and oil production is dependent upon transportation, pipelines and refining facilities, which neither we nor many of our operators control. Any limitation in the availability of those facilities could interfere with our operators’ ability to market our operators’ production and could harm our business.

The marketability of our operators’ production depends in part on the availability, proximity and capacity of pipelines, tanker trucks and other transportation methods, and processing and refining facilities owned by third parties. Neither we nor the majority of our operators control these third-party transportation facilities and our operators’ access to them may be limited or denied. Insufficient production from the wells on our acreage or a significant disruption in the availability of third-party transportation facilities or other production facilities could adversely impact our operators’ ability to deliver, to market or produce natural gas, NGLs and oil and thereby cause a significant interruption in our operators’ operations. If they are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, they may be required to shut in or curtail production. In addition, the amount of natural gas, NGLs or oil that can be produced and sold is subject to curtailment in certain other circumstances outside of our or our operators’ control, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on these systems, downstream processing facilities’ failure to accept unprocessed natural

 

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gas, tanker truck availability and extreme weather conditions. Also, production from our wells may be insufficient to support the construction of pipeline facilities, and the shipment of our operators’ natural gas, NGLs and oil on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we and our operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing or refining-facility capacity, or an inability to obtain favorable terms for delivery of the natural gas, NGLs and oil produced from our acreage, could reduce our operators’ ability to market the production from our properties and have a material adverse effect on our financial condition, results of operations and cash flows. Our operators’ access to transportation options and the prices our operators receive can also be affected by federal and state regulation—including regulation of natural gas, NGLs and oil production, transportation and pipeline safety—as well by general economic conditions and changes in supply and demand. In addition, the third parties on whom our operators rely for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.

Drilling for and producing natural gas, NGLs and oil are high-risk activities with many uncertainties that may materially adversely affect our business, financial condition, results of operations and cash flows.

The drilling activities of the operators of our properties will be subject to many risks. For example, we will not be able to assure our stockholders that wells drilled by the operators of our properties will be productive. Drilling for natural gas, NGLs and oil often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient natural gas, NGLs or oil to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that natural gas, NGLs or oil are present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. Further, our operators’ drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

 

   

unusual or unexpected geological formations;

 

   

loss of drilling fluid circulation;

 

   

title problems;

 

   

facility or equipment malfunctions;

 

   

unexpected operational events;

 

   

shortages or delivery delays of equipment and services;

 

   

compliance with environmental and other governmental requirements; and

 

   

adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations,

 

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including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash flows may be materially adversely affected.

Competition in the natural gas and oil industry is intense, which may adversely affect our and our operators’ ability to succeed.

The natural gas and oil industry is intensely competitive, and the operators of our properties compete with other companies that may have greater resources. Many of these companies explore for and produce natural gas, NGLs and oil, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas, NGLs and oil market prices. Our operators’ larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than our operators can, which would adversely affect our operators’ competitive position. Our operators may have fewer financial and human resources than many companies in our operators’ industry and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. Furthermore, the natural gas and oil industry has experienced recent consolidation amongst some operators, which has resulted in certain instances of combined companies with larger resources. Such combined companies may compete against our operators or, in the case of consolidation amongst our operators, may choose to focus their operations on areas outside of our properties. In addition, our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transaction in a highly competitive environment.

A deterioration in general economic, business, political or industry conditions would materially adversely affect our results of operations, financial condition and cash flows.

Concerns over global economic conditions, energy costs, geopolitical issues, including the conflict between Russia and Ukraine, the impacts of the COVID-19 pandemic, inflation, the availability and cost of credit and slow economic growth in the United States have contributed to economic uncertainty and diminished expectations for the global economy. Additionally, acts of protest and civil unrest have caused economic and political disruption in the United States. Meanwhile, continued hostilities in Europe and the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. For example, an oversupply of natural gas, NGLs or oil due to reduced demand as a result of slower global economic growth could lead to a severe decline in worldwide natural gas, NGLs and oil prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could further diminish, which could impact the price at which natural gas, NGLs and oil from our properties are sold, affect the ability of our operators, customers and suppliers to continue operations and ultimately materially adversely impact our results of operations, financial condition and cash flows.

Conservation measures, technological advances, increased attention to ESG matters and continued negative investor sentiment toward natural gas and oil focused companies could materially reduce demand for natural gas, NGLs and oil, availability of capital and adversely affect our results of operations and the trading market for shares of our Class A common stock.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to natural gas, NGLs and oil, technological advances in fuel economy and energy-

 

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generation devices could reduce demand for natural gas, NGLs and oil. The impact of the changing demand for natural gas, NGLs and oil services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

It is also possible that the concerns about the production and use of fossil fuels will reduce the number of investors willing to own shares of our Class A common stock, adversely affecting the market price of our Class A common stock. For example, certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth, pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on their social and environmental considerations. Certain other stakeholders have pressured commercial and investment banks to stop financing oil and natural gas and related infrastructure projects. If this negative sentiment continues, it may reduce the availability of capital funding for potential development projects, which could have a material adverse effect on our business, prospects, financial condition, results of operations and cash flows.

Additionally, to the extent ESG matters negatively impact our or our operators’ reputation, we or our operators may not be able to compete as effectively to recruit or retain employees, which may adversely affect our or our operators’ operations. ESG matters may also impact our or our operators’ suppliers and customers, which may ultimately have adverse impacts on our or our operators’ operations.

Failure of imported or exported liquid natural gas to be a competitive source of energy for the United States or international markets could adversely affect our operators and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Operations of LNG projects are dependent upon the ability of our operators to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from North America and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets. Additionally, insufficient receiving capacity, LNG tanker capacity or political instability in foreign countries that import natural gas may also impede the willingness or ability of LNG purchasers and merchants in such countries to export LNG from the United States. In the United States, due mainly to a historically abundant supply of natural gas and discoveries of substantial quantities of unconventional, or shale, natural gas, imported LNG has not developed into a significant energy source. In addition to natural gas, LNG also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy. Some of these sources of energy may be available at a lower cost than LNG in certain markets.

As a result of these and other factors, LNG may not be a competitive source of energy in the United States or internationally. The failure of LNG to be a competitive supply alternative to local natural gas, oil and other alternative energy sources in markets accessible to our operators could adversely affect the ability of our operators to deliver LNG from the United States or to the United States on a commercial basis. Any significant impediment to the ability to deliver LNG to or from

 

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the United States generally could have a material adverse effect on our operators and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Risks Related to Environmental and Regulatory Matters

Natural gas, NGLs and oil operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for our operators, and failure to comply could result in our operators incurring significant liabilities, either of which may impact our operators’ willingness to develop our interests.

Our operators’ activities on the properties in which we hold interests are subject to various federal, state and local governmental regulations that may change from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity to conserve supplies of natural gas, NGLs and oil.

In addition, the production, handling, storage and transportation of natural gas, NGLs and oil, as well as the remediation, emission and disposal of natural gas, NGLs and oil wastes, by-products thereof and other substances and materials produced or used in connection with natural gas, NGLs and oil operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of worker health and safety, natural resources and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions on our operators, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operators’ operations on our properties. Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control, species protection, and waste management, among other matters.

Laws and regulations governing exploration and production may also affect production levels. Our operators must comply with federal and state laws and regulations governing conservation matters, including, but not limited to:

 

   

provisions related to the unitization or pooling of the natural gas and oil properties;

 

   

the establishment of maximum rates of production from wells;

 

   

the spacing of wells;

 

   

the plugging and abandonment of wells; and

 

   

the removal of related production equipment.

Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety laws and regulations. For example, in November 2021, the Pipeline and Hazardous Materials Safety Administration issued a final rule significantly expanding reporting and safety requirements for operators of gas gathering pipelines, including previously unregulated pipelines. Compliance with such regulations may require increased capital costs for third-party natural gas, NGLs and oil transporters. These transporters may attempt to pass on such costs to our operators, which in turn could affect profitability on the properties in which we own mineral interests.

 

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Our operators must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.

Our operators may be required to make significant expenditures to comply with the governmental laws and regulations described above and may be subject to potential fines and penalties if they are found to have violated these laws and regulations. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. Please read “Business—Regulation of Environmental and Occupational Safety and Health Matters” for a description of the laws and regulations that affect our operators and that may affect us. These and other potential regulations could increase the operating costs of our operators and delay production and may ultimately impact our operators’ ability and willingness to develop our properties.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause our operators to incur increased costs, additional operating restrictions or delays and fewer potential drilling locations.

Our operators engage in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Currently, hydraulic fracturing is generally exempt from regulation under the Underground Injection Control program of the U.S. Safe Drinking Water Act (“SDWA”) and is typically regulated by state oil and gas commissions or similar agencies.

However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. Also, from time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. This or other federal legislation related to hydraulic fracturing may be considered again in the future, though we cannot predict the extent of any such legislation at this time.

Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states in which our properties are located. States could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular.

Increased regulation and attention given to the hydraulic fracturing process, including the disposal of produced water gathered from drilling and production activities, could lead to greater opposition to, and litigation concerning, natural gas, NGLs and oil production activities using hydraulic fracturing techniques in areas where we own mineral interests. Additional legislation or regulation could also lead to operational delays or increased operating costs for our operators in the production of natural gas, NGLs and oil, including from the development of shale plays, or could make it more difficult for our operators to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing

 

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could potentially cause a decrease in our operators’ completion of new natural gas and oil wells on our properties and an associated decrease in the production attributable to our interests, which could have a material adverse effect on our business, financial condition and results of operations.

Legislation or regulatory initiatives intended to address seismic activity could restrict our operators’ drilling and production activities, as well as our operators’ ability to dispose of produced water gathered from such activities, which could have a material adverse effect on their future business, which in turn could have a material adverse effect on our business.

State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity.

In addition, a number of lawsuits have been filed alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. In some instances, regulators may also order that disposal wells be shut in.

Our operators will likely dispose of large volumes of produced water gathered from its drilling and production operations by injecting it into wells pursuant to permits issued by governmental authorities overseeing such disposal activities. While these permits will be issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict our operators’ ability to use hydraulic fracturing or dispose of produced water gathered from drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring them to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

Restrictions on the ability of our operators to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of natural gas, NGLs and oil production during both the drilling and hydraulic fracturing processes. Over the past several years, parts of the country have experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. Such conditions may be exacerbated by climate change. If our operators are unable to obtain water to use in their operations from local sources, or if our operators are unable to effectively utilize flowback water, they may be unable to economically drill for or produce natural gas, NGLs and oil from our properties, which could have an adverse effect on our financial condition, results of operations and cash flows.

 

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A series of risks arising out of the threat of climate change could result in increased operating costs, limit the areas in which natural gas, NGLs and oil production may occur, and reduce demand for the natural gas, NGLs, and oil that our operators produce.

The threat of climate change continues to attract considerable attention in the United States and abroad. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions greenhouse gases (“GHGs”) as well as to restrict or eliminate such future emissions. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

In recent years, Congress has considered legislation to reduce emissions of GHGs, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other regulatory initiatives are expected to be proposed that may be relevant to GHG emissions issues. For example, the Inflation Reduction Act of 2022 (the “IRA”), which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on GHG emission from certain facilities, was signed into law in August 2022. The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transitions away from fossil fuels, which could in turn adversely affect our business and results of operations. Moreover, President Biden has highlighted addressing climate change as a priority of his administration and has issued several Executive Orders addressing climate change. In addition, following the U.S. Supreme Court finding that GHGs constitute a pollutant under the Clean Air Act (the “CAA”), the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the United States Department of Transportation (“DOT”), implement GHG emissions limits on vehicles manufactured for operation in the United States. The regulation of methane from oil and gas facilities has been subject to uncertainty in recent years.

In September 2020, the Trump Administration revised prior regulations to rescind certain methane standards and remove the transmission and storage segments from the source category for certain regulations. However, in September 2020, the EPA finalized two sets of amendments to the 2016 Subpart OOOOa New Source Performance Standards. The first, known as the “2020 Technical Rule,” reduced the 2016 rule’s fugitive emissions monitoring requirements and expanded exceptions to pneumatic pump requirements, among other changes. The second, known as the “2020 Policy Rule,” rescinded the methane-specific requirements for certain oil and natural gas sources in the production and processing segments. On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the 2020 Technical Rule by September 2021 and consider revising the 2020 Policy Rule. On June 30, 2021, President Biden signed a resolution under the Congressional Review Act (“CRA”) passed by Congress that revoked the 2020 Policy Rule. The CRA resolution did not address the 2020 Technical Rule. On November 15, 2021, the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive

 

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standards set by EPA. Under the proposed rule, states would have three years to develop their compliance plan for existing sources and the regulations for new sources would take effect immediately upon issuance of a final rule. The EPA is expected to issue both a supplemental proposed rule, that may expand or modify the current proposed rule, and final rule by the end of 2022. We cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a significant possibility.

At the state level, several states including Pennsylvania have proceeded with a number of state and regional efforts aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. In April 2022, Pennsylvania finalized regulations establishing a cap-and-trade program under its existing authority to regulate air emissions, enabling Pennsylvania to join the Regional Greenhouse Gas Initiative, a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. As a result, our operators’ may experience increased operating costs if they are required to purchase emission allowances in connection with their operations.

At the international level, the United Nations-sponsored “Paris Agreement” requires member states to submit non-binding, individually-determined reduction goals known as “Nationally Determined Contributions” every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. Additionally, at the 26th conference of parties (“COP26”), the United States and the European Union jointly announced the launch of a Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. COP26 concluded with the finalization of the Glasgow Climate Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. Various state and local governments have also publicly committed to furthering the goals of the Paris Agreement. The full impact of these actions, and any legislation or regulation promulgated to fulfill the United States’ commitments thereunder, is uncertain at this time, and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects upon us and the operations of our operators.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including action taken by President Biden with respect to his climate change related pledges. On January 27, 2021, President Biden issued an Executive Order that calls for substantial action on climate change, including, among other things, the increased use of zero-emission vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risks across government agencies and economic sectors. The Biden Administration has also called for restrictions on leasing on federal land and the Department of Interior’s comprehensive review of the federal leasing program, which resulted in a reduction in the volume of onshore land held for lease and an increased royalty rate. Substantially all of our interests are located on private lands, but we cannot predict the full impact of these developments or whether the Biden Administration may pursue further restrictions. Other actions that could be pursued by the Biden Administration include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emission limitations for oil and gas facilities. Litigation risks are also increasing as a number of parties have sought to bring suit against various oil and natural gas companies in state or federal court, alleging among other things, that such companies created

 

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public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. Should we be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to causation or contribution to the asserted damage, or to other mitigating factors. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

There are also increasing financial risks for fossil fuel producers as stockholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced that it had joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Although we cannot predict the effects of these actions, such limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

Additionally, on March 21, 2022, the SEC issued a proposed rule regarding the enhancement and standardization of mandatory climate-related disclosures for investors. The proposed rule would require registrants to include certain climate-related disclosures in their registration statements and periodic reports, including, but not limited to, information about the registrant’s governance of climate-related risks and relevant risk management processes; climate-related risks that are reasonably likely to have a material impact on the registrant’s business, results of operations, or financial condition and their actual and likely climate-related impacts on the registrant’s business strategy, model, and outlook; climate-related targets, goals and transition plan (if any); certain climate-related financial statement metrics in a note to their audited financial statements; Scope 1 and Scope 2 GHG emissions; and Scope 3 GHG emissions and intensity, if material or if the registrant has set a GHG emissions reduction target or goal that includes Scope 3 emissions. If the proposed rule is adopted in its current form, an attestation report from an independent GHG emissions attestation provider will be required to cover Scope 1 and 2 GHG emissions metrics for large accelerated and accelerated filers after the first disclosure year. Additionally, the proposed rule would provide a safe harbor for liability for Scope 3 GHG emissions disclosure and an exemption from the Scope 3 GHG emissions disclosure requirement for smaller reporting companies. According to the SEC’s Spring 2022 regulatory agenda, issued in June 2022, the proposed climate disclosure rule is scheduled to be finalized in October 2022. Although the final form and substance of these requirements is not yet known and the ultimate scope and impact on our business is uncertain, compliance with the proposed rule, if finalized, may result in additional legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources.

 

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The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce the profitability of our interests. Additionally, political, litigation and financial risks may result in our oil and natural gas operators restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the profitability of our interests. To date, any costs related to climate change regulation incurred by our operators has not had a material impact on production from our properties or otherwise materially and adversely affected our business. However, one or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our operations, as well as those of our operators and their supply chains. Such physical risks may result in damage to operators’ facilities or otherwise adversely impact their operations, such as if they become subject to water use curtailments in response to drought, or demand for their products, such as to the extent warmer winters reduce the demand for energy for heating purposes, which may adversely impact the production or attractiveness of our interests. While extreme weather events have increased in frequency and severity in some areas where our properties are located, to date, such events have not had a material impact on production from our properties or otherwise materially and adversely affected our business.

Increased attention to ESG matters may impact our business or the business of our operators.

Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, increasing mandatory ESG disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our operators’ products (and thus in our mineral interests), reduced profits, increased legislative and judicial scrutiny, investigations and litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us or our operators. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors. To date however, changes in social pressures and consumer demand related to increased attention to ESG and conservation matters have not had a material impact on production from our properties or otherwise materially and adversely affected our business. Voluntary disclosures regarding ESG matters, as well as any ESG disclosures mandated by law, could result in private litigation or government investigation or enforcement action regarding the sufficiency or validity of such disclosures. In addition, failure or a perception (whether or not valid) of failure to implement ESG strategies or achieve ESG goals or commitments, including any GHG reduction or neutralization goals or commitments, could result in private litigation and damage our reputation, cause our investors or consumers to lose confidence in our Company, and negatively impact our operations.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from

 

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companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our or operators’ access to and costs of capital. Also, institutional lenders may, of their own accord, decide not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our or our operators’ access to capital for potential growth projects.

Changes in tax laws and regulations could adversely impact our earnings and the cost, manner or feasibility of conducting our operations.

Members of Congress periodically introduce legislation to revise U.S. federal income tax laws which could have a material impact on us. The most significant potential tax law changes that could impact us include increases in the regular income tax rate, the repeal of expensing intangible drilling costs or percentage depletion, the repeal of like-kind exchange tax deferral rules on real property and further limited deductibility of interest expense, any of which could adversely impact our current and deferred federal and state income tax liabilities. The recently enacted IRA imposes a new minimum tax based on adjusted financial statement income and a new excise tax on stock repurchases, either of which could adversely impact our future federal tax liabilities. State and local taxing authorities in jurisdictions in which we operate or own assets may enact new taxes, such as the imposition of a severance tax on the extraction of natural resources in states in which we produce natural gas, NGLs and oil, or change the rates of existing taxes, which could adversely impact our earnings, cash flows and financial position.

Additional restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our operators’ ability to conduct drilling activities.

In the United States, the Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). In August 2019, the United States Fish and Wildlife Services (“FWS”) and National Marine Fisheries Service (“NMFS”) issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat. A coalition of states have challenged the three rules and the litigation was stayed after President Biden issued an Executive Order directing the agencies to review the rules. In addition, on December 18, 2020, the FWS amended its regulations governing critical habitat designations, which are subject to ongoing litigation. In June 2021, FWS and NMFS announced plans to begin rulemaking processes to rescind these rules. To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where our operators operate, our operators’ abilities to conduct or expand operations could be limited, or our operators could be forced to incur material additional costs. Moreover, our operators’ drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons.

In addition, as a result of one or more settlements approved by the FWS, the agency was required to make a determination on the listing of numerous other species as endangered or threatened under the ESA by the end of the FWS’ 2017 fiscal year. The FWS did not meet that deadline; however, its review is reportedly ongoing. The designation of previously unidentified endangered or threatened species could cause our operators’ operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands, which may reduce the profitability of our interests to the extent they are associated with such designations.

 

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Risks Related to this Offering and Our Class A Common Stock

We are a holding company. Our sole material asset after completion of this offering will be our equity interest in Bounty LLC and we are accordingly dependent upon distributions from Bounty LLC to pay taxes, cover our corporate and other overhead expenses and pay any dividends on our Class A common stock.

We are a holding company and will have no material assets other than our equity interest in Bounty LLC. Please see “Corporate Reorganization.” We have no independent means of generating revenue. To the extent Bounty LLC has available cash, Bounty LLC is generally required to make pro rata cash distributions (which we refer to as “tax distributions”) to all its unitholders, including to us, in an amount sufficient to allow us to pay our U.S. federal, state, local and non-U.S. tax liabilities. We also expect Bounty LLC may make non-pro rata cash distributions periodically to enable us to cover our corporate and other overhead expenses. In addition, as the sole managing member of Bounty LLC, we intend to cause Bounty LLC to make pro rata cash distributions to all of its unitholders, including to us, in an amount sufficient to allow us to fund dividends to our stockholders, to the extent our board of directors declares such dividends. Therefore, although we expect to pay dividends on our Class A common stock, our ability to do so may be limited to the extent Bounty LLC and its subsidiaries are limited in their ability to make these and other distributions to us. To the extent that we need funds and Bounty LLC or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of their financing arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition. Further, although we expect that Bounty LLC will initially make distributions to us and the Existing Owners equal to 100% of (i) cash available for distribution and (ii) cash from lease bonus income, and that we, in turn, will pay quarterly dividends equal to the amount received from Bounty LLC net of cash taxes, the declaration and payment of any dividends are at the sole discretion of our board of directors and our board of directors may change our dividend policy at any time based on our cash flow needs, including, without limitation, to significantly reduce such quarterly dividends or even to eliminate dividends entirely. See “Dividend Policy” for more information.

If we fail to develop or maintain an effective system of internal controls over financial reporting, we may not be able to report our financial results accurately and timely or prevent fraud, which may result in material misstatements in our financial statements or failure to meet our periodic reporting obligations. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.

Prior to the completion of this offering, we were a private entity. We have not completed an assessment of the effectiveness of our internal controls over financial reporting, and our independent registered public accounting firm was not required to, and did not, conduct an audit of our internal controls over financial reporting as of December 31, 2021 or 2020. Our internal controls over financial reporting do not currently meet all the standards contemplated by Section 404 of the Sarbanes-Oxley Act. Accordingly, we cannot assure you that we have identified all, or that we will not in the future have additional, material weaknesses. If we are not able to implement the requirements of Section 404 in a timely manner or with adequate compliance at the time required, this may cause us to be unable to report on a timely basis and thereby subject us to adverse regulatory consequences, including sanctions by the SEC or violations of applicable stock exchange listing rules.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

 

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Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results may be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock. Additional material weaknesses may be identified in the future. If we identify such issues or if we are unable to produce accurate and timely financial statements, the trading price of our Class A common stock may decline and we may be unable to maintain compliance with the NYSE listing standards.

We will incur increased costs as a result of operating as a public company, including the cost of compliance with securities laws, and our management will be required to devote substantial time to compliance efforts.

As a public company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. Our management and other personnel will need to devote a substantial amount of time and financial resources to comply with obligations related to being a publicly traded corporation. We currently estimate that we will incur approximately $             million annually in additional operating expenses as a publicly traded corporation that we have not previously incurred, including costs associated with compliance under the Exchange Act, annual and quarterly reports to common stockholders, registrar and transfer agent fees, audit fees, incremental director and officer liability insurance costs and director and officer compensation.

In addition, we will be required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act as early as our annual report for the fiscal year ending December 31, 2023, Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls upon becoming a large accelerated filer, as defined in the SEC rules, or otherwise ceasing to qualify as an emerging growth company under the JOBS Act. We are evaluating our existing controls over financial reporting and we will design enhanced processes and controls to the extent warranted based on our review. We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our independent registered public accounting firm will not identify any additional material weaknesses in our internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our independent registered public accounting firm identify and report such material weaknesses, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the stock price of our Class A common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

 

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There is no existing market for our Class A common stock, and a trading market that will provide you with adequate liquidity may not develop. The price of our Class A common stock may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our Class A common stock. After this offering, there will be only             publicly traded shares of Class A common stock held by our public common stockholders (or                      shares if the underwriters exercise in full their option to purchase additional shares of Class A common stock). We do not know the extent to which investor interest will lead to the development of an active trading market or how liquid that market might be. You may not be able to resell your Class A common stock at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the Class A common stock and limit the number of investors who are able to buy the Class A common stock.

The initial public offering price for the Class A common stock offered hereby will be determined by negotiations between us and the representative of the underwriters and may not be indicative of the market price of the Class A common stock that will prevail in the trading market. The market price of our Class A common stock may decline below the initial public offering price.

Our Existing Owners will initially have the ability to direct the voting of a majority of the voting power of our Class A common stock, and their interests may conflict with those of our other stockholders.

Holders of shares of our Class A common stock and Class B common stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our certificate of incorporation. Upon completion of this offering, our Existing Owners will beneficially own, in the aggregate, 100% of our Class B common stock, representing         % of our combined voting power (or approximately         % if the underwriters exercise in full their option to purchase additional shares of Class A common stock). As a result, our Existing Owners will initially be able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our Class A common stock will be able to affect the way we are managed or the direction of our business. The interests of our Existing Owners with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders.

Given this concentrated ownership, our Existing Owners would have to approve any potential acquisition of us. In addition, certain of our directors and director nominees are currently employees of our Existing Owners or their affiliates. These directors’ duties as employees of our Existing Owners or their affiliates may conflict with their duties as our directors, and the resolution of these conflicts may not always be in our or your best interest. Finally, the existence of significant stockholders may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Our Existing Owners’ concentration of stock ownership may also adversely affect the trading price of our Class A common stock to the extent investors perceive a disadvantage in owning stock of a company with significant stockholders.

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

Subject to certain limitations and exceptions, our Existing Owners, who hold Bounty LLC Units, may require Bounty LLC to redeem their Bounty LLC Units for shares of Class A common

 

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stock (on a one-for-one basis, subject to conversion rate adjustments for stock splits, stock dividends and reclassification and other similar transactions), and our Existing Owners may sell any of such shares of Class A common stock. Additionally, after the expiration or waiver of the lock-up provision contained in the underwriting agreement entered into in connection with this offering, we may sell additional shares of Class A common stock in subsequent public offerings or may issue additional shares of Class A common stock or convertible securities. After the completion of this offering, and assuming full exercise of the underwriters’ option to purchase additional shares, we will have outstanding         shares of Class A common stock and         shares of Class B common stock. This number includes         shares of Class A common stock that we are selling in this offering and         shares of Class A common stock that we may sell in this offering if the underwriters exercise their option to purchase additional shares in full, which shares may be resold immediately in the public market. Following the completion of this offering, and assuming full exercise of the underwriters’ option to purchase additional shares, our Existing Owners will own, in the aggregate,          shares of Class B common stock, representing approximately         % of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements between them and the underwriters described in “Underwriting,” but may be sold into the market in the future.

Following the completion of this offering, the Existing Owners will be party to a registration rights agreement, which will, among other things, require us to, in certain circumstances, register          shares of Class A common stock that they may receive in exchange for their Bounty LLC Units (and a corresponding number of shares of Class B common stock). See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.” In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of          shares of our Class A common stock issued or reserved for issuance under our equity incentive plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up restrictions, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

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

Our Existing Owners and their affiliates are not limited in their ability to compete with us, and the corporate opportunity provisions in our amended and restated certificate of incorporation could enable our Existing Owners and their affiliates to benefit from corporate opportunities that might otherwise be available to us.

Our governing documents will provide that our Existing Owners and their affiliates (including portfolio investments of our Existing Owners and their affiliates) are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us and that we renounce any interest or expectancy in any business opportunity that may be from time to time presented to our Existing Owners or their affiliates. In particular, subject to the limitations of applicable law, our amended and restated certificate of incorporation will, among other things:

 

   

permit our Existing Owners and their affiliates and our directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

 

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provide that if our Existing Owners or their affiliates or any director or officer of one of our affiliates, our Existing Owners or their affiliates who is also one of our directors becomes aware of a potential business opportunity, transaction or other matter, they will have no duty to communicate or offer that opportunity to us.

Our Existing Owners or their affiliates may become aware, from time to time, of certain business opportunities (such as acquisition opportunities) and may direct such opportunities to other businesses in which they have invested, in which case we may not become aware of or otherwise have the ability to pursue such opportunity. Further, such businesses may choose to compete with us for these opportunities, possibly causing these opportunities to not be available to us or causing them to be more expensive for us to pursue. In addition, our Existing Owners and their affiliates may dispose of natural gas and oil properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those assets. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to our Existing Owners and their affiliates could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. Please read “Description of Capital Stock—Corporate Opportunity.”

Our Existing Owners and their affiliates are established participants in the natural gas and oil industry and have resources greater than ours, which may make it more difficult for us to compete with our Existing Owners and their affiliates with respect to commercial activities as well as for potential acquisitions. We cannot assure you that any conflicts that may arise between us and our stockholders, on the one hand, and our Existing Owners and their affiliates, on the other hand, will be resolved in our favor. As a result, competition from our Existing Owners and their affiliates could adversely impact our results of operations.

A significant reduction by our Existing Owners of their ownership interests in us could adversely affect us.

We believe that our Existing Owners’ ownership interests in us provide them with an economic incentive to assist us to be successful. Upon the expiration of the lock-up restrictions on transfers or sales of our securities following the completion of this offering, none of our Existing Owners will be subject to any obligation to maintain its ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce its ownership interest in us. Furthermore, as described under “Corporate Reorganization,” our Existing Owners may distribute all or a portion of their ownership in us to their partners or members, as applicable. In the event our Existing Owners reduce their ownership interest in us, our Existing Owners and their affiliates may have less incentive to assist in our success and the individuals initially appointed to our board of directors by our Existing Owners may resign. Such actions could adversely affect our ability to successfully implement our business strategies, which could adversely affect our business, financial condition and results of operations.

Our amended and restated certificate of incorporation and amended and restated bylaws will contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock and could deprive our investors of the opportunity to receive a premium for their shares.

Our amended and restated certificate of incorporation will authorize our board of directors to issue preferred stock without stockholder approval in one or more series, designate the number of shares constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be

 

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beneficial to our stockholders. Among other things, upon the completion of this offering, our amended and restated certificate of incorporation and amended and restated bylaws will:

 

   

establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders;

 

   

provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

 

   

provide that the authorized number of directors constituting our board of directors may be changed only by resolution of the board of directors;

 

   

provide that all vacancies, including newly created directorships, shall, except as otherwise required by law or, if applicable, the rights of holders of a series of our preferred stock, be filled by the affirmative vote of a majority of our directors then in office, even if less than a quorum;

 

   

provide that our bylaws can be amended by the board of directors;

 

   

provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three-year terms, other than directors that may be elected by holders of our preferred stock, if any;

 

   

provide that special meetings of our stockholders may only be called by our board of directors pursuant to a resolution adopted by the affirmative vote of a majority of the members of the board of directors serving at the time of such vote; and

 

   

prohibit cumulative voting on all matters.

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

Our amended and restated certificate of incorporation will provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporate Law (“DGCL”), our amended and restated certificate of incorporation or our amended and restated bylaws or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. In the event the Delaware Court of Chancery lacks subject matter jurisdiction, then the sole and exclusive forum for such action or proceeding shall be the federal district court for the District of Delaware. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and to have consented to, the provisions of our amended and restated certificate

 

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of incorporation described in the preceding sentence. This provision would not apply to claims brought to enforce a duty or liability created by the Exchange Act, the Securities Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder. The choice of forum provision in our amended and restated certificate of incorporation may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find this provision unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

We will limit the liability of, and indemnify, our directors and officers.

Although our directors and officers are accountable to us and must exercise good faith, good business judgement, and integrity in handling our affairs, our amended and restated certificate of incorporation and the indemnification agreements that we intend to enter into with all of our non-employee directors and officers will provide that our non-employee directors and officers will be indemnified to the fullest extent permitted under Delaware law. As a result, our stockholders may have fewer rights against our non-employee directors and officers than they would have absent such provisions in our proposed amended and restated certificate of incorporation and indemnification agreements, and a stockholder’s ability to seek and recover damages for a breach of fiduciary duties may be reduced or restricted. Delaware law allows indemnification of our non-employee directors and officer, if they (i) have acted in good faith, in a manner the non-employee director or officer reasonably believes to be in or not opposed to our best interests, and (ii) with respect to any criminal action or proceeding, if the non-employee director or officer had no reasonable cause to believe the conduct was unlawful.

Pursuant to our proposed amended and restated certificate of incorporation and indemnification agreements, each non-employee director and officer who is made a party to a legal proceeding because he or she is or was a non-employee director or officer, is indemnified by us from and against any and all liability, except that we may not indemnify a non-employee director or officer: (i) for any liability incurred in a proceeding in which such person is adjudged liable to us or is subjected to injunctive relief in favor of us; (ii) for acts or omissions that involve intentional misconduct or a knowing violation of law, fraud or gross negligence; (iii) for unlawful distributions; (iv) for any transaction for which such non-employee director or officer received a personal benefit or as otherwise prohibited by or as may be disallowed under Delaware law; or (v) with respect to any dispute or proceeding between us and such non-employee director or officer unless such indemnification has been approved by a disinterested majority of our board of directors or by a majority in interest of disinterested stockholders. We will be required to pay or reimburse attorney’s fees and expenses of a non-employee director or officer seeking indemnification as they are incurred, provided the non-employee director or officer executes an agreement to repay the amount to be paid or reimbursed if there is a final determination by a court of competent jurisdiction that such person is not entitled to indemnification.

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

Based on an assumed initial public offering price of $         per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of shares of our Class A common stock in this offering will experience an immediate and substantial dilution of $         per share in the as adjusted net tangible

 

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book value per share of Class A common stock from the initial public offering price, and our as adjusted net tangible book value as of                     , 2022 after giving effect to this offering would be $         per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. See “Dilution.”

If Bounty LLC were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and Bounty LLC might be subject to potentially significant tax inefficiencies.

Section 7704 of the Code generally provides that a publicly traded partnership will be treated as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership, the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. However, if 90% or more of a partnership’s gross income for every taxable year consists of “qualifying income,” the partnership may continue to be treated as a partnership for U.S. federal income tax purposes. Qualifying income generally includes income earned from passive ownership interests in oil and gas properties. There may be future changes to U.S. federal income tax laws or the Treasury Department’s interpretations of the qualifying income rules in a manner that could impact Bounty LLC’s ability to qualify as a partnership for federal income tax purposes. However, we believe that substantially all of Bounty LLC’s gross income will constitute qualifying income for purposes of Section 7704(d) and intend to operate such that Bounty LLC does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. In addition, the Bounty LLC Agreement will provide for limitations on the ability of Existing Owners to transfer their Bounty LLC Units and will provide us, as managing member of Bounty LLC, with the right to impose restrictions (in addition to those already in place) on the ability of Existing Owners to exchange their Bounty LLC Units pursuant to a Redemption Right to the extent we believe it is necessary to ensure that Bounty LLC will continue to be treated as a partnership for U.S. federal income tax purposes.

If Bounty LLC were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, significant tax inefficiencies might result for us and for Bounty LLC. In particular, Bounty LLC would pay U.S. federal income tax on its taxable income at the corporate tax rate, which is currently a maximum of 21%. Distributions to us would generally be taxed again as corporate distributions. Because a tax would be imposed on Bounty LLC as a corporation, the amount of cash distributions to us would be substantially reduced, which may cause a substantial reduction in the value of our Class A common stock.

If we were deemed to be an investment company under the Investment Company Act of 1940, as amended (the “1940 Act”), applicable restrictions could make it impractical for us to continue our business as contemplated and could have a material adverse effect on our business, prospects, financial condition, results of operations and cash flows.

Under Sections 3(a)(1)(A) and (C) of the 1940 Act, a company generally will be deemed to be an “investment company” for purposes of the 1940 Act if it (i) is, or holds itself out as being, engaged primarily, or proposes to engage primarily, in the business of investing, reinvesting or trading in securities or (ii) is engaged, or proposes to engage, in the business of investing, reinvesting, owning, holding or trading in securities and it owns or proposes to acquire investment securities having a value exceeding 40% of the value of its total assets (exclusive of U.S. government securities and cash items) on an unconsolidated basis. We do not believe that we are an “investment company,” as such term is defined in either of those sections of the 1940 Act.

As the sole managing member of Bounty LLC, we will control and manage Bounty LLC. On that basis, we believe that our interest in Bounty LLC is not an “investment security” under the 1940 Act. Therefore, we have less than 40% of the value of our total assets (exclusive of U.S. government securities and cash items) in “investment securities.” However, if we were to lose the

 

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right to manage and control Bounty LLC, interests in Bounty LLC could be deemed to be “investment securities” under the 1940 Act.

We intend to conduct our operations so that we will not be deemed to be an investment company. However, if we were deemed to be an investment company, restrictions imposed by the 1940 Act, including limitations on our capital structure and our ability to transact with affiliates, could make it impractical for us to continue our business as contemplated and could have a material adverse effect on our business, prospects, financial condition, results of operations and cash flows.

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

We, certain of our Existing Owners and all of our directors and executive officers have entered or will enter into lock-up agreements pursuant to which we and they will be subject to certain restrictions with respect to the sale or other disposition of our Class A common stock for a period of 180 days following the date of this prospectus, Raymond James & Associates, Inc. at any time and without notice may release all or any portion of the Class A common stock subject to the foregoing lock-up agreements. See “Underwriting” for more information on these agreements. If the restrictions under the lock-up agreements are waived, then the Class A common stock, subject to compliance with the Securities Act or exceptions therefrom, will be available for sale into the public markets, which could cause the market price of our Class A common stock to decline and impair our ability to raise capital.

Our organizational structure confers certain benefits upon the Existing Owners that will not benefit the holders of our Class A common stock to the same extent as it will benefit the Existing Owners.

Our organizational structure confers certain benefits upon the Existing Owners that will not benefit the holders of our Class A common stock to the same extent as it will benefit the Existing Owners. We will be a holding company and will have no material assets other than our ownership of Bounty LLC Units. As a consequence, our ability to declare and pay dividends to the holders of our Class A common stock will be subject to the ability of Bounty LLC to provide distributions to us. If Bounty LLC makes such distributions, the Existing Owners will be entitled to receive equivalent distributions from Bounty LLC on a pro rata basis. However, because we must pay taxes, amounts ultimately distributed as dividends to holders of our Class A common stock are expected to be less on a per-share basis than the amounts distributed by Bounty LLC to our Existing Owners on a per-unit basis. This and other aspects of our organizational structure may adversely impact the future trading market for our Class A common stock.

We may issue preferred stock whose terms could adversely affect the voting power or value of our Class A common stock.

Our amended and restated certificate of incorporation will authorize our board of directors to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of our preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of a class or series of our preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of our preferred stock could affect the residual value of our Class A common stock.

 

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

We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things: (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer; (iii) provide certain disclosure regarding executive compensation required of larger public companies; or (iv) hold nonbinding advisory votes on executive compensation. We have also elected to use the extended transition period to delay adoption of new or revised accounting pronouncements applicable to public companies until such pronouncements are made applicable to private companies. Accordingly, our financial statements may not be comparable to the financial statements of public companies that comply with such new or revised accounting standards. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.07 billion of revenues in a fiscal year, have more than $700 million in market value of our Class A common stock held by non-affiliates, or issue more than $1 billion of non-convertible debt over a three-year period.

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

If securities or industry analysts do not publish research or reports or publish unfavorable research about our business, the price and trading volume of our Class A common stock could decline.

The trading market for our Class A common stock will depend in part on the research and reports that securities or industry analysts publish about us or our business. We do not currently have and may never obtain research coverage by securities and industry analysts. If no securities or industry analysts commence coverage of us, the trading price for our Class A common stock and other securities would be negatively affected. In the event we obtain securities or industry analyst coverage, if one or more of the analysts who covers us downgrades our securities, the price of our securities would likely decline. If one or more of these analysts ceases to cover us or fails to publish regular reports on us, interest in the purchase of our securities could decrease, which could cause the price of our Class A common stock and other securities and their trading volume to decline.

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact, included in this prospectus regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “may,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions and the negative of such words and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this prospectus.

The following important factors, in addition to those discussed elsewhere in this prospectus, could affect the future results of the energy industry in general, and our company in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:

 

   

our ability to execute on our business strategies;

 

   

the effect of changes in commodity prices;

 

   

the effects of political instability or armed conflict in natural gas, NGLs and oil producing regions, including, but not limited to, the conflict between Russia and Ukraine and the destabilizing effect such conflict has posed, and may continue to pose, for the European continent and the global natural gas and oil markets;

 

   

the effects of changes in general market conditions, including fluctuations in commodity prices and macroeconomic conditions;

 

   

the effects of global pandemics, including COVID-19, or any government response to such occurrence or threat;

 

   

the level of production on our properties;

 

   

risks associated with the drilling and operation of natural gas and oil wells;

 

   

the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;

 

   

legislative or regulatory actions pertaining to hydraulic fracturing, including restrictions on the use of water;

 

   

the availability of pipeline capacity and transportation facilities;

 

   

the effect of existing and future laws and regulatory actions;

 

   

the impact of derivative instruments or lack thereof;

 

   

conditions in the capital markets and our ability to obtain capital on favorable terms or at all;

 

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the overall supply and demand for natural gas, NGLs and oil, and regional supply and demand factors, delays, or interruptions of production;

 

   

competition from others in the energy industry;

 

   

uncertainty in whether development projects will be pursued;

 

   

uncertainty of estimates of natural gas, NGLs and oil reserves and production;

 

   

the cost of developing the natural gas, NGLs and oil underlying our properties;

 

   

our ability to replace our natural gas, NGLs and oil reserves;

 

   

our ability to identify, complete and integrate acquisitions;

 

   

title defects in the properties in which we invest;

 

   

the cost of inflation;

 

   

technological advances; and

 

   

general economic, business or industry conditions.

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

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

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

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

 

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USE OF PROCEEDS

We expect to receive approximately $         million of net proceeds (assuming the midpoint of the price range set forth on the cover of this prospectus) from the sale of the Class A common stock offered by us after deducting underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to contribute all of the net proceeds from this offering to Bounty LLC in exchange for Bounty LLC Units. Bounty LLC intends to use approximately $         million of the net proceeds from our sale of shares to purchase Bounty LLC Units, together with an equal number of shares of Class B common stock, from the Exchanging Members (at a purchase price per unit and share of Class B common stock, based on the midpoint of the estimated price range set forth on the cover page of this prospectus, net of underwriting discounts and commissions) and approximately $         million of the net proceeds to fund future acquisitions of mineral interests; however, it currently does not have any specific acquisitions planned. A $1.00 increase or decrease in the assumed initial public offering price of $        per share would cause the net proceeds from this offering, after deducting the underwriting discounts and commissions and estimated offering expenses, received by us to increase or decrease, respectively, by approximately $         million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same. If the proceeds increase due to a higher initial public offering price, we would contribute the additional net proceeds to Bounty LLC and Bounty LLC intends to use such additional net proceeds retained by it after payment of amounts owing to our Existing Owners to purchase Bounty LLC Units and Class B common stock as described above to fund future acquisitions of mineral interests. If the proceeds decrease due to a lower initial public offering price, we will contribute fewer net proceeds to Bounty LLC and Bounty LLC will pay less to our Existing Owners to purchase their Bounty LLC units and Class B common stock as contemplated above and have fewer net proceeds to direct to acquisitions.

To the extent the underwriters’ option to purchase additional shares is exercised, we intend to contribute all of the net proceeds therefrom to Bounty LLC in exchange for an additional number of Bounty LLC Units equal to the number of shares of Class A common stock issued pursuant to the underwriters’ option. Bounty LLC intends to use approximately $         million of the net proceeds from our sale of additional shares to purchase Bounty LLC Units, together with an equal number of shares of Class B common stock, from the Exchanging Members (at a purchase price per unit and share of Class B common stock, based on the midpoint of the estimated price range set forth on the cover page of this prospectus, net of underwriting discounts and commissions) and approximately $         million of net proceeds to fund future acquisitions of mineral interests.

 

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DIVIDEND POLICY

Overview

We expect Bounty LLC to initially pay quarterly distributions to us and the Existing Owners equal to 100% of (i) cash available for distribution and (ii) cash from lease bonus income, and that we, in turn, will pay quarterly dividends equal to the amount received from Bounty LLC net of cash taxes. From time to time, we may aim to balance the return of capital to investors with the selective allocation of capital toward acquisitions that we believe will be accretive to stockholder value while preserving a strong balance sheet through varying commodity price environments. Accordingly, Bounty LLC may distribute less than 100% of its cash available for distribution, or decide to use only a portion or none of its cash from lease bonus income to pay dividends. See “Summary—Non-GAAP Financial Measures” for the definitions of Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution used by us and Bounty LLC and a reconciliation of each of these measures to our most directly comparable GAAP financial measure.

While we expect to pay quarterly dividends in accordance with this financial philosophy, we have not adopted a formal written dividend policy to pay a fixed amount of cash regularly or to pay any particular amount based on the achievement of, or derivable from, any specific financial metrics, including cash available for distribution. Further, we are not contractually obligated to pay any dividends and do not have any required minimum quarterly dividend. Our payment of dividends may vary from quarter to quarter, may be significantly reduced or may be eliminated entirely. While we initially intend to pay quarterly dividends equal to 100% of the cash distributed to us from Bounty LLC net of cash taxes, the actual amount of any distributions from Bounty LLC, and therefore, the dividends we pay, may fluctuate depending on our cash flow needs, which may be impacted by potential acquisition opportunities and the availability of financing alternatives, the need to service any future indebtedness or other liquidity needs and general industry and business conditions, including the impact of commodity prices and the pace of the development of our properties by E&P companies. Given our reliance on third-party operators for all of the exploration, development and production on our properties and the impact of commodity prices on our results of operations and financial position, we cannot provide any assurance that we will pay dividends in the future. Our payment of dividends will be at the sole discretion of our board of directors, which may change our dividend philosophy at any time. Our board of directors will take into account:

 

   

general economic and business conditions;

 

   

our financial condition and operating results;

 

   

our cash flows from operations and current and anticipated cash needs, including for acquisitions;

 

   

legal, tax, regulatory and future contractual restrictions; and

 

   

such other factors as our board of directors may deem relevant.

Our ability to declare and pay dividends to the holders of our Class A common stock will be subject to the ability of Bounty LLC to provide distributions to us due to our nature as a holding company that will have no material assets other than our ownership of membership interests in Bounty LLC. Currently there are no restrictions on Bounty LLC to distribute funds to us. If Bounty LLC makes such distributions, the Existing Owners will be entitled to receive equivalent distributions from Bounty LLC on a pro rata basis. However, because we must pay taxes, amounts ultimately paid as dividends to holders of our Class A common stock are expected to be less on a per share basis than the amounts distributed by Bounty to the Existing Owners on a per unit basis.

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2022:

 

   

on an actual basis for our predecessor; and

 

   

on an as adjusted basis for Bounty Minerals to give effect to (i) the transactions described under “Corporate Reorganization,” (ii) the sale of shares of our Class A common stock in this offering at an assumed initial offering price of $     per share (which is the midpoint of the range set forth on the cover of this prospectus) and (iii) the application of the net proceeds from this offering as set forth under “Use of Proceeds.”

The information set forth in the table below is illustrative only and will be adjusted based on the actual initial public offering price and other final terms of this offering. This table should be read in conjunction with “Use of Proceeds” and the financial statements and accompanying notes included elsewhere in this prospectus.

 

     As of June 30, 2022 (1)  
     Predecessor 
Actual
     Bounty Minerals
As Adjusted (2)
 
     (in thousands, except number
of shares and par value)
 

Cash and cash equivalents (3)

   $ 27,571      $    
  

 

 

    

 

 

 

Total long-term debt

             

Members’ equity / stockholders’ equity:

     

Members’ equity

     468,246     

Class A common stock—0.01 par value; no shares authorized, issued or outstanding, actual;             shares authorized,             shares issued and outstanding, pro forma

         

Class B common stock—0.01 par value; no shares authorized, issued or outstanding, actual;             shares authorized,             shares issued and outstanding, pro forma

         

Additional paid-in capital

         

Retained earnings

         

Non-controlling interest (4)

         
  

 

 

    

 

 

 

Total member’s equity / stockholders’ equity

   $ 468,246      $                
  

 

 

    

 

 

 

Total capitalization

   $ 468,246      $    
  

 

 

    

 

 

 

 

(1)

Bounty Minerals was incorporated in June 2022. The data in this table has been derived from the historical consolidated financial statements included in this prospectus which pertain to the assets, liabilities, revenues and expenses of our accounting predecessor, Bounty LLC.

(2)

A $1.00 increase (decrease) in the assumed initial public offering price of $         per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) additional paid-in capital, total equity and total capitalization by approximately $         million, $         million and $         million, respectively, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions payable by us. We may also increase or decrease the number of shares we are offering. An increase (decrease) of one million shares offered by us at an assumed offering price of $         per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) additional paid-in capital, total equity and total capitalization by approximately $        million,

 

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  $        million and $        million, respectively, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.
(3)

As of                 2022, we had $        million in cash and cash equivalents. Includes approximately $         of net proceeds that we intend to use for future acquisitions. See “Use of Proceeds.”

(4)

The as adjusted basis column includes the Bounty LLC interests not owned by us, which represents        % of the Bounty LLC Units. The Existing Owners will hold a non-controlling economic interest in Bounty LLC. Bounty Minerals will hold        % of the economic interest in Bounty LLC.

 

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DILUTION

Purchasers of our Class A common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of our Class A common stock for accounting purposes. Our net tangible book value as of June 30, 2022, after giving pro forma effect to our corporate reorganization, was approximately $        million, or $        per share of Class A common stock. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of Class A common stock that will be outstanding immediately prior to the closing of this offering including giving effect to the corporate reorganization (assuming that 100% of our Class B common stock has been cancelled in connection with a redemption of Bounty LLC Units for Class A common stock). After giving effect to the sale of the shares in this offering and further assuming the receipt of the estimated net proceeds (after deducting estimated underwriting discounts and commissions and estimated offering expenses), our adjusted pro forma net tangible book value as of June 30, 2022 would have been approximately $        million, or $        per share. This represents an immediate increase in the net tangible book value of $        per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $        per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering (assuming that 100% of our Class B common stock has been cancelled in connection with a redemption of Bounty LLC Units for Class A common stock):

 

Initial public offering price per share

  

Pro forma net tangible book value per share as of June 30, 2022 (after giving effect to the corporate reorganization)

   $                

Increase per share attributable to new investors in the offering

   $    
  

 

 

 

As adjusted pro forma net tangible book value per share (after giving effect to the corporate reorganization and this offering)

   $    

Dilution in pro forma net tangible book value per share to new investors in this offering

   $    
  

 

 

 

A $1.00 increase (decrease) in the assumed initial public offering price of $         per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would increase (decrease) our as adjusted pro forma net tangible book value per share after the offering by $        and increase (decrease) the dilution to new investors in this offering by $        per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same, after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

 

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The following table summarizes, on an adjusted pro forma basis as of June 30, 2022, the total number of shares of Class A common stock owned by existing stockholders (assuming that 100% of our Class B common stock has been cancelled in connection with a redemption of Bounty LLC Units for Class A common stock) and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $        , calculated before deduction of estimated underwriting discounts and commissions.

 

     Shares Purchased     Total
Consideration
    Average
Price Per
Share
 
     Number    Percent     Amount      Percent  
     (in thousands)  

Existing stockholders

                            $                             $                

New investors

               $                 $    
  

 

  

 

 

   

 

 

    

 

 

   

Total

               $                 $    
  

 

  

 

 

   

 

 

    

 

 

   

The data in the table excludes            shares of Class A common stock initially reserved for issuance and unissued under our equity incentive plan.

If the underwriters’ option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to             , or approximately         % of the total number of shares of Class A common stock.

 

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

The following discussion and analysis should be read in conjunction with the “Summary—Summary Historical and Pro Forma Financial Data” and the accompanying financial statements and related notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for natural gas, NGLs and oil, production volumes, estimates of proved, probable and possible reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Unless otherwise indicated, the historical financial information in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects only the historical financial results of our predecessor, Bounty LLC, and does not give effect to the transactions described in “Corporate Reorganization.”

Overview

We own, acquire and manage mineral interests in the Appalachian Basin with the objective of growing cash flow from our existing portfolio for distribution to stockholders. Our initial target area was guided by a strong technical team that identified the areas of the basin we believe have the highest potential economics, enabling us to acquire our current holdings of approximately 65,000 net mineral acres. Our focus has been on acquiring primarily non-producing minerals in developing shale plays, which has allowed us to deliver significant organic production and cash flow growth as operators have increasingly developed the core of the basin. We expect this to continue as only 17% of our existing portfolio by identified net 3P locations have been developed as of June 30, 2022, which does not include the additional resource potential in our stacked pay areas. Our assets are exclusively mineral interests, which entitle us to the right to receive a share of recurring revenues from production without being subject to development capital requirements, operating expenses, or maintenance capital requirements. Mineral ownership results in higher cash flow margins than any other portion of the energy sector by providing exposure to commodity prices and minimizing operating expense while limiting exposure to service and development cost inflation.

We are a natural gas-focused minerals company. For the six months ended June 30, 2022, the production from our mineral acreage position was substantially all natural gas and NGLs, with total production associated with our mineral interests totaling 7.7 Bcfe, comprised of 76% natural gas, 20% NGLs and 4% oil. For the three months ended June 30, 2022, total production associated with our mineral interests was 4.2 Bcfe, comprised of 76% natural gas, 20% NGLs and 4% oil. We plan to accomplish our objectives of growing cash flow and paying quarterly dividends by utilizing cash flow from the current and continued development of our acreage. We intend to further grow our acreage position by selectively targeting additional accretive acquisitions using the same technical, land and legal rigor our team has historically applied to acquisition opportunities. Our revenue principally consists of royalties from natural gas, NGLs and oil

 

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producing activities and revenues from lease bonuses and extension payments. We are not a producer, and our natural gas, NGLs and oil revenue is derived from a fixed percentage of the natural gas, NGLs and oil produced by exploration and production operators from the acreage underlying our mineral interests, and in some instances net of post-production expenses and taxes.

Market Conditions and Operational Trends

Historically, natural gas, NGLs and oil prices have been volatile and may continue to be volatile in the future. During the past five years, the Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. The posted price for WTI has ranged from a low of negative ($36.98) per barrel in April 2020 to a high of $123.64 per barrel in March 2022. As of June 30, 2022, the posted price for oil was $107.76 per barrel and the Henry Hub spot market price of natural gas was $6.54 per MMBtu. Lower prices may not only decrease our revenues, but also potentially the amount of natural gas, NGLs and oil that our operators can produce economically. We expect this market will continue to be volatile in the future. We currently have no commodity price hedges in place or debt outstanding. Additionally, in 2020, the outbreak of COVID-19 caused a continuing disruption to the natural gas and oil industry and to our business by, among other things, contributing to a significant decrease in global crude oil demand and the price for oil. These events, combined with the macro-economic impact of the continued outbreak of the COVID-19 pandemic and declining availability of hydrocarbon storage, exacerbated the decline in commodity prices, including the historic, record low price of negative ($36.98) per barrel that occurred in April 2020. The decline in commodity prices adversely affected the revenues we received for our mineral interests in 2020. Although commodity prices were alleviated in 2021, market volatility has continued, and we expect it will continue for the foreseeable future.

Many E&P operators of our mineral interests announced reductions to their capital budgets for 2020 and beyond, which adversely affected the development pace of our properties during 2020 and the beginning of 2021. However, many operators have since resumed or increased drilling and completion activities compared to activity levels in 2020 in connection with the increase in commodity prices in late 2020 and 2021.

How We Evaluate Our Operations

We use a variety of operational and financial measures to assess our operations. Among the measures considered by management are the following:

 

   

volumes of natural gas, NGLs and oil produced;

 

   

number of rigs on our acreage, permits, DUCs, producing wells and PARs;

 

   

commodity prices; and

 

   

Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution.

Volumes of Natural Gas, NGLs and Oil Produced

In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various resource plays that comprise our portfolio of properties. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.

 

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Number of Rigs on our Acreage, Permits, DUCs, Producing Wells and PARs

In order to track and assess the performance of our assets, we monitor and analyze the number of rigs currently drilling our properties. We also constantly monitor the number of permits, DUCs, producing wells and PARs that are applicable to our mineral and royalty interests in an effort to evaluate near-term production from the various resource plays that comprise our asset base.

Commodity Prices

Commodity prices have historically been volatile and may continue to be volatile in the future. Lower prices may not only decrease our revenues, but also potentially the amount of natural gas, NGLs and oil that our operators can produce economically. The prices we receive for natural gas, NGLs and oil are determined by factors affecting global and regional supply and demand dynamics, such as economic and geopolitical conditions, production levels, availability of transportation, weather cycles and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and NYMEX prices are referred to as differentials. Substantially all of our production is derived from properties located in the Appalachian Basin of the United States.

Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.

Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas that is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.

NGLs. NGLs pricing is generally tied to the price of oil, but varies based on differences in liquid components and location.

Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil-pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.

The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities, such as sulfur.

 

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Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.

Hedging

We currently have no commodity price hedges, which results in full exposure to commodity prices. We may in the future enter into certain derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, any such hedging contracts may partially mitigate the effect of lower prices on our future revenue.

Adjusted EBITDA, Adjusted EBITDA Ex Lease Bonus and Cash Available for Distribution

Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution are non-GAAP supplemental financial measures used by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets and their ability to sustain dividends over the long term without regard to financing methods, capital structure or historical cost basis.

We and Bounty LLC define Adjusted EBITDA as net income (loss) before interest expense, depreciation, depletion and amortization and, less other income, gain or loss on sale of oil and gas properties, stock based compensation expense and adjusted for certain other non-cash items. We and Bounty LLC define Adjusted EBITDA ex lease bonus as Adjusted EBITDA further adjusted to add the non-cash portion of lease bonus income paid as mineral interests and to eliminate the impacts of lease bonus revenue we receive due to the unpredictability of timing and magnitude of the revenue. We and Bounty LLC define cash available for distribution as Adjusted EBITDA ex lease bonus less interest expense and cash taxes.

Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution do not represent and should not be considered alternatives to, or more meaningful than, net income, income from operations, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of our financial performance. Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution have important limitations as analytical tools because they exclude some but not all items that affect net income, the most directly comparable GAAP financial measure. Our and Bounty LLC’s computation of Adjusted EBITDA, Adjusted EBITDA ex lease bonus and cash available for distribution may differ from computations of similarly titled measures of other companies. For further discussion, please read “Summary—Summary Historical and Pro Forma Financial Data—Non-GAAP Financial Measures.”

Sources of Our Revenues

A significant portion of our revenues are derived from the mineral royalty payments we receive from our operators based on the sale of natural gas, NGLs and oil produced from our mineral interests. Royalty revenues may vary significantly from period to period as a result of changes in volumes of production sold by our operators, production mix and commodity prices. A portion of our revenue also comes from other royalty and lease bonus payments. Other royalty revenue is comprised of flat rate, shut-in and gas storage payments. Lease bonus revenue includes cash payments received at the beginning of a new lease and extension payments on current leases.

 

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The following table presents the breakdown of our revenues for the following periods:

 

     Six Months Ended June 30,     Year Ended December 31,  
           2022                 2021                 2021                 2020        

Revenue

        

Oil and gas royalty revenues

        

Natural gas sales

     52.8     53.4     63.0     63.2

NGLs sales

     17.9     22.4     22.1     14.5

Oil sales

     8.3     10.3     7.8     12.0

Other royalty revenue

     0.0     0.3     0.1     0.1
  

 

 

   

 

 

   

 

 

   

 

 

 

Total royalty revenue

     79.0     86.4     93.0     89.8
  

 

 

   

 

 

   

 

 

   

 

 

 

Lease bonus revenue

     21.0     13.6     7.0     10.2
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenue

     100     100     100     100
  

 

 

   

 

 

   

 

 

   

 

 

 

Principle Components of Our Cost Structure

The following is a description of the principle components of our cost structure. However, as an owner of mineral interests, we are not obligated to fund drilling and completion capital expenditures to bring a horizontal well on line, lease operating expenses to produce our natural gas, NGLs and oil or the plugging and abandonment costs at the end of a well’s economic life. All of the aforementioned costs are borne entirely by the E&P operator that has leased our mineral interests.

Royalty Deductions

Royalty deductions consist of our share of expenses for transportation, gathering, compression, processing and severance and ad valorem taxes.

Transportation, Gathering, Compression and Processing Expenses

Transportation, gathering, compression and processing expenses include the costs to process and transport our production to applicable sales points. Generally, the terms of the lease governing the development of our properties define the operator’s ability to pass through these expenses to us by deducting a pro rata portion of such expenses from our production revenues.

Severance and Ad Valorem Taxes

Severance taxes are paid on produced natural gas, NGLs and oil based on either a percentage of revenues from production sold or the number of units of production sold at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our natural gas, NGLs and oil revenues, which is driven by our production volumes and prices received for our natural gas, NGLs and oil. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the state or local government’s appraisal of the value of our natural gas, NGLs and oil properties, which also trend with anticipated production, as well as natural gas, NGLs and oil prices. Rates, methods of calculating property values and timing of payments vary across the different counties in which we own mineral interests.

 

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Depreciation and Depletion

Depreciation and depletion is the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas properties. We use the successful efforts cost method of accounting, and, as such, all costs associated with successful acquisitions are capitalized and reasonably aggregated and depleted based on a common geological structural feature. Costs associated with unsuccessful acquisitions are expensed. Depletion is the expense recorded based on the cost basis of our properties and the volume of hydrocarbons extracted during each respective period, calculated on a units-of-production basis. Estimates of proved reserves are a major component of our calculation of depletion. We adjust our depletion rates in the fourth quarter of each year based upon the year-end reserve report prepared by CG&A, unless circumstances indicate that there has been a significant change in reserves or costs.

General and Administrative

General and administrative (“G&A”) expenses are costs incurred for overhead, including payroll and benefits for our staff, costs of maintaining our headquarters, costs of managing our properties, audit and other fees for professional services and legal compliance. As a result of becoming a public company, we anticipate incurring incremental G&A expenses relating to expenses associated with SEC reporting requirements, including annual and quarterly reports to stockholders, tax return preparation and dividend expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing on the NYSE, independent auditor fees, legal expenses and investor relations expenses. These incremental G&A expenses are not reflected in the historical financial statements of our predecessor included elsewhere in this prospectus.

County and Other Taxes

County and other taxes are primarily comprised of county taxes and commercial activity taxes.

Acquisition and Land Costs

Acquisition and land costs include costs associated with unsuccessful acquisitions and ongoing land and title maintenance costs on existing properties.

Interest Expense

We did not have any debt outstanding or interest payments during the six months ended June 30, 2022 or the year ended December 31, 2021 and we do not currently have any debt outstanding. During the year ended December 31, 2020, we paid unused line fees per our credit agreement. We never drew on the facility and the credit agreement terminated on July 1, 2020. We reflected these unused line fee payments under our credit facility during the year ended December 31, 2020 in interest expense.

Factors Affecting the Comparability of Our Financial Results

Our future results of operations may not be comparable to the historical results of operations of our predecessor for the periods presented, primarily for the reasons described below.

Corporate Reorganization

The historical consolidated financial statements included in this prospectus are based on the financial statements of our accounting predecessor, Bounty LLC. As a result, the historical consolidated financial data may not give you an accurate indication of what our actual results

 

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would have been if the corporate reorganization had been completed at the beginning of the periods presented or of what our future results of operations are likely to be.

After giving effect to the corporate reorganization and this offering, Bounty Minerals will own an approximate        % interest in Bounty LLC (or        % if the underwriters exercise their option to purchase additional shares in full). In addition, Bounty Minerals will be the sole managing member of Bounty LLC and will be responsible for all operational, management and administrative decisions relating to Bounty LLC’s business.

The corporate reorganization that will be completed simultaneously with the closing of this offering provides a mechanism by which the Bounty LLC Units to be allocated among the Existing Owners, including the holders of incentive units, will be determined. As a result, the satisfaction of all conditions relating to the vesting of certain incentive units in Bounty LLC held by our management and certain employees and non-employees will be probable. Accordingly, we will recognize a charge for stock compensation expense of approximately $            million related to the estimated fair value of the incentive units at the time of grant, all of which will be non-cash. In addition, based on an assumed initial offering price of $            per share (which is the midpoint of the range set forth on the cover of this prospectus), over the next year as the vesting conditions of the unvested incentive units are satisfied we will recognize additional non-cash charges for stock compensation expense of approximately $            million.

Acquisitions

We plan to pursue potential accretive acquisitions of additional mineral interests. We believe we will be well positioned to acquire such assets and, should such opportunities arise, identifying and executing acquisitions will be a key part of our strategy. However, if we are unable to make acquisitions on economically acceptable terms, our future growth may be limited, and any acquisitions we may make may reduce, rather than increase, our cash flows and ability to pay dividends to our stockholders.

Debt and Interest Expense

Our predecessor has no debt outstanding. As a public company, we may finance a portion of our acquisitions or operations with borrowings under future credit facilities or other debt arrangements. As a result, any future borrowings will incur interest expense that is affected by both fluctuations in interest rates and our financing decisions.

Public Company Expenses

Following the closing of this offering, we anticipate incurring incremental general and administrative expenses as a result of operating as a publicly traded company, such as expenses associated with SEC reporting requirements, including annual and quarterly reports, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our Class A common stock on the NYSE, independent auditor fees, independent reserve engineer fees, legal fees, investor relations expenses, registrar and transfer agent fees, director and officer insurance expenses and director and officer compensation expenses. These incremental general and administrative expenses are not reflected in the historical financial statements of our predecessor. Additionally, in anticipation of this offering, we have hired additional employees and consultants, including accounting, engineering and legal personnel, in order to prepare for the requirements of being a publicly traded company.

 

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Income Taxes

Bounty Minerals is subject to U.S. federal and state income taxes as a corporation. Our predecessor, Bounty LLC, is treated as a flow-through entity for U.S. federal income tax purposes, and as such, is generally not subject to U.S. federal income tax at the entity level. Rather, the tax liability with respect to its taxable income will be passed through to the members of Bounty LLC, including Bounty Minerals, following our corporate reorganization. Accordingly, the financial data attributable to Bounty LLC contains no provision for U.S. federal income taxes or income taxes in any state or locality (other than margin tax in the State of Texas). We estimate that Bounty Minerals would have been subject to U.S. federal, state and local taxes at a blended statutory rate of        % of 2020 pre-tax earnings and would be subject to a blended statutory rate of        % of 2021 pre-tax earnings. Based on blended statutory rates of        % and        % for 2020 and 2021, respectively, Bounty Minerals would have incurred pro forma income tax expense for the years ended December 31, 2020 and 2021 of approximately $            million and $            million, respectively.

 

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Results of Operations

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021

The following table provides the components of our predecessor’s revenues and expenses for the periods indicated, as well as each period’s respective average prices and production volumes:

 

     Six Months Ended June 30,               
          2022                 2021            Variance  
     (dollars in thousands, except for realized prices)  

Production

          

Natural gas (MMcf)

     5,821        5,655        166       2.9

NGLs (MBbls)

     258        225        33       14.6

Oil (MBbls)

     56        55        1       2.0
  

 

 

    

 

 

    

 

 

   

 

 

 

Equivalents (MMcfe)

     7,705        7,335        370       5.0

Equivalents per day (Mcfe/d)

     42,568        40,523        2,045       5.0

Revenues

          

Natural gas revenue

   $ 33,552      $ 14,417      $ 19,135       132.7

NGLs revenue

     11,406        6,053        5,353       88.4

Oil revenue

     5,265        2,790        2,475       88.7

Other royalty revenue

     16        86        (71     (81.8 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

Total royalty revenue

     50,239        23,347        26,892       115.2

Lease bonus

     13,369        3,673        9,695       263.9
  

 

 

    

 

 

    

 

 

   

 

 

 

Total revenue

   $ 63,607      $ 27,020      $ 36,587       135.4
  

 

 

    

 

 

    

 

 

   

 

 

 

Realized prices

          

Natural gas (/Mcf)

   $ 5.76      $ 2.55      $ 3.21       126.1

NGLs (/Bbl)

     44.17        26.87        17.30       64.4

Oil (/Bbl)

     94.42        51.02        43.39       85.0
  

 

 

    

 

 

    

 

 

   

 

 

 

Equivalents (/Mcfe)

   $ 6.52      $ 3.17      $ 3.35       105.5
  

 

 

    

 

 

    

 

 

   

 

 

 

Operating expenses

          

Royalty deductions

   $ 4,318      $ 3,452      $ 866       25.1

County and other taxes

     291        183        108       58.9

Acquisition and land costs

     2        1,640        (1,638     (99.9 )% 

Depreciation and depletion

     5,985        6,591        (606     (9.2 )% 

General and administrative

     4,017        3,056        962       31.5
  

 

 

    

 

 

    

 

 

   

 

 

 

Total expenses

   $ 14,613      $ 14,922      $ (309     (2.1 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

Income from operations

   $ 48,995      $ 12,098      $ 36,897       305.0

Other income (expense)

          

Other income

   $ 1,026      $ 1      $ 1,025       149,190.0
  

 

 

    

 

 

    

 

 

   

 

 

 

Total other income (expense), net

   $ 1,026      $ 1      $ 1,025       149,190.0
  

 

 

    

 

 

    

 

 

   

 

 

 

Net income

   $ 50,020      $ 12,099      $ 37,922       313.4
  

 

 

    

 

 

    

 

 

   

 

 

 

 

Note:

Individual variance amounts may not calculate due to rounding.

 

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Revenues

Total revenues for the six months ended June 30, 2022 increased by 135%, or $36.6 million, compared to the six months ended June 30, 2021. The increase was attributable to a $26.9 million increase in total royalty revenue during the period and a $9.7 million increase in lease bonus revenue. The increase in total royalty revenue was primarily the result of increased commodity prices and increased drilling and completion activity on our mineral interests, which resulted in a 5% increase in production volumes to 42,568 Mcfe/d and a corresponding increase in revenue of $1.2 million. Realized commodity prices increased 106% resulting in an additional $25.8 million increase in total royalty revenue.

Natural gas revenue for the six months ended June 30, 2022 increased by 133%, or $19.1 million, compared to the six months ended June 30, 2021. Natural gas production volumes increased 3% to 32,159 Mcf/d resulting in a $0.4 million increase in natural gas sales. The increase in natural gas production volumes for the period was primarily attributable to increased drilling and completion activity on our properties. Realized natural gas prices increased by 126% to $5.76 per Mcf resulting in an additional increase in revenue of $18.7 million.

NGLs revenue for the six months ended June 30, 2022 increased by 88%, or $5.4 million compared to the six months ended June 30, 2021. NGLs production volumes increased by 15% to 1,427 Boe/d, resulting in a $0.9 million increase in NGLs sales, while realized NGLs prices increased by 64% to $44.17 per barrel, resulting in an additional increase in revenue of $4.5 million.

Oil revenue for the six months ended June 30, 2022 increased by 89%, or $2.5 million, compared to the six months ended June 30, 2021. Oil production volumes increased 2% to 308 Boe/d resulting in a $56 thousand increase in oil revenue, while realized oil prices increased 85% to $94.42 per barrel, resulting in an additional increase in revenue of $2.4 million.

Other royalty revenue for the six months ended June 30, 2022 decreased by 82% or $71 thousand, compared to the six months ended June 30, 2021. The decrease for the period was primarily attributable to a settlement payment for royalties received in 2021.

Lease bonus revenue for the six months ended June 30, 2022 increased by 264%, or $9.7 million, compared to the six months ended June 30, 2021. The increase was primarily attributable to an increase in leasing activity on our interests in Ohio, Pennsylvania, and West Virginia and lease extension options in Pennsylvania and West Virginia.

Other income

Other income includes interest income and a litigation settlement in 2022.

Operating and other expenses

Royalty deductions for the six months ended June 30, 2022 increased by 25%, or $0.9 million, as compared to the six months ended June 30, 2021, which was largely driven by the 15% increase in our NGL volumes resulting in increased transportation and processing expenses.

County and other taxes for the six months ended June 30, 2022 increased by 59%, or $0.1 million, as compared to the six months ended June 30, 2021, which was primarily due to higher county taxes associated with natural gas revenue as a result of higher natural gas production volumes and natural gas prices and due to Ohio commercial activity taxes.

 

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Acquisition and land expenses for the six months ended June 30, 2022 decreased by 100%, or $1.6 million, as compared to the six months ended June 30, 2021, which was primarily due to a contingent loss in 2021 of previously acquired minerals as a result of title issues.

Depreciation and depletion expense for the six months ended June 30, 2022 decreased by 9%, or $0.6 million, compared to the six months ended June 30, 2021, which was primarily due to a decrease in depletion expense of $0.6 million. Higher production volumes increased our depletion expense by $0.5 million, and a lower depletion rate decreased our depletion expense by $1.1 million.

General and administrative expense for the six months ended June 30, 2022 increased by 32%, or $0.9 million, compared to the six months ended June 30, 2021 as a result of legal, audit and other costs associated with the offering.

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

The following table provides the components of our predecessor’s revenues and expenses for the periods indicated, as well as each period’s respective average prices and production volumes:

 

     Year Ended December 31,               
          2021                2020           Variance  
     (dollars in thousands, except for realized
prices)
 

Production

          

Natural gas (MMcf)

     13,587        11,087        2,500       22.6

NGLs (MBbls)

     503        347        157       45.2

Oil (MBbls)

     101        115        (14     (12.2 )% 
  

 

 

    

 

 

    

 

 

   

 

 

 

Equivalents (MMcfe)

     17,209        13,854        3,356       24.2

Equivalents per day (Mcfe/d)

     47,149        37,852        9,297       24.6

Revenues

          

Natural gas revenue

   $ 46,856      $ 18,723      $ 28,133       150.3

NGLs revenue

     16,483        4,284        12,199       284.8

Oil revenue

     5,785        3,565        2,220       62.3

Other royalty revenue

     93        34        59       173.5
  

 

 

    

 

 

    

 

 

   

 

 

 

Total royalty revenue

     69,218        26,606        42,612       160.1

Lease bonus

     5,215        3,024        2,191       72.5
  

 

 

    

 

 

    

 

 

   

 

 

 

Total revenue

   $ 74,433      $ 29,630      $ 44,803       151.2
  

 

 

    

 

 

    

 

 

   

 

 

 

Realized prices

          

Natural gas (/Mcf)

   $ 3.45      $ 1.69      $ 1.76       104.1

NGLs (/Bbl)

     32.76        12.36        20.40       165.0

Oil (/Bbl)

     57.48        31.08        26.40       84.9
  

 

 

    

 

 

    

 

 

   

 

 

 

Equivalents (/Mcfe)

   $ 4.02      $ 1.92      $ 2.10       109.4
  

 

 

    

 

 

    

 

 

   

 

 

 

 

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     Year Ended December 31,              
          2021                2020          Variance  
     (dollars in thousands, except for realized
prices)
 

Operating expenses

         

Royalty deductions

   $ 8,637      $ 4,987     $ 3,650       73.2

County and other taxes

     411        326       85       26.1

Acquisition and land costs

     1,686        274       1,412       515.3

Depreciation and depletion

     12,788        11,692       1,096       9.4

General and administrative

     5,915        6,532       (617     (9.4 )% 
  

 

 

    

 

 

   

 

 

   

 

 

 

Total expenses

   $ 29,436      $ 23,811     $ 5,626       23.6
  

 

 

    

 

 

   

 

 

   

 

 

 

Income from operations

   $ 44,996      $ 5,819     $ 39,117       673.3

Other income (expense)

         

Other income

   $ 2      $ 175     $ (173     (98.9 )% 

Interest expense, net

            (57     57       100.0
  

 

 

    

 

 

   

 

 

   

 

 

 

Total other income (expense), net

   $ 2      $ 117     $ (115     (98.3 )% 
  

 

 

    

 

 

   

 

 

   

 

 

 

Net income

   $ 44,998      $ 5,936     $ 39,061       657.9
  

 

 

    

 

 

   

 

 

   

 

 

 

 

Note: Individual variance amounts may not calculate due to rounding.

Revenues

Total revenues for the twelve months ended December 31, 2021 increased by 151%, or $44.8 million, compared to the year ended December 31, 2020. The increase was attributable to a $42.6 million increase in total royalty revenue during the period and a $2.2 million increase in lease bonus revenue. The increase in total royalty revenue was primarily the result of increased commodity prices and increased drilling and completion activity on our mineral interests, which resulted in a 25% increase in production volumes to 47,149 Mcfe/d and a corresponding increase in revenue of $5.7 million. Realized commodity prices increased 109% resulting in an additional $36.8 million increase in total royalty revenue.

Natural gas revenue for the year ended December 31, 2021 increased by 150%, or $28.1 million, compared to the year ended December 31, 2020. Natural gas production volumes increased 23% to 37,225 Mcf/d resulting in a $4.2 million increase in natural gas sales. The increase in natural gas production volumes for the period was primarily attributable to increased drilling and completion activity on our properties in Pennsylvania and West Virginia. Realized natural gas prices increased by 104% to $3.45 per Mcf resulting in an additional increase in revenue of $23.9 million.

NGLs revenue for the year ended December 31, 2021 increased by 285%, or $12.2 million compared to the year ended December 31, 2020. NGLs production volumes increased by 45% to 1,378 Boe/d, resulting in a $1.9 million increase in NGLs sales, while realized NGLs prices increased by 165% to $32.76 per barrel, resulting in an additional increase in revenue of $10.3 million.

Oil revenue for the year ended December 31, 2021 increased by 62%, or $2.2 million, compared to the year ended December 31, 2020. Oil production volumes decreased 12% to 276 Boe/d resulting in a $0.4 million decrease in oil revenue. The decrease in oil production volumes for the period was primarily attributable to lower overall production from new wells in 2021

 

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compared to new well production in 2020. The decrease in oil production was offset by an increase in realized oil prices, which increased 85% to $57.48 per barrel, resulting in an additional increase in revenue of $2.7 million.

Other royalty revenue for the year ended December 31, 2021 increased by 173.5% or $59 thousand, compared to the year ended December 31, 2020. The increase for the period was primarily attributable to a settlement payment for royalties owed.

Lease bonus revenue for the year ended December 31, 2021 increased by 72%, or $2.2 million, compared to the year ended December 31, 2020. The increase was primarily attributable to an increase in leasing activity on our interests in Ohio and West Virginia.

Other income

Other income includes interest income and a litigation settlement in 2020.

Operating and other expenses

Royalty deductions for the year ended December 31, 2021 increased by 73%, or $3.7 million, as compared to the year ended December 31, 2020, which was largely driven by the 25% increase in our production volumes.

County and other taxes for the year ended December 31, 2021 increased by 26%, or $85 thousand, as compared to the year ended December 31, 2020, which was primarily due to higher county taxes associated with natural gas revenue as a result of higher natural gas production volumes and natural gas prices and due to Ohio commercial activity taxes associated with leasing activity.

Acquisition and land expenses for the year ended December 31, 2021 increased by 515%, or $1.4 million, as compared to the year ended December 31, 2020, which was primarily due to a contingent loss of previously acquired minerals as a result of title issues.

Depreciation and depletion expense for the year ended December 31, 2021 increased by 9%, or $1.1 million, compared to the year ended December 31, 2020, which was primarily due to an increase in depletion expense of $1.1 million. Higher production volumes increased our depletion expense by $2.7 million, and a lower depletion rate decreased our depletion expense by $1.6 million.

General and administrative expense for the year ended December 31, 2021 decreased by 9%, or $617 thousand, compared to the year ended December 31, 2020 as a result of lower professional fees and employee costs.

Interest and debt related expense for the year ended December 31, 2021 decreased $57 thousand compared to the year ended December 31, 2020 due to the expiration of the utilized credit agreement in 2020 and no additional debt incurred in the year ended December 31, 2021.

Capital Requirements and Sources of Liquidity

Historically, our primary sources of liquidity have been capital contributions from the Existing Owners and cash flows from operations. Following the completion of this offering, we expect our primary sources of liquidity to be the net proceeds retained from this offering, cash flows from operations, proceeds from any future issuances of debt or equity securities and, to the extent

 

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needed, borrowings under future credit facilities. We do not anticipate entering into any credit facilities in the near future. We expect our primary use of capital will be for the payment of dividends to our stockholders and for investing in our business, specifically the acquisition of additional mineral interests.

As a mineral interest owner, we incur the initial cost to acquire our interests, but thereafter do not incur any development capital expenditures or lease operating expenses, which are entirely borne by the operator. As a result, our only capital expenditures are related to our acquisition of additional mineral and royalty interests. The amount and allocation of future acquisition-related capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operations, investing and financing activities and our ability to assimilate acquisitions. For the six months ended June 30, 2022 and 2021, we incurred approximately $0 and $0.2 million, respectively, for acquisition-related capital expenditures. For the years ended December 31, 2021 and 2020, we incurred approximately $0.3 million and $0.9 million, respectively, for acquisition-related capital expenditures. We periodically assess changes in current and projected cash flows, acquisition and divestiture activities and other factors to determine the effects on our liquidity. Based upon our current natural gas, NGLs and oil price expectations for the year ending December 31, 2022, following the closing of this offering, we believe that our cash flow from operations and a portion of the proceeds from this offering will provide us with sufficient liquidity to execute our current strategy. However, our ability to generate cash is subject to a number of factors, many of which are beyond our control, including commodity prices, weather and general economic, financial, competitive, legislative, regulatory and other factors. If we require additional capital for acquisitions or other reasons, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, asset sales, offerings of debt and equity securities or other means. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us.

As of June 30, 2022, we had no debt outstanding, as we did not renew or replace our previously utilized credit facility agreement when it expired in 2020. However, we may put in place a new credit facility in the future.

Working Capital

Our working capital, which we define as current assets minus current liabilities, $43 million and $29 million as of June 30, 2022 and December 31, 2021, respectively. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant.

When new wells are turned to sales, our collection of receivables has lagged approximately three months from initial production as operators complete the division order process, at which point we are paid in arrears. Our cash and cash equivalents balance totaled $27.6 million and $13.6 million at June 30, 2022 and December 31, 2021, respectively. We expect that our cash flows from operations and the estimated net proceeds from this offering, as described under “Use of Proceeds,” will be sufficient to fund our working capital needs. We expect that the pace of our operators’ drilling of our undeveloped locations, production volumes, commodity prices and differentials to Henry Hub and WTI prices for our natural gas, NGLs and oil production will be the largest variables affecting our working capital.

 

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Cash Flows

The following table summarizes our cash flows for the periods:

 

     Six Months Ended June 30,     Year Ended December 31,  
           2022                 2021                 2021                 2020        
     (In thousands)  

Net cash provided by operating activities

   $ 55,540     $ 16,742     $ 46,136     $ 18,297  

Net cash used in investing activities

     (8     (261     (343     (898

Net cash used in financing activities

     (41,517     (17,500     (42,500     (23,827

Analysis of Cash Flow Changes Between the Six Months Ended June 30, 2022 and 2021

Operating activities. Net cash provided by operating activities is primarily affected by the prices of natural gas, NGLs and oil, production volumes, lease bonus revenue and changes in working capital. The 5% increase in production volumes and the 106% increase in realized prices during the six months ended June 30, 2022 discussed above were offset by increases in cash operating expenses and accounts receivable. Typically, an operator makes initial payment related to a new well approximately three months after the well has come on line, often comprised of multiple months of production paid in arrears.

Investing activities. Net cash used in investing activities is primarily comprised of purchases of furniture, equipment and natural gas and oil mineral interests. For the six months ended June 30, 2022, our net cash used in investing activities was primarily a result of acquisitions of mineral interests totaling $6 thousand and additions to other fixed assets of $2 thousand.

For the six months ended June 30, 2021, our net cash used by investing activities was primarily a result of acquisitions of mineral interests totaling $251 thousand and additions to other fixed assets of $10 thousand.

Financing activities. Net cash used by financing activities for the six months ended June 30, 2022 included $41.5 million in net capital distributions to the Existing Owners.

Net cash used in financing activities for the six months ended June 30, 2021 included $17.5 million in net capital distributions to the Existing Owners.

Analysis of Cash Flow Changes Between the Year Ended December 31, 2021 and 2020

Operating activities. Net cash provided by operating activities is primarily affected by the prices of natural gas, NGLs and oil, production volumes, lease bonus revenue and changes in working capital. The 24% increase in production volumes and the 109% increase in realized prices during the year ended December 31, 2021 discussed above were offset by increases in operating expenses and accounts receivable. Typically, an operator makes initial payment related to a new well approximately three months after the well has come on line, often comprised of multiple months of production paid in arrears.

Investing activities. Net cash used in investing activities is primarily comprised of purchases of furniture, equipment and natural gas and oil mineral interests. For the year ended December 31, 2021, our net cash used in investing activities was primarily a result of acquisitions of mineral interests totaling $323 thousand and additions to other fixed assets of $20 thousand.

For the year ended December 31, 2020, our net cash used by investing activities was primarily a result of acquisitions of mineral interests totaling $880 thousand and additions to other fixed assets of $18 thousand.

 

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Financing activities. Net cash used by financing activities for the year ended December 31, 2021 included $42.5 million in net capital distributions to the Existing Owners.

Net cash used in financing activities for the year ended December 31, 2020 included $23.8 million in net capital distributions to the Existing Owners.

Our Credit Facility

On September 21, 2017, we entered into a revolving credit agreement with Frost Bank secured by certain of our oil and gas properties. The borrowing base of $15,000,000 was subject to periodic redeterminations and bore interest at the prime rate. The Company never drew on the facility and the credit agreement terminated on July 1, 2020. The Company paid $38,125 in unused line fees in 2020.

Contractual Obligations

As of June 30, 2022 and as of December 31, 2021, we did not have any long-term debt, capital lease obligations, or long-term liabilities. Please see “Our Credit Facility” for a description of our previous revolving credit facility and Note 5 to our consolidated financial statements for the six months ended June 30, 2022 and 2021 and Note 7 to our consolidated financial statements for the years ended December 31, 2021 and 2020 included elsewhere in this prospectus for our operating lease obligations under the office lease agreement.

Quantitative and Qualitative Disclosure About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates and operator credit risk as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas and oil prices and interest rates and operator credit risk. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.

Commodity Price Risk

Our major market risk exposure is in the pricing that our operators receive for the natural gas, NGLs and oil produced from our properties. Realized prices are primarily driven by the prevailing global prices for natural gas, NGLs and oil in the United States. Pricing for natural gas, NGLs and oil has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. During the past five years, the Henry Hub spot market price for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. The posted price for WTI has ranged from a low of negative ($36.98) per barrel in April 2020 to a high of $123.64 per barrel in March 2022. As of June 30, 2022, the Henry Hub spot market price of natural gas was $6.54 per MMBtu and the posted price for oil was $107.76 per barrel. Lower prices may not only decrease our revenues, but also potentially the amount of natural gas, NGLs and oil that our operators can produce economically. We expect this market will continue to be volatile in the future. We currently have no commodity price hedges in place or debt outstanding. The prices our operators receive for the natural gas, NGLs and oil produced from our properties depend on numerous factors beyond their and our control, as discussed in “Risk Factors—Risks Related to Our Business.” A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations.

A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.6 million change in our royalty revenues related to natural gas sales for the six months ended June 30, 2022.

 

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A $1.00 per barrel change in NGLs prices would have resulted in a $0.3 million change in our royalty revenues related to NGL sales for the six months ended June 30, 2022. A $1.00 per barrel change in our realized oil price would have resulted in a $56 thousand change in our royalty revenues related to oil sales for the six months ended June 30, 2022. Royalties on natural gas sales contributed 53% of our total revenues for the six months ended June 30, 2022. Royalties on NGLs sales contributed 18% of our total revenues for the six months ended June 30, 2022.

A $0.10 per Mcf change in our realized natural gas price would have resulted in a $1.4 million change in our royalty revenues related to natural gas sales for the year ended December 31, 2021. A $1.00 per barrel change in NGLs prices would have resulted in a $0.5 million change in our royalty revenues related to NGL sales for the year ended December 31, 2021. A $1.00 per barrel change in our realized oil price would have resulted in a $0.1 million change in our royalty revenues related to oil sales for the year ended December 31, 2021. Royalties on natural gas sales contributed 63% of our total revenues for the year ended December 31, 2021. Royalties on NGLs sales contributed 22% of our total revenues for the year ended December 31, 2021.

We do not have any derivative instruments outstanding. We may in the future enter into derivative instruments, such as collars, swaps and basis swaps, to partially mitigate the impact of commodity price volatility. These hedging instruments would allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in natural gas, NGLs and oil prices.

Operator Credit Risk

Our principal exposures to credit risk are through receivables generated by the production activities of our operators. The inability or failure of our significant operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit risk associated with our operators is acceptable.

Interest Rate Risk

As of June 30, 2022, and December 31, 2021 and 2020, we had no debt outstanding. We never borrowed under our credit facility, and it terminated in July of 2020. Unused fee interest was calculated under the terms of the credit agreement governing our credit facility at a rate per annum equal to one-half of one percent (0.5%) of the difference between the borrowing base and the unused amount of the facility, calculated and paid quarterly. We may use certain derivative instruments to hedge our exposure to variable interest rates in the future, but we do not currently have any interest rate hedges in place.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our predecessor’s consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our predecessor’s financial statements requires it to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

A complete list of our predecessor’s significant accounting policies are described in the notes to our predecessor’s audited financial statements for the year ended December 31, 2021 included elsewhere in this prospectus.

 

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Basis of Accounting

The accounts are maintained and the financial statements have been prepared in accordance with GAAP.

Principles of Consolidation

Our predecessor’s financial statements included elsewhere in this prospectus include the accounts of Bounty Minerals LLC, Bounty Minerals Management LLC, Bounty Minerals BlockerCo LLC and Bounty Minerals EmployeeCo LLC, each wholly owned subsidiaries of Bounty LLC. All intercompany accounts and transactions have been eliminated in the financial statements.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect certain reported amounts in the financial statements and accompanying notes. Actual results could differ from these estimates and assumptions. Significant estimates with regard to these financial statements include the estimation of proved oil and gas reserves used in the calculation of depletion expense, the impairment of long-lived assets, including mineral interests, the estimate of the fair value of share-based compensation, and revenue accruals.

Recently Issued Accounting Pronouncements

See “Note 2—Summary of Significant Accounting Policies” to our consolidated financial statements as of December 31, 2021 included elsewhere in this prospectus, for a discussion of recent accounting pronouncements.

Under the JOBS Act, we expect that we will meet the definition of an “emerging growth company,” which would allow us to take advantage of an extended transition period for complying with new or revised accounting standards pursuant to Section 107(b) of the JOBS Act.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of Sarbanes-Oxley, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of Sarbanes-Oxley, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to have our independent registered public accounting firm attest to the effectiveness of our internal control over financial reporting under Section 404 until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. To comply with the requirements of being a public company, we will need to implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Inflation

There has been an increase in inflation in the United States, primarily in the past year. However, it has not had a material impact on our results of operations for the six months ended June 30, 2022 and 2021 or the years ended December 31, 2021 and 2020. Although the impact of

 

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inflation on our operations has been insignificant in recent years, it is still a factor in the United States economy and our operators tend to experience inflationary pressure on the cost of oilfield services and equipment as drilling activity increases in the areas in which our properties are located due to increasing natural gas and oil prices.

 

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BUSINESS

Our Company

We own, acquire and manage mineral interests in the Appalachian Basin with the objective of growing cash flow from our existing portfolio for distribution to stockholders. Our initial target area was guided by a strong technical team that identified the areas of the basin we believe have the highest potential economics, enabling us to acquire our current holdings of approximately 65,000 net mineral acres. Our focus has been on acquiring primarily non-producing minerals in developing shale plays, which has allowed us to deliver significant organic production and cash flow growth as operators have increasingly developed the core of the basin. We expect this to continue as only 17% of our existing portfolio by identified net 3P locations have been developed as of June 30, 2022, which does not include the additional resource potential in our stacked pay areas. Our assets are exclusively mineral interests, which entitle us to the right to receive a share of recurring revenues from production without being subject to development capital requirements, operating expenses, or maintenance capital requirements. Mineral ownership results in higher cash flow margins than any other portion of the energy sector by providing exposure to commodity prices and minimizing operating expense while limiting exposure to service and development cost inflation.

We are a natural gas-focused minerals company. For the six months ended June 30, 2022, the production from our mineral acreage position was substantially all natural gas and NGLs, with total production associated with our mineral interests totaling 7.7 Bcfe, comprised of 76% natural gas, 20% NGLs and 4% oil. For the three months ended June 30, 2022, total production associated with our mineral interests was 4.2 Bcfe, comprised of 76% natural gas, 20% NGLs and 4% oil. We plan to accomplish our objectives of growing cash flow and paying quarterly dividends by utilizing cash flow from the current and continued development of our acreage. We intend to further grow our acreage position by selectively targeting additional accretive acquisitions using the same technical, land and legal rigor our team has historically applied to acquisition opportunities.

Our History

Our team has a long history of buying mineral interests in top-tier prospective acreage throughout the United States. We were formed in 2012 with the objective of acquiring primarily non-producing mineral interests in the Appalachian Basin. We believe our team has a demonstrated and proven competitive advantage to technically identify, source, evaluate, negotiate, acquire and manage mineral and royalty interests in high quality areas of the Appalachian Basin. We acquired all of our approximately 65,000 net mineral acres through more than 1,200 transactions covering three states and 30 counties. The substantial majority of our acreage is subject to a lease, and of that leased acreage, we have had the opportunity to directly negotiate leases on over 21,000 net mineral acres, generating over $101 million of lease bonus income from our inception to June 30, 2022. The members of our executive team, including our Executive Chairman, have an average of 30 years of oil and gas experience, including prior leadership experience in the management of, and value creation within, minerals, upstream and midstream assets. We utilize geology and engineering consultants with an average of over 43 years of experience in the Appalachian Basin, with extensive subsurface expertise including vertical well logs and performance analysis, to help us identify and evaluate potential acquisition opportunities. We believe we have earned a positive reputation for building relationships through our negotiations with mineral owners, evaluating and analyzing title, navigating legal complexities and consistently and efficiently closing deals. Over the last five years, we have also actively engaged with the legislatures of Pennsylvania, West Virginia and Ohio to advocate for the passage of laws to both protect mineral owners and promote development. This process has allowed us to develop mutually beneficial relationships with operators and land owners, which are key to our continued success.

 

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Our experience and expertise has enabled us to aggregate a considerable inventory of non-producing acreage ahead of development activity. In 2017, our primary allocation of capital shifted from acquisition and resource capture to returning capital to our stockholders. While our capital allocation strategy shifted, our production grew by over 33% on a Mcfe basis from 2019 to 2021, demonstrating our ability to grow production without the need for additional significant capital investment in acquisitions due to our inventory remaining largely ahead of development activity. The graphic below compares our net acres acquired by year to our total net production over time:

 

LOGO

In addition to our production growth, our royalty revenue has increased substantially since 2019. We generated $25.7 million in royalty revenue in the fourth quarter of 2021 compared to $12.4 million in the fourth quarter of 2019, representing an increase of more than 107%.

Our Focus on the Appalachian Basin

We targeted the Southwestern portion of the Appalachian Basin in the tri-state area covering Ohio, West Virginia and Southwestern Pennsylvania, focusing on the highly-attractive, dry gas and liquids-rich portions of the play with stacked pay potential in three separate zones that provide favorable economics. While dry gas is the predominant resource in the Marcellus, Utica and Upper Devonian Shales, each of the Marcellus and the Utica shales have liquids-rich reserves located in the western portion of the play with dry gas reserves in the eastern portion. The geologic characteristics of the Appalachian Basin are mature and well-understood and we believe the continuous nature of the hydrocarbons in our targeted area of the basin provide for more consistent and a higher probability of development of our acreage. We have achieved organic production growth and increased cash flow by following emerging well results and targeting undeveloped areas with the best underlying geology where we expect operators will continue development activity and complete new wells to offset declines and grow production. The Southwestern portion of the Appalachian Basin, where we primarily target and own minerals, has grown from approximately 1,700 horizontal producing wells in 2012 to more than 10,600 horizontal producing wells as of March 31, 2022.

Our production growth has significantly outpaced the broader Appalachian Basin. Per the May 2022 EIA Update, dry natural gas production from the shale formations of Appalachia has been growing since 2006, with production in the region reaching 33.6 Bcf/d in December 2021. Since 2019, the production growth of the Appalachian Basin as a whole has averaged a 3% CAGR according to the May 2022 EIA Update, while increased development of our portfolio over the same period has resulted in organic gas production growth at a materially higher 10% CAGR. The graphic below compares our dry gas production growth from 2019 to 2021 to the dry gas production growth of the Appalachian Basin as a whole during the same period.

 

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Bounty vs. Appalachia Dry Gas Production Growth

 

LOGO

As of June 30, 2022, CG&A estimated only 17% of our existing portfolio by identified net 3P locations was currently developed. The graphic below compares our annual production (Mcfe/d) to the percentage of our acreage that was developed from 2013 through 2021:

Total Annual Production vs % Developed by Year

 

LOGO

Our focus on Appalachia is also unique among public mineral companies, who either have limited or no exposure to the Appalachian Basin. As such, we believe we offer a unique opportunity to public investors looking to participate in the growth of the largest and most economic natural gas basin in the United States.

 

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Future Development

Our minerals are leased to some of the top operators in Southwest Appalachia, who have significant inventory of future locations and DUCs, as well as a substantial portion of current active rigs in the basin. In the preceding two years, 79% of our acreage has been within five miles of an active rig, and 61% of our mineral acreage was within three miles of an active rig. In 2021, there were a total of 636 completions within counties in which we own mineral interests, of which 25% were located on our acreage. As of June 30, 2022, 39% of current active rigs in Southwest Appalachia were developing units on our acreage position. This increased activity on our acreage and proximity to rig activity further demonstrates the likelihood of future development and the potential for continued development. According to Enverus production data, as of August 10, 2022, 32 of the top 100 wells in Southwest Appalachia were on our acreage, and our mineral position was operated by all of the top ten operators in our portion of the basin, based on 2021 gross operated production. These operators make up approximately 79% of our total leased acreage position and, since 2020, have completed approximately 84% of the total wells within the counties in which we own mineral interests. Five of our top operators are companies whose capital budgets are deployed solely in Appalachia.

As operators continue to develop the substantial inventory of horizontal drilling locations on our acreage, we expect this development activity to support our production and cash flow from undeveloped mineral acreage in our portfolio. We divide our horizontal well inventory into six categories based on the development stage of the well or prospective well: (i) PDP, (ii) PARs, (iii) DUCs, (iv) permitted wells, (v) additional drilling locations inside current Bounty DSUs, and (vi) additional drilling locations in DSUs that we anticipate will be formed in the future based on our assumptions described below. PARs, DUCs and permitted wells, which we collectively refer to as our “activity wells,” provide near-term visibility on production activity in areas where we own interests, as we found that activity wells are likely to be converted into producing wells under a short time horizon. We refer to additional drilling locations inside current Bounty DSUs and additional drilling locations on DSUs that we anticipate will be formed in the future, as our “additional locations.”

The table below reflects our current gross and net horizontal producing wells, activity wells and additional locations as of June 30, 2022 across our DSU acreage by state and play, consistent with our 3P reserve report prepared by CG&A.

 

State

   PDP      PARs(1)      DUCs      Permitted
Wells
     LOCs Inside
Existing Unit
     Remaining
Locs
     Total  

Ohio

     494        18        33        17        95        835        1,492  

Pennsylvania

     253        6        27        24        39        675        1,024  

West Virginia

     505        42        36        81        106        1,901        2,671  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Gross Location Count

     1,252        66        96        122        240        3,411        5,187  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Net Location Count(2)

     11.04        0.50        0.81        1.81        2.40        48.12        64.68  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

PARs are completed wells on which we are awaiting receipt of revenue from operators. Producing wells that are temporarily shut-in due to nearby operational activity are included in the PAR category. On average, Bounty receives first payment on production three months after first production with the first revenue payment normally covering several months of production.

(2)

Reflects the assumed number of locations in which we would own a 100% net revenue interest determined by multiplying our total gross locations included in our DSU acreage by our anticipated average net revenue interest across our DSU acreage.

 

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Play Name

  PDP     PARs(1)     DUCs     Permitted
Wells
    LOCs Inside
Existing Unit
    Remaining
LOCs
    Total  

Marcellus

    725       40       56       84       124       1,856       2,885  

Utica Point Pleasant

    516       26       40       38       112       1,250       1,982  

Upper Devonian

    11                   4       305       320  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Gross Location Count

    1,252       66       96       122       240       3,411       5,187  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Net Location Count(2)

    11.04       0.50       0.81       1.81       2.40       48.12       64.68  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1)

PARs are completed wells on which we are awaiting receipt of revenue from operators. Producing wells that are temporarily shut-in due to nearby operational activity are included in the PAR category. On average, Bounty receives first payment on production three months after first production with the first revenue payment normally covering several months of production.

(2)

Reflects the assumed number of locations in which we would own a 100% net revenue interest determined by multiplying our total gross locations included in our DSU acreage by our anticipated average net revenue interest across our DSU acreage.

Our net mineral acreage is typically incorporated into larger DSUs, which are areas designated as a unit by agreement, field spacing rules, unit designation, or otherwise combined with other acreage pursuant to an administrative permit or order. We estimate and refer to this combined acreage, whether or not formally designated as a drilling spacing unit, as “DSU acreage” and to any DSU acreage in which we are entitled to participate or expect to be entitled to participate as a result of our mineral interests as our “DSU acres.” As of June 30, 2022, we had approximately 1,131,827 gross DSU acres. When our acreage is incorporated into a DSU acreage position, we participate in production from such acreage with our net revenue interest diluted on a proportional basis due to the incorporation of additional acreage in the DSU. Our additional locations represent locations on our DSU acreage that we have identified based on CG&A’s analysis of proved horizons and on publicly available information regarding existing operator spacing and development plans. In order to identify our additional locations, we undertake a four-step analysis to make determinations with respect to likely development programs, prospective zones, prospective well density per zone and, ultimately, the number of additional locations that exist on our DSU acreage. First, we analyze our acreage on a tract-by-tract basis, based upon what we believe to be the most likely development scenario for that tract. This is based on our review of offset or surrounding well geometry and/or well geometry that directly intersects our individual tracts. Second, each tract is assigned prospective zones based on a variety of factors, including geologic data, offset well results and industry activity. Third, we perform a prospective well density per zone analysis, which requires evaluation of (i) what we believe to be the most likely well spacing assumptions based on industry disclosure, third-party research and other publicly available data and (ii) offset activity data from producing wells, permitted wells and DUCs, Finally, for each prospective zone, we determine the number of producing wells, DUCs and permitted wells currently in existence and then assign additional locations to that tract based on our well spacing assumptions.

When we analyze and incorporate spacing assumptions, our methodology centers around several assumptions including inter-lateral well spacing, lateral length, unit setbacks, wellbore orientation and assumed DSU acreage. We generally estimate our DSU acreage based upon the drainage pattern each wellbore meeting the above spacing assumptions can withstand due to existing development within the area, and not to exceed a 1,280-acre threshold. Our current average DSU acreage for additional locations based on this framework is 770 acres. Our additional locations assume (i) in the Utica Formation, a 1,000 foot inter-lateral spacing and (ii) in the Marcellus and Upper Devonian Formations, a 750 foot inter-lateral spacing.

 

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Our additional horizontal well inventory contains a range of lateral lengths, the substantial majority of which are from 10,500 feet to 11,500 feet. The lateral length assumptions used for our additional locations in our inventory is based on historical activity in the area around each location. Operators have continued to drill longer lateral wells that are expected to yield higher economics. As such, our assumptions about lateral lengths may change in the future in-line with these developments which may contribute to decreases in horizontal locations. Additionally, it may be possible, through further down spacing and targeting of additional zones, to increase horizontal locations.

We believe there are significant opportunities to continue acquiring non-producing mineral acreage in the Appalachian Basin. We also anticipate that continued improvement in drilling and completion techniques may expand the economic viability of new core areas. The historical production, pricing, and differential data from our acreage on over 1,250 gross PDP wells and 11.04 net PDP wells in our current portfolio provides valuable information within each of our type curve areas for future acquisition economics and provides visibility to production and cash flow growth opportunities. With the help of CG&A, we have developed 17 individual type curves within our core areas that we use to evaluate potential acquisitions. In addition to our technical knowledge, over ten years of experience in the Appalachian Basin has given us the ability to leverage our familiarity of the regulatory environment, and unique title nuances to identify and evaluate opportunities that will supplement our organic development. We intend to capitalize on our reputation and relationships with landowners and operators to access distinct acquisition opportunities.

Key Operators

Our portfolio of assets provides exposure to a diverse group of top-tier producers, many of which operate solely in Appalachia and are able to deploy all of their capital within the basin. At current activity levels, the top operators in our portfolio have over a decade of premium inventory, which we believe will continue to drive future cash flow in the basin. As of June 30, 2022, these active operators were operating 26 rigs of the 31 total active rigs (84%) in Southwest Appalachia. The graphics below show our operator breakdown by controlled leased acreage as well as the rig count of Southwest Appalachia operators as of June 30, 2022.

 

Bounty Operator Exposure by Acreage

 

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Operators across Southwest Appalachia have continued to increase productivity per well by increasing lateral lengths and implementing more effective completion techniques, which directly benefit our mineral interests. These technical enhancements drive down well breakeven costs, which increase the number of economic drilling locations underlying our acreage and in the Appalachian Basin as a whole. Lower breakeven costs allow for continued development in low price environments. For example, production in Southwest Appalachia stayed relatively consistent during the low commodity price environment in 2020. Each additional hydrocarbon recovered increases our cash flow, and we realize the benefit of these improvements without incurring any related capital expense. Furthermore, additional economic locations within the Appalachian Basin contribute to greater potential acquisition targets.

Due to certain enhanced pricing provisions in our leases that we have opportunistically negotiated, covering over 21,000 net mineral acres, we also benefit from the strategies that some of our top operators employ to capitalize on higher commodity prices. In particular, given that United States exports for LNG according to the 2022 AEO will grow at a 4.6% CAGR from 2020 through 2040, several of our top producers, including Antero Resources Corporation, Range Resources Corporation, Southwestern Energy Company and EQT Corporation, have either begun or announced an intention to market natural gas directly to LNG facilities to realize premium pricing relative to Henry Hub. Under our negotiated leases, our enhanced pricing provisions provide that our proceeds will be based on a percentage of the gross price of the first sale of the commodity to a non-affiliate of the operator, as opposed to the in-basin spot price which for 2021 averaged approximately $0.62 below the Henry Hub spot price, whereas Bounty’s average differential was approximately $0.16 below Henry Hub spot price. According to the “EIA Liquefaction Report,” the United States is currently a leading exporter of LNG, with more than 80 MTPA of liquefaction capacity, or approximately 18% of global liquefaction capacity per the GIIGNL Annual Report. We believe that the increased global demand for LNG from a multitude of different regions for a myriad of uses will encourage the continued development of the Appalachian Basin, which is comprised of the most economic shale plays as of June 2022, and contains 50% of the United States’ remaining, recoverable shale gas reserves per the EIA Reserves Report.

We expect our current and future mineral acreage to be developed by our operators, who we believe will continue to deploy the most modern drilling and completion technologies, have access to capital and continually negotiate contracts that improve pricing.

Our Mineral Interests

As of June 30, 2022, our high quality portfolio solely consisted of mineral interests and we intend to continue to primarily acquire mineral interests. We believe that mineral interests have the highest and best value for our stockholders and provide the best long-term results, as they represent a perpetual right to the economic value of minerals produced from the land. Mineral interests are real property interests and grant ownership of the natural gas, NGLs and crude oil underlying a tract of land and the rights to explore for, drill for and produce natural gas, NGLs and crude oil on that land or to lease those exploration and development rights to a third party. When we lease those rights, usually for a one to five-year term, we typically receive an upfront cash payment, known as a lease bonus, and we retain a mineral royalty, which entitles us to a percentage of production or revenue from production free of lease operating expenses. A lessee can extend the lease beyond the initial lease term with continuous drilling, production or other operating activities or through negotiated contractual lease extension options. When production and drilling cease, the lease terminates, allowing us to lease the exploration and development rights to another party and receive another lease bonus.

Bounty’s focus on non-producing mineral acreage has created the opportunity for us to acquire a significant amount of acreage initially not subject to a lease. As a result, Bounty has had the opportunity to directly negotiate leases with operators to secure favorable terms that enhance

 

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pricing, minimize post-production expenses, and encourage more rapid development of our minerals. Of our approximately 65,000 net mineral acres, we have negotiated leases directly with operators on over 21,000 net mineral acres and generated over $101 million of lease bonus from inception to June 30, 2022. Historically, this income has been reinvested to acquire additional minerals. We have also been able to modify existing leases on almost 700 net mineral acres prior to production being established. Amendments to existing leases allow Bounty the opportunity to negotiate some of these same advantageous lease terms. Since inception, we have been able to enhance margins by raising the average royalty rate in our portfolio by 14% through negotiating new leases and amending current leases on approximately one-third of our total acreage. In addition, as of June 30, 2022, we had approximately 14,500 core net mineral acres that are not currently subject to a lease. As operators continue to establish and complete new DSUs through leasing within the core of Southwest Appalachia, we believe this provides us with the ability to continue to generate revenue both through the potential for initial lease bonus payments and enhanced royalty rate and pricing provisions, as demonstrated through the over 1,450 acres leased first half of 2022 generating approximately $4.5 million in new lease bonus income.

We generate a substantial portion of our revenues and cash flows from our mineral interests when natural gas, NGLs and oil are produced from our acreage and sold by the applicable operators and other working interest owners. Our royalty revenue generated from these mineral and royalty interests was approximately $50.2 million for the six months ended June 30, 2022 and $69.2 million for the year ended December 31, 2021. Approximately 90% of royalty revenue during the first half of 2022 was derived from the sale of natural gas and NGLs.

Unlike traditional oil and gas operators who must acquire large contiguous blocks of acreage to drill horizontal wells, targeting mineral ownership gives us the flexibility to acquire smaller blocks of acreage throughout the most economic areas of Southwest Appalachia. As a mineral interest owner, we make the initial investment to capture these interests but do not incur any development capital or lease operating expense associated with the development and extraction of the minerals. This insulates much of our company from service and material cost inflation, unlike operating companies, midstream companies and refineries. Additionally, ownership of mineral interests provides exposure to commodity prices, including natural gas, NGLs and oil. In order to maintain this uncapped exposure for our investors, we do not currently employ any commodity hedges. Our G&A has been consistently low relative to our revenues representing approximately 8% of revenue for the twelve months ended December 31, 2021. As our production has increased, our G&A continues to decline on a cost per unit of production basis as evidenced in the chart below.

 

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These advantages and minimized cost structure resulted in higher cash margins and free cash flow, allowing us to allocate a higher percentage of revenue to both distributions and re-investment opportunities compared to traditional exploration and production companies.

Mineral Ownership Summary

Currently, our mineral interests are entirely in the Appalachian Basin, which we believe is one of the premier unconventional natural gas producing regions in the United States. According to Enverus production data, as of August 10, 2022, 32 of the top 100 wells in Southwest Appalachia were on our acreage, and our mineral position was operated by all of the top ten operators in our portion of the basin, based on 2021 gross operated production. Our mineral acreage position is located in the most active states in Appalachia based on number of active horizontal wells. The table below summarizes our current mineral assets by state as of June 30, 2022.

 

     Leased Acreage      Unleased Acreage      Grand Total  

Ohio

     18,091        6,692     

Pennsylvania

     10,374        2,976     

West Virginia

     21,575        4,822     
  

 

 

    

 

 

    

Total

     50,040        14,490        64,530  
  

 

 

    

 

 

    

 

 

 

As set forth above, as of June 30, 2022, our interests covered approximately 65,000 net mineral acres, which the substantial majority have been leased to exploration and production (“E&P”) operators and other working interest owners with us retaining an average 16.3% royalty. Typically, within the mineral and royalty industry, owners standardize ownership of net royalty acres (“NRAs”) to a 12.5%, or a 1/8th, royalty interest, representing the number of equivalent acres earning a 12.5% royalty. When adjusted to a 1/8th royalty, our mineral interests represent approximately 65,300 NRAs, or approximately 8,200 NRAs on a 100% basis. The table below sets forth our weighted average royalty, as well as the NRAs adjusted to a 1/8th royalty and on a 100% basis, for our leased acreage.

 

     Net Mineral
Acres
     Weighted
Average Royalty
    NRAs (1/8
Basis)(1)(3)
     NRAs (100%
Basis)(2)(3)
 

Leased Acreage

          

Ohio

     18,091        16.4     23,777        2,972  

Pennsylvania

     10,374        15.3     12,692        1,587  

West Virginia

     21,575        16.7     28,825        3,603  

Leased Acreage Total

     50,040        16.3     65,294        8,162  
  

 

 

      

 

 

    

 

 

 

 

(1)

Standardized to a 1/8th Royalty (The hypothetical number of acres in which an owner owns a standardized 12.5%, or 1/8th, royalty interest based on the actual number of net mineral acres in which such owner has an interest and the average royalty interest such owner has in such net mineral acres. For example, an owner who has a 25%, or 1/4th, royalty interest in 100 net mineral acres would hypothetically own 200 NRAs on a 1/8th basis (100 multiplied by 25% divided by 12.5%)).

(2)

Standardized to a 100% Royalty (The hypothetical number of acres in which an owner owns a standardized 100% royalty interest based on the actual number of net mineral acres in which such owner has an interest and the average royalty interest such owner has in such net mineral acres. For example, an owner who has a 25%, or 1/4th, royalty interest in 100 net mineral acres would hypothetically own 25 NRAs on a 100% basis (100 multiplied by 25%)).

(3)

May not sum or recalculate due to rounding.

 

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Strategies

Our primary objective is to create stockholder value and maximize stockholder returns. We intend to accomplish these goals by executing the following strategies:

 

   

Utilizing the continued development of our portfolio to increase cash returns to stockholders while maintaining a conservative capital structure. Following this offering and subject to the determination of our Board of Directors, we initially expect to return capital to our stockholders through quarterly dividends. We expect Bounty LLC to initially pay quarterly distributions to us and the Existing Owners equal to 100% of (i) cash available for distribution and (ii) cash from lease bonus income, and that we, in turn, will pay quarterly dividends equal to the amount received from Bounty LLC net of cash taxes. See “Dividend Policy” for more information on the factors that could impact our expectations for our quarterly dividends and the factors our Board of Directors will consider in determining the frequency and amounts of dividends that we expect to pay. Only 17% of our existing portfolio by identified net 3P locations is currently developed, which does not include the additional resource potential underlying our minerals, made up of the Utica and Upper Devonian shales that lie above and below the Marcellus in stacked pay areas of our portfolio. As such, we believe that we have a significant amount of continued development built into our current portfolio and that such development will enable us to increase cash returns to stockholders over time. Further, because we have no debt, we believe that we will be able to continue to grow cash returns while also maintaining a conservative capital structure.

 

   

Actively managing our mineral acreage to capitalize on its continued development. We intend to maximize the revenues generated from our current portfolio of mineral interests by utilizing our team’s experience in the Appalachian Basin. For example, because we diligently review operator activity and payments, we are able to ensure that our operators are in compliance with their lease obligations and that the payments are timely, accurately disbursed and commensurate with our royalty percentage. Additionally, we have a history of directly negotiating new leases or amending current leases with favorable terms that enhance pricing, minimize post-production expenses and encourage our operators to more rapidly develop our minerals.

 

   

Providing exposure to commodity prices with protection from service and material cost inflation. As a mineral interest owner, we do not incur any development or lease operating expense associated with the development and extraction of the minerals. This insulates much of our company from service cost inflation unlike operating companies, midstream companies and refiners. Additionally, our business provides uncapped exposure to commodity prices as we do not currently have any commodity hedges in place. These advantages result in higher cash margins and free cash flow as a percentage of revenue, allowing us to allocate a higher percentage of our revenue to both distributions and re-investment opportunities as compared to traditional exploration and production companies.

 

   

Targeting accretive non-producing acreage in the core economic areas of the Appalachian Basin. While additional production and cash flow in our portfolio is initially expected to be generated from our already captured position in Southwest Appalachia, we intend to continue focusing our acquisition efforts in areas with the greatest economic and development potential. With over a decade of future drilling locations indicated by the top operators in the Appalachian Basin, we believe there are significant opportunities to target non-producing acreage. We plan to focus our acquisition efforts in these areas by

 

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continuing to follow technical results. The historical production, pricing and differential data provided to us on over 1,250 PDP wells in our current portfolio provides additional guidance within each of our type curve areas for future acquisition opportunities. We intend to primarily acquire mineral interests, and not target ORRIs or non-operated working interests. We believe mineral interests provide the highest and best value for our stockholders and the best long-term results, as they represent a perpetual right to the economic value of minerals produced from the land.

Strengths

We believe that the following competitive strengths will allow us to successfully execute our business strategies and to achieve our primary business objectives.

 

   

Natural gas is the preferred hydrocarbon to facilitate the energy transition, and the top operators on our mineral acreage have strong commitment to ESG. Natural gas is a clean-burning energy source with emissions far below that of oil and coal, two competing carbon-based energy sources. Per the EPA Emissions Report, the increasing use of natural gas in lieu of coal and oil has been partly responsible for the decline in United States greenhouse gas emissions from electricity generation since 1990. Methane also serves as a reliable secondary fuel that can supplement weather dependent clean energy sources, such as wind and solar power, to ensure electric grid reliability. The top operators on our acreage position have all made public commitments to environmental stewardship and to produce natural gas in a safer and cleaner manner than overseas competitors. Per the Rystad Report, Appalachia had the lowest scope 1 CO2 emissions of all United States onshore basins in 2020. Of the public operators on our acreage, all have incorporated an ESG metric into their management compensation structure, which we believe further incentivizes ethical development. With all of our acreage situated in the most economic area of the Appalachian Basin, we are primed to benefit as carbon pressures mount and transition to cleaner fuels accelerates.

 

   

Our undeveloped acreage provides exposure to natural gas demand growth. Natural gas is vital to the world economy and is used as a source of energy for electric power generation, a transport fuel and as a chemical feedstock, among a multitude of other uses. The 2022 AEO forecasts United States natural gas consumption to grow from 30.24 Tcf in 2021 to 34.01 Tcf by 2050. Adding to the growing domestic consumption of natural gas, LNG exports set a record high in 2021, averaging 9.7 Bcf/d and a 50% growth rate from 2020, according to the March 2022 EIA Update. The growing demand for natural gas will require an increasing number of wells drilled in Appalachia as the basin contains 50% of the United States’ remaining, recoverable shale gas reserves per the EIA Reserves Report. Appalachia continues to have superior drilling economics relative to other gas resource plays within the United States, as evidenced by the increase in active rigs in the basin over prior years. Our acreage is in the top producing areas within Appalachia with only 17% of our acreage by identified net 3P locations currently developed and in receipt of revenue. Natural gas and natural gas liquids comprised 96% of our current production and 98% of our 3P reserves as of June 30, 2022. We expect future growth in natural gas demand will support the continued growth of our cash flows and distributions.

 

   

Our acreage is concentrated in the premier natural gas basin in the United States with exposure to multiple pay zones. Appalachia is one of the premier natural gas regions in the world with over 33.6 Bcf/d of natural gas production as of December 2021, representing more than one-third of total United States dry gas production per the May 2022 EIA Update. There are currently three primary prospective pay zones in Southwest Appalachia, the Marcellus, Utica and Upper Devonian formations. Although the Marcellus and Utica

 

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formations are the most recent shale discoveries, the development of the Appalachian Basin over the past several years has significantly reduced the risk associated with the core areas of each play. The Southwestern portion of the Appalachian Basin, where our acreage is concentrated, is known for being predominantly dry gas; however, there is also exposure to liquids-rich natural gas and oil in both the Marcellus and Utica formations. Targeting acreage in the more liquids-rich areas of the Appalachian Basin in addition to the dry gas areas has allowed us to capitalize on commodity price fluctuations that drive operator economics and development plans.

 

   

Portfolio of high-quality operators developing our position. As of June 30, 2022, we owned approximately 65,000 net mineral acres and had an interest in greater than 1,250 wells across 610 DSUs in the core of Appalachia. Our mineral acreage is situated within all of the top ten producing counties in Southwest Appalachia based on total gross 2021 production. At current activity levels, the top operators in our portfolio have over a decade of premium inventory left, which we believe will drive future cash flow. Our premier operators, including Antero Resources Corporation, Ascent Resources Utica Holdings, LLC, CNX Resources Corporation, EQT Corporation, Gulfport Energy Corporation, Range Resources Corporation and Southwestern Energy Company, have continued to increase productivity per well by increasing lateral lengths and implementing more effective completion techniques. These technical enhancements directly benefit our mineral interests, as each additional hydrocarbon recovered increases our cash flow. Most importantly, we realize the benefit of these improvements without any of the capital expense. Furthermore, the enhancement in drilling efficiency further benefits us by increasing the number of economic drilling locations underlying our acreage and the Appalachian Basin as a whole. We expect our mineral acreage to be converted from undeveloped to producing by our operators who deploy the most modern drilling and completion technologies, have access to capital and are environmentally focused.

 

   

Experienced and proven management team. The members of our executive team, including our Executive Chairman, have an average of 30 years of oil and gas experience, including prior leadership experience in the management of, and value creation within, minerals, upstream and midstream assets. As a result, the executive team has significant breadth and experience in understanding and driving value creation through all stages of oil and gas asset life-cycle maturation. Our team has a long history of buying mineral interests in high-quality prospective acreage throughout the United States, most notably in Appalachia with the acquisition of approximately 65,000 net mineral acres through more than 1,200 transactions. We believe we have a demonstrated and proven competitive advantage in our ability to technically identify, source, evaluate, negotiate, acquire and manage mineral and royalty interests in high-quality acreage positions.

Appalachia and Natural Gas Overview

All of our mineral assets are located in the Appalachian Basin, which spans from upstate New York down through Pennsylvania, West Virginia, and into sections of Kentucky, Maryland, and Tennessee. According to the Encyclopedia Brittanica, this area is the oldest producing hydrocarbon region in America with oil and gas first discovered by Edwin Drake in Titusville, Pennsylvania in 1859 using conventional drilling techniques. Since that initial discovery, the industry has transitioned from conventional vertical drilling to unconventional horizontal drilling while continuously producing oil and gas in Appalachia to meet consumer needs. Currently, development of oil and gas is focused in the tri-state area of Ohio, Pennsylvania, and West Virginia, the core of the basin. Recent drilling activity has primarily targeted the Marcellus and Utica shales. According to 2017 EIA Statistics, drilling in the Marcellus Shale began in Pennsylvania in 2003 and development later extended to West Virginia, while drilling targeting the Utica formation began in 2010. In addition to these primary plays, there are multitudes of other targets in which we have exposure, including: the Berea, Big Injun, Devonian, Huron, and Rhinestreet plays.

 

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During the course of its 150-year drilling history, Appalachia has developed as one of the premier natural gas regions in the world, producing a 33.6 Bcf/d of natural gas as of December 31, 2021 per the May 2022 EIA Update. The Appalachian Basin represents greater than one-third of total United States dry gas production, as shown below:

U.S. Shale Dry Gas Production By Basin Over Time

 

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Source: EIA

The 2022 AEO forecasts United States natural gas consumption to grow from 30.24 Tcf in 2021 to 34.01 Tcf by 2050. As demand increases, the Appalachian Basin is going to continue to be integral in meeting U.S. consumption. Per the 2022 AEO, even in the midst of demand increase, U.S. natural gas imports have declined year over year since 2017, as shown below:

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The decrease in global imports leaves domestic Appalachia production primed to fill the void. Adding to the growing domestic consumption of natural gas, U.S. exports of LNGs set a record high in 2021, averaging 9.7 billion cubic feet per day (Bcf/d) and a 50% growth rate from 2020, according to the March 2022 EIA Update. Even with substantial growth from 2020 to 2021, 2022 EIA Statistics forecasts LNG exports increasing an additional 25% to 12.2 Bcf/d in 2022. The growing demand for natural gas will require an increasing number of wells drilled in the Appalachian Basin, which contains 50% of the United States’ remaining, recoverable shale gas reserves per the EIA’s Reserve Report. According to the S&P IRR report, the Marcellus and Utica Shale formations have the highest half-cycle post-tax internal rates of return (“IRR”) in the United States. Half-Cycle Post-Tax IRR is the internal rate of return from drilling an oil & gas well when only considering the marginal costs of drilling that single well (drilling and completion costs) as well as the tax costs, but not full-cycle costs such as acreage acquisition costs, general and administrative expenses, and infrastructure costs. The below graph uses the 12-month futures strip pricing as of June 2022. These favorable economics support our expectation that operators will focus on continued development of the area for years to come.

June 2022 Half-Cycle IRR Post-Tax Analysis

 

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Natural Gas, NGLs and Oil Data

Proved, Probable and Possible Reserves

Evaluation of Proved, Probable and Possible Reserves. Our proved, probable and possible reserve estimates as of June 30, 2022, December 31, 2021 and 2020 are based on reserve reports prepared by CG&A, our independent petroleum engineers. The reports of CG&A contain further discussion of the reserves estimates and its preparation procedures.

Within CG&A, the technical person primarily responsible for preparing the reserve estimates set forth in the reserve reports incorporated herein is Todd Brooker, President. Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker has been an employee of CG&A since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays,

 

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coalbed methane fields, waterfloods and complex, faulted structures. Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering, and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers (SPE) and the Society of Petroleum Evaluation Engineers (SPEE).

Mr. Brooker meets or exceeds the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. CG&A does not own an interest in any of our properties, nor is it employed by us on a contingent basis. Summaries of CG&A’s reports with respect to our proved, probable and possible reserve estimates as of June 30, 2022, December 31, 2021 and 2020 are included as exhibits to the registration statement of which this prospectus forms a part.

We maintain a consulting staff of petroleum engineers and geoscience professionals who work closely with our management team and CG&A to ensure the integrity, accuracy and timeliness of the data used to calculate our proved, probable and possible reserves relating to our properties. Our consulting staff, along with members from our management team, meet with our independent reserve engineers periodically during the period covered by the proved, probable and possible reserve report to discuss the assumptions and methods used in the proved, probable and possible reserve estimation process. We provide historical information to CG&A for our properties, such as ownership interest, natural gas and oil production, commodity prices and our estimates of our operators’ operating and development costs. Courtney Blackstock, our Director of Business Development, is primarily responsible for overseeing the review of our reserve estimates. Ms. Blackstock has substantial reservoir and operations experience having more than 15 years of experience. Prior to joining our Company in 2017, Ms. Blackstock worked at Trinity River Energy, Comstock Resources and Denbury Resources.

The preparation of our proved, probable and possible reserve estimates were reviewed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

 

   

review and verification of historical production data, which data is based on actual production as reported by our operators;

 

   

review by Ms. Blackstock of all of our reported proved, probable and possible reserves, including the review of all significant reserve changes and all new PUDs additions;

 

   

review of reserve estimates by Ms. Blackstock or under her direct supervision; and

 

   

direct reporting responsibilities by Ms. Blackstock to our Chief Executive Officer and President.

Estimation of Proved Reserves. In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are those quantities of oil and natural 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. The term “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. All of our proved reserves as of June 30, 2022, December 31, 2021 and 2020 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination

 

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results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy. Non-producing reserve estimates, for developed and undeveloped properties, were forecast using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developed non-producing and PUDs for our properties, due to the abundance of analog data.

To estimate economically recoverable proved reserves and related future net cash flows, we considered many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data that cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field-tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core data, and historical well cost and operating expense data.

Estimation of Probable Reserves. Estimates of probable reserves are inherently imprecise. When producing an estimate of the amount of natural gas, NGLs and oil that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. All of our probable reserves as of June 30, 2022, December 31, 2021 and 2020 were estimated using a deterministic method, which involves two distinct determinations: (i) an estimation of the quantities of recoverable oil and natural gas and (ii) an estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves uses the same generally accepted analytical procedures as are used in estimating proved reserves, namely production performance-based methods, material balance-based methods, volumetric-based methods and analogy. In the case of probable reserves, the recoverable reserves cannot be said to have a “high degree of confidence that

 

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the quantities will be recovered”, but are “as likely as not to be recovered.” The lower degree of certainty can come from several factors including: (1) direct offset production that does not meet an economic threshold, despite localized averages that do meet that threshold, (2) an increased distance from offset production to the probable location of over one mile but under three miles, (3) a perceived risk of communication or depletion from nearby producers, (4) a perceived risk of attempting new drilling or completion technologies that have not been used in direct offset production or (5) an uncertainty regarding geologic positioning that could affect recoverable reserves. When considering the factors referenced above, the lower degree of certainty of our probable reserves came from a combination of these factors. Many of the probable locations assigned in our reserve reports had few uncertainties and resemble proved undeveloped locations except for their distance from commercial production. Other probable locations had uncertainties related to not only distance from commercial production, but also related to well spacing and development timing. In general, we did not book probable locations if there was geologic uncertainty or if there was not commercial production to support such locations.

Estimation of Possible Reserves. Estimates of possible reserves are also inherently imprecise. When producing an estimate of the amount of natural gas, NGLs and oil that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors.

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. All of our possible reserves as of June 30, 2022, December 31, 2021 and 2020 were estimated using a deterministic method, which involves two distinct determinations: an estimation of the quantities of recoverable oil and natural gas and an estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves uses the same generally accepted analytical procedures as are used in estimating proved reserves, namely production performance-based methods, material balance-based methods, volumetric-based methods and analogy. In the case of possible reserves, the recoverable reserves cannot be said to be “as likely as not to be recovered,” but “might be achieved, but only under more favorable circumstances than are likely.” The lower degree of certainty can come from several factors including: (1) direct offset production that does not meet an economic threshold, despite localized averages that do meet that threshold, (2) an increased distance from offset production to the possible location of over one mile but under five miles, (3) a perceived risk of communication or depletion from nearby producers, (4) a perceived risk of attempting new drilling or completion technologies that have not been used in direct offset production or (5) an uncertainty regarding geologic positioning that could affect recoverable reserves. When considering the factors referenced above, the lower degree of certainty of our possible reserves came from a combination of these factors. Many of the possible locations assigned in our reserve reports had few uncertainties and resemble proved undeveloped locations except for their distance from commercial production. Other possible locations had uncertainties related to not only distance from commercial production, but also related to well spacing and development timing. In general, we did not book possible locations if there was geologic uncertainty or if there was not commercial production to support such location.

Estimates of probable and possible reserves are inherently imprecise and are more uncertain than proved reserves, but have not been adjusted for risk due to that uncertainty, and therefore they may not be comparable with each other and should not be summed either together or with

 

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estimates of proved reserves. Estimates of probable reserves which may potentially be recoverable through additional drilling or recovery techniques are subject to substantially greater risk of not actually being realized by us as compared to estimates of proved reserves. Possible reserves are reserves that are less certain to be recovered than probable reserves.

Summary of Reserves. The following table presents our estimated net proved, probable and possible reserves as of June 30, 2022, December 31, 2021 and 2020, based on our proved, probable and possible reserve estimates as of such dates, which have been prepared by CG&A, our independent petroleum engineering firm, in accordance with the rules and regulations of the SEC. All of our proved, probable and possible reserves are located in the United States. The increase in our estimated net proved, probable and possible reserves over this period was primarily the result of an increase in commodity prices.

 

     June 30,
2022 (1)
     December 31,
2021 (2)
     December 31,
2020 (3)
 

Estimated proved developed reserves:

        

Natural gas (MMcf)

     81,833        81,961        65,492  

NGLs (MBbls)

     3,960        3,875        2,460  

Oil (MBbls)

     441        490        386  
  

 

 

    

 

 

    

 

 

 

Total (MMcfe) (4)

     108,238        108,151        82,568  

Estimated proved undeveloped reserves:

        

Natural gas (MMcf)

     67,831        71,786        25,791  

NGLs (MBbls)

     3,006        1,894        955  

Oil (MBbls)

     364        374        168  
  

 

 

    

 

 

    

 

 

 

Total (MMcfe) (4)

     88,050        85,394        32,529  

Estimated proved reserves:

        

Natural gas (MMcf)

     149,665        153,747        91,283  

NGLs (MBbls)

     6,966        5,769        3,415  

Oil (MBbls)

     805        864        554  
  

 

 

    

 

 

    

 

 

 

Total (MMcfe) (4)

     196,288        193,545        115,097  

Estimated probable reserves (3):

        

Natural gas (MMcf)

     413,699        390,431        140,267  

NGLs (MBbls)

     14,282        14,417        6,391  

Oil (MBbls)

     2,394        2,209        1,619  
  

 

 

    

 

 

    

 

 

 

Total (MMcfe) (4)

     513,757        490,187        188,327  

Estimated possible reserves (4):

        

Natural gas (MMcf)

     224,989        242,490        61,477  

NGLs (MBbls)

     5,791        6,379        2,963  

Oil (MBbls)

     731        706        354  
  

 

 

    

 

 

    

 

 

 

Total (MMcfe) (5)

     264,122        285,000        81,379  

Natural Gas and Oil Prices: