Phoenix Energy One, LLC S-1/A, filed May 9, 2025
Phoenix Energy One, LLC (PHXE-P)
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As filed with the U.S. Securities and Exchange Commission on May 9, 2025.
Registration No. 333-282862
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
AMENDMENT NO. 4
TO
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
PHOENIX ENERGY ONE, LLC
(Exact name of registrant as specified in its charter)
| Delaware | 1311 | 83-4526672 | ||
| (State or other jurisdiction of incorporation or organization) |
(Primary Standard Industrial Classification Code Number) |
(I.R.S. Employer Identification Number) |
18575 Jamboree Road, Suite 830
Irvine, California 92612
(303) 749-0074
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
David Wheeler
Chief Legal Officer
18575 Jamboree Road, Suite 830
Irvine, California 92612
(303) 749-0074
(Name, address, including zip code, and telephone number, including area code, of agent for service)
With a copy to:
Christopher J. Clark, Esq.
Ross McAloon, Esq.
Latham & Watkins LLP
555 Eleventh Street, NW, Suite 1000
Washington, District of Columbia 20004-1304
(202) 637-2200
Approximate date of commencement of proposed sale to the public: From time to time after the effectiveness of this Registration Statement.
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ☒
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | ☐ | Accelerated filer | ☐ | |||
| Non-accelerated filer | ☒ | Smaller reporting company | ☐ | |||
| Emerging growth company | ☐ | |||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☐
The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the registration statement shall become effective on such date as the U.S. Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
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The information in this prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the U.S. Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.
SUBJECT TO COMPLETION, DATED MAY 9, 2025
PROSPECTUS
PHOENIX ENERGY ONE, LLC
$750,000,000 Senior Subordinated Notes
Comprising
| $140,000,000 9.0% Three-Year Cash Interest Notes | $110,000,000 9.0% Three-Year Compound Interest Notes | |
| $40,000,000 10.0% Five-Year Cash Interest Notes | $40,000,000 10.0% Five-Year Compound Interest Notes | |
| $30,000,000 11.0% Seven-Year Cash Interest Notes | $30,000,000 11.0% Seven-Year Compound Interest Notes | |
| $170,000,000 12.0% Eleven-Year Cash Interest Notes | $190,000,000 12.0% Eleven-Year Compound Interest Notes |
This is the initial public offering of our Senior Subordinated Notes (the “Notes”). We are offering up to $750,000,000 in aggregate principal amount of Notes on a continuous basis.
We will offer Notes with scheduled maturities of three, five, seven, and/or eleven years from the date of initial issuance of such Notes. Interest will accrue on the Notes at the rates set forth in this prospectus for each maturity and interest payment method, which range from 9.00% per annum to 12.00% per annum. Interest will be payable on the Notes monthly in arrears on the tenth day of each month or, if such day is not a business day, the following business day, either in cash (such Notes, “Cash Interest Notes”) or by adding such interest to the then-outstanding principal amount of the Notes (such Notes, “Compound Interest Notes”). We will issue Notes with specific maturities, interest payment methods, and interest rates in the amounts set forth in this prospectus. When you purchase Notes, you will select an available maturity, interest payment method, and related interest rate. See “Prospectus Summary—The Offering.”
The Notes will be our unsecured senior subordinated obligations and will not be guaranteed by any of our subsidiaries or affiliates. The Notes will rank senior in right of payment to all of our existing and future indebtedness and other obligations that are expressly subordinated in right of payment to the Notes; pari passu in right of payment with all of our existing and future indebtedness that is not so subordinated; effectively junior to any of our secured indebtedness and other secured obligations to the extent of the assets securing such indebtedness or other secured obligations; contractually subordinated to any indebtedness that we expressly agree is senior to the Notes; and effectively junior to any liabilities (including trade payables) or preferred equity of our subsidiaries. As of March 31, 2025, after giving effect to the sale of the Notes offered hereby (but not the use of proceeds therefrom, including to repay other indebtedness) and the borrowing of an additional $25.0 million under the Fortress Credit Agreement (as defined below) in April 2025, we would have had approximately $1,109.4 million of indebtedness outstanding, including $550.2 million that will rank contractually senior to the Notes, no additional amounts that will rank pari passu with the Notes, and $559.2 million that will be subordinated to the Notes. See “Risk Factors—Risks Related to the Notes and this Offering—Your right to receive payment under the Notes is contractually subordinated to Senior Debt,” “Risk Factors—Risks Related to the Notes and this Offering—The Notes are the Issuer’s obligations alone, and will be structurally subordinated to all obligations of the Issuer’s existing and future subsidiaries,” and “Description of Notes—Ranking.”
We recorded net losses of $24.8 million and $16.2 million for the years ended December 31, 2024 and 2023, respectively, and net income of $5.7 million for the year ended December 31, 2022. In 2023 and 2024, we incurred a significant amount of debt in order to accelerate the growth of our business by acquiring additional assets and establishing our direct drilling operations. As a result, our cash flows from operations alone would not have been sufficient to service required cash interest and principal payment obligations under our then-existing debt in 2023 and 2024. Furthermore, as of December 31, 2024, we estimate that we will need to make approximately $749.3 million and $3,224.8 million in capital expenditures to develop all our proved and probable undeveloped reserves, respectively, and that we will need to raise approximately $658.9 million in additional capital through the end of 2028 to fund such development. Although we expect our cash flows from operations to be sufficient to service cash interest and principal payment obligations under our debt for the foreseeable future, there can be no assurance as to the sufficiency of our cash flows for that purpose, and we do not expect such cash flows alone to be adequate to fund both our debt service obligations and the development of our reserves. Therefore, we expect to require additional capital to fund our growth and may require additional liquidity to service our debt. As a result, we may use the proceeds of additional debt, including the Notes offered hereby, to make interest and principal payments on our existing debt. See “Risk Factors—Risks Related to Our Business and Operations—The acquisition and development of our properties, directly or through our third-party E&P operators, will require substantial capital, and we and our third-party E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all, including as a result of increases in the cost of capital resulting from Federal Reserve policies in the past few years and otherwise,” “Risk Factors—Risks Related to Our Indebtedness—Despite our current level of indebtedness, we will still be able to incur substantially more debt. This could further exacerbate the risks to our financial condition described above,” “Risk Factors—Risks Related to Our Indebtedness—We may not be able to generate sufficient cash to service all of our existing and future indebtedness, including the Notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful,” “Risk Factors—Risks Related to the Notes and this Offering—We may invest or spend the proceeds of this offering in ways with which you may not agree,” “Use of Proceeds,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
We may redeem any Note, in whole or in part, at any time, at a redemption price equal to the then-outstanding principal amount thereof, plus accrued and unpaid interest, to, but excluding, the date of redemption. We may also purchase Notes, in whole or in part, at any time, through open-market or privately negotiated transactions with noteholders or pursuant to one or more tender or exchange offers or otherwise, upon such terms and at such prices, as well as with such consideration, as we may determine.
Subject to the provisions described in “Description of Notes—Subordination,” a holder may require us, at any time and from time to time prior to maturity, to redeem its Notes at a price equal to 95% of the aggregate principal amount of such Notes plus accrued and unpaid interest to, but excluding, the date of redemption, subject to certain exceptions and to an annual cap on all such redemptions of 10% of the aggregate principal amount of all Notes issued and then outstanding (the “10% Limit”). The principal amount of any Notes requested for redemption by, and redeemed from, our manager, executive officers, or their respective family members during any calendar year will not be included in calculating the 10% Limit with respect to any other holders for such calendar year; however, such redemptions will be included in calculating the 10% Limit with respect to our manager, executive officers, and their respective family members. Noteholders will not otherwise have the right to require us to redeem any Notes. If we are prohibited by law or contract (including the terms of our indebtedness) from redeeming Notes, or the 10.0% Limit limits a holder’s ability to have its Notes redeemed, the holder may have to hold its Notes to maturity. Our ability to redeem Notes may also be limited by our then-existing financial resources. We cannot assure you that sufficient funds will be available when necessary to make any required purchases. See “Risk Factors—Risks Related to the Notes and this Offering—Holders of Notes will have a limited right to require us to redeem their Notes, and we may not be able to repurchase such Notes when requested” and “Description of Notes—Mandatory Redemption; Repurchase at the Option of the Holders.”
The Notes will be issued only in registered form in minimum denominations of $1,000, and the initial minimum investment amount per holder will be $5,000 (the “Minimum Purchase Amount”). From time to time, we may, however, accept investments of less than the Minimum Purchase Amount or increase or decrease the Minimum Purchase Amount. There is no aggregate minimum purchase amount of Notes we are seeking to offer. We have the right to reject any investment, in whole or in part, for any reason.
The Notes will be a new issue of securities for which there is currently no established public trading market or trading platform. The Notes will not be listed on any securities exchange or automated quotation system. Notes will be transferable by a holder only with our prior written consent, which we may provide at our sole discretion and determine on an ad hoc basis. Accordingly, there can be no assurance as to the development of a trading platform, or the development or liquidity of any market, for the Notes, or that you will be able to transfer your Notes. Therefore, you must be prepared to hold your Notes to maturity. See “Risk Factors—Risks Related to the Notes and this Offering—Notes may only be transferred with our consent. There is no established trading market for the Notes and an active trading market for the Notes is not expected to develop” and “Description of Notes—Transfer.”
We are a wholly owned subsidiary of Phoenix Equity Holdings, LLC, a Delaware limited liability company (“Phoenix Equity”). Phoenix Equity is our sole member and, as such, directs our business and operations, including appointment and compensation of our officers. Lion of Judah Capital, LLC, a Delaware limited liability company (“LJC”), controls Phoenix Equity and, therefore, indirectly has control over our management. Furthermore, Adam Ferrari, our Chief Executive Officer, is the manager of Phoenix Equity. Daniel Ferrari and Charlene Ferrari each own 50% of the voting membership interests in, and are the managers of, LJC. Adam Ferrari, our Chief Executive Officer and the son of Daniel and Charlene Ferrari, owns 100% of the economic interests in LJC, but has no voting or managerial interest in LJC.
We are offering the Notes directly, without an underwriter or placement agent, and on a continuous basis. We have not made any arrangement to place any of the proceeds from this offering in an escrow, trust, or similar account. The Notes will be offered to prospective investors on a commercially reasonable efforts basis by Dalmore Group, LLC (“Dalmore Group” or, in its capacity as our broker/dealer of record, the “Managing Broker-Dealer”), a New York limited liability company and a member of the Financial Industry Regulatory Authority, Inc. (“FINRA”). “Commercially reasonable efforts” means that our broker/dealer of record is not obligated to purchase any specific number or dollar amount of Notes, but will use commercially reasonable efforts to sell the Notes. We reserve the right to engage additional broker-dealers who are members of FINRA (“selling group members”) to assist in the sale of the Notes.
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| Per Note | Total | |||||||
| Public offering price |
100.000 | % | $ | 750,000,000 | ||||
| Underwriting discounts(1) |
— | % | $ | — | ||||
| Proceeds, before expenses, to us |
100.000 | % | $ | 750,000,000 | ||||
| (1) | We have engaged Dalmore Group to perform administrative and compliance-related functions in connection with this offering, but not for underwriting or placement agent services. The fee for such functions ranges from 0.55% to 0.75% of the gross proceeds of the offering, depending on the amount sold and other factors (the “Broker-Dealer Fee”), which fee could total $5,025,000 if all Notes offered hereby are issued and sold. In addition to the Broker-Dealer Fee, we will pay to Dalmore Group certain sales commissions ranging from 0.50% to 1.00%, all of which sales commissions will be passed on to certain of our non-executive personnel who are licensed registered representatives of Dalmore Group and which fees could total $5,978,000 if all Notes offered hereby are issued and sold. Sales commissions increase based on the maturity of the Notes sold (i.e., sales of Notes with a three-year maturity result in a 0.50% sales commission, and sales of Notes with an 11-year maturity result in a 1.00% sales commission). See “Use of Proceeds” and “Plan of Distribution” for more information. |
We may amend or supplement this prospectus from time to time by filing amendments or supplements as required. You should read this entire prospectus and any amendments or supplements carefully before you make an investment decision.
Investors will be required to satisfy the suitability requirements described in this prospectus in order to purchase Notes. The method for submitting subscriptions and a more detailed description of the offering process are included in “Plan of Distribution—Financial Suitability Requirements” beginning on page 150 of this prospectus.
Investing in the Notes involves a high degree of risk, and should only be considered by those who can afford to lose their entire investment. Before you invest in Notes, you should carefully read the section entitled “Risk Factors” beginning on page 19 of this prospectus.
Neither the U.S. Securities and Exchange Commission (the “SEC”) 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.
The Notes are not certificates of deposit or similar obligations guaranteed by any depository institution and are not insured by the Federal Deposit Insurance Corporation or any governmental or private insurance fund, or any other entity. We do not contribute funds to a separate account such as a sinking fund to repay the Notes upon maturity.
The date of this prospectus is , 2025.
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Through and including , 2025 (the 90th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.
You should read this prospectus carefully before you invest in the Notes. This prospectus and the exhibits to the registration statement to which this prospectus relates contain the terms of the Notes we are offering. It is important for you to read and consider all of the information contained in this prospectus before making your investment decision.
You should rely only on the information contained in this prospectus, any amendment or supplement to this prospectus, or any free writing prospectus we may authorize to be delivered or made available to you. Neither we nor any selling group member has authorized anyone to provide you with information or to make any representations other than those contained in this prospectus, any amendment or supplement to this prospectus, or any free writing prospectuses we may authorize to be delivered or made available to you. Neither we nor any selling group member take any responsibility for, and provide no assurance as to the reliability of, any other information that others may give you. This prospectus, any amendment or supplement to this prospectus, or any applicable free writing prospectus is an offer to sell only the Notes offered hereby or thereby, but only under circumstances and in jurisdictions where it is lawful to do so. The information contained in this prospectus, any amendment or supplement to this prospectus, or any applicable free writing prospectus is current only as of its date, regardless of the time of its delivery or of any sale of Notes. Our business, financial condition, results of operations, and prospects may have changed since such date.
Neither we nor any selling group member have undertaken any efforts to qualify this offering for offers to investors in any jurisdiction outside the United States. Investors must have a U.S. mailing address (other than a P.O. Box) and a U.S. social security number and/or a U.S. tax identification number to be eligible to participate in this offering. See “Plan of Distribution.”
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The offering described in this prospectus is a continuous offering pursuant to Rule 415 under the U.S. Securities Act of 1933, as amended (the “Securities Act”). We intend to close sales of Notes on a weekly basis as described in the section of this prospectus entitled “Plan of Distribution—Offering Process.” From time to time, we may prepare prospectus supplements to update this prospectus for various purposes, such as to disclose changes to the terms of the offering of the Notes, provide quarterly updates of financial and other information included in this prospectus, and disclose other material developments. These prospectus supplements will be filed with the SEC pursuant to Rule 424(b) promulgated under the Securities Act and will be posted on our website. When required by SEC rules, such as when there is a “fundamental change” in the offering or the information contained in this prospectus, or when an annual update of financial information is required by the Securities Act or SEC rules, we will file post-effective amendments to the registration statement of which this prospectus forms a part, which will include either a prospectus supplement or an entirely new prospectus to replace this prospectus. We currently anticipate that post-effective amendments will be required, among other times, when there are changes to the material terms of the Notes.
The Notes are not available for offer and sale to residents of every state. Our website indicates the states where residents may purchase Notes. We will post on our website any special suitability standards or other conditions applicable to purchases of Notes in certain states that are not otherwise set forth in this prospectus as amended or supplemented from time to time.
CERTAIN DEFINED TERMS
As used in this prospectus, unless otherwise noted or the context otherwise requires (and except as otherwise defined in “Description of Notes” for purposes of that section only), references to:
| • | “Adamantium” means Adamantium Capital LLC, a Delaware limited liability company and a direct, wholly owned subsidiary of the Issuer. |
| • | “Adamantium Bonds” means unsecured bonds offered and sold by Adamantium pursuant to an offering under Rule 506(c) of Regulation D under the Securities Act, the proceeds of which are loaned to the Issuer under the Adamantium Loan Agreement (as defined below) as further described in “Prospectus Summary—The Offering—Ranking” and “Description of Notes—Ranking.” |
| • | “Adamantium Debt” means, collectively, indebtedness outstanding under the Adamantium Bonds, Adamantium Loan Agreement, and Adamantium Secured Note. |
| • | “Adamantium Loan Agreement” means that certain Loan Agreement, dated as of September 14, 2023, by and among the Issuer and PhoenixOp, as borrowers, and Adamantium, as lender, as the same may be amended and supplemented from time to time. |
| • | “Adamantium Secured Note” means that certain Secured Subordinated Promissory Note, dated as of November 1, 2024, by and between Adamantium and the noteholder named therein, as the same may be amended and supplemented from time to time. |
| • | “Adamantium Securities” means, collectively, indebtedness outstanding under the Adamantium Bonds and Adamantium Secured Note. |
| • | “Bbl” means one stock tank barrel, of 42 U.S. gallons liquid volume, used in this prospectus in reference to crude oil or other liquid hydrocarbons. |
| • | “Boe” means barrel of oil equivalent. |
| • | “Btu” means British thermal unit, which is the heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit. |
| • | “Dalmore Group” means Dalmore Group, LLC, a New York limited liability company and a member of FINRA. |
| • | “E&P” means exploration and production. |
| • | “Fortress” means Fortress Credit Corp., a Delaware corporation. |
| • | “Fortress Credit Agreement” means that certain Amended and Restated Senior Secured Credit Agreement, dated as of August 12, 2024, by and among the Issuer, PhoenixOp, as borrower, each of the lenders from time to time party thereto, and Fortress, as administrative agent for the lenders, as the same may be amended or supplemented from time to time. |
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| • | “Indenture” means that certain indenture, dated on or around the date of this prospectus, by and between the Issuer and UMB Bank, N.A., as trustee. |
| • | “Issuer” means Phoenix Energy One, LLC, a Delaware limited liability company. |
| • | “LJC” means Lion of Judah Capital, LLC, a Delaware limited liability company and the holder of a majority of the voting membership interests in Phoenix Equity. |
| • | “Mcf” means one thousand cubic feet. |
| • | “MMBtu” means one million Btus. |
| • | “NGL” means natural gas liquids. |
| • | “NMAs” means net mineral acres. |
| • | “NRAs” means net royalty acres. |
| • | “Phoenix Equity” means Phoenix Equity Holdings, LLC, a Delaware limited liability company and the sole member of the Issuer. |
| • | “PhoenixOp” means Phoenix Operating LLC, a Delaware limited liability company and a direct, wholly owned subsidiary of the Issuer. |
| • | “Reg A Bonds” means unsecured bonds offered and sold to date by the Issuer pursuant to an offering under Regulation A under the Securities Act as further described in “Prospectus Summary—The Offering—Ranking” and “Description of Notes—Ranking.” |
| • | “Reg D Bonds” means unsecured bonds offered and sold to date by the Issuer pursuant to offerings under Rule 506(b) or (c), as applicable, of Regulation D under the Securities Act as further described in “Prospectus Summary—The Offering—Ranking” and “Description of Notes—Ranking.” |
| • | “Reg D/Reg A Bonds” means, collectively, the Reg D Bonds and the Reg A Bonds. |
| • | “Senior Debt” means any indebtedness that the Issuer expressly determines is senior to the Notes, including, as of the date of this prospectus, indebtedness under the Fortress Credit Agreement, the Adamantium Debt, and the Senior Reg D/Reg A Bonds. |
| • | “Senior Reg D Bonds” means, collectively, the July 2022 506(c) Bonds, the 2020 506(b) Bonds, and the 2020 506(c) Bonds, each as defined in “Prospectus Summary—The Offering—Ranking” and “Description of Notes—Ranking.” |
| • | “Senior Reg D/Reg A Bonds” means the Reg D/Reg A Bonds that are not Subordinated Reg D Bonds. |
| • | “Subordinated Reg D Bonds” means, collectively, the August 2023 506(c) Bonds and the December 2022 506(c) Bonds, each as defined in “Prospectus Summary—The Offering—Ranking” and “Description of Notes—Ranking.” |
| • | “Trustee” means UMB Bank, N.A., in its capacity as trustee, acting on behalf of the noteholders. |
| • | “we,” “us,” “our,” the “Company,” “Phoenix Energy,” and similar references refer to Phoenix Energy One, LLC, formerly known as Phoenix Capital Group Holdings, LLC, and, where appropriate, its subsidiaries. |
For ease of reference, we have repeated definitions for certain of these terms in other portions of the body of this prospectus. All such definitions conform to the definitions set forth above.
Certain monetary amounts, percentages, and other figures included in this prospectus have been subject to rounding adjustments. Percentage amounts included in this prospectus have not in all cases been calculated on the basis of such rounded figures, but on the basis of such amounts prior to rounding. For this reason, percentage amounts in this prospectus may vary from those obtained by performing the same calculations using the figures in our consolidated financial statements included elsewhere in this prospectus. Certain other amounts that appear in this prospectus may not sum due to rounding.
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TRADEMARKS, TRADE NAMES, AND SERVICE MARKS
We own or have rights to trademarks, trade names, or service marks that we use in conjunction with the operation of our business. In addition, our name, logo, and website name and address are our service marks or trademarks. Solely for convenience, our trademarks, trade names, and service marks referred to in this prospectus appear without the ®, TM, and SM symbols, but those references are not intended to indicate, in any way, that we will not assert, to the fullest extent permitted under applicable law, our rights or the rights of the applicable licensors to these trademarks, trade names, and service marks. This prospectus may also contain additional trademarks, trade names, and service marks of other companies. We do not intend our use or display of other companies’ trademarks, trade names, or service marks to imply, and such use or display should not be construed to imply, relationships with, or endorsement or sponsorship of us by, these other companies.
INDUSTRY DATA AND OPERATING METRICS
This prospectus contains estimates, projections, and information concerning our industry and our business. We are responsible for all of the disclosure in this prospectus, and while we believe that each of the publications, studies, and surveys used throughout this prospectus are prepared by reputable sources and are generally reliable, we have not independently verified market and industry data from third-party sources. Some data and statistical and other information are based on internal estimates and calculations that are derived from publicly available information, research we conducted, internal surveys, our management’s knowledge of our industry, and their assumptions based on such information and knowledge, which we believe to be reasonable. In each case, this information and data involves a number of assumptions and limitations, and you are cautioned not to give undue weight to such information, estimates, or projections. Industry publications and other reports we have obtained from independent parties may state that the data contained in these publications or other reports have been obtained in good faith or from sources considered to be reliable, but they do not guarantee the accuracy or completeness of such data. In addition, projections, assumptions, and estimates of the future performance of the industry in which we operate and our future performance are necessarily subject to a high degree of uncertainty and risk due to a variety of factors, including those described in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.” These and other factors could cause our future performance to differ materially from the assumptions and estimates made by third parties and us.
Reserve engineering is a process of estimating underground accumulations of oil, natural gas, and NGL 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 could impact our strategy. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas, and NGL that we expect our operators to ultimately recover.
NON-GAAP FINANCIAL MEASURES
In addition to measures determined in accordance with generally accepted accounting principles in the United States (“GAAP”), this prospectus contains non-GAAP financial measures, which either exclude or include amounts that are not excluded from or included in the most directly comparable measures calculated and presented in accordance with GAAP.
Specifically, we utilize the non-GAAP financial measures “EBITDA” and “PV-10” in this prospectus as supplemental measures of financial performance that are not required by, or presented in accordance with, GAAP.
We calculate EBITDA by adding back to net income (loss) interest income, interest expense, depreciation, depletion, amortization, and accretion expense for the respective periods. Our management uses EBITDA to understand and compare our operating results across accounting periods, for internal budgeting and forecasting purposes, and to evaluate financial performance and liquidity, in each case, without regard to financing methods, capital structure, or historical cost basis. EBITDA is presented as supplemental disclosure as we believe it provides useful information to investors and others in understanding and evaluating our results, prospects, and liquidity period over period, including as compared to results of other companies. By providing this non-GAAP financial measure, together with a reconciliation to GAAP results, we believe we are enhancing investors’ understanding of our business and our operating performance, as well as assisting investors in evaluating how well we are executing strategic initiatives.
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EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income (loss), the most directly comparable GAAP measure. In particular, EBITDA excludes certain material costs, such as interest expense, and certain non-cash charges, such as depreciation, depletion, amortization, and accretion expense, that have been necessary elements of our expenses. Because EBITDA does not account for these expenses, its utility as a measure of our operating performance has material limitations. Other companies may not publish this or similar metrics, and our computation of EBITDA may differ from computations of similarly titled measures of other companies. Therefore, our EBITDA should be considered in addition to, and not as a substitute for, in isolation from, or superior to, our financial information prepared in accordance with GAAP, and should be read in conjunction with our consolidated financial statements and the related notes included elsewhere in this prospectus.
We calculate PV-10 as the discounted future net cash flows attributable to our proved oil and natural gas reserves before income taxes, discounted at 10% annually. PV-10 differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure, because it is calculated on a pre-tax basis. We use PV-10 when assessing the potential return on investment related to our oil and natural gas properties. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future income taxes, and is useful for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize PV-10 as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities.
Because the Issuer is a limited liability company and has currently elected to be treated as a partnership for income tax purposes, the pro rata share of taxable income or loss is included in the individual income tax returns of members based on their percentage of ownership. Consequently, no provision for income taxes is made in our standardized measure of discounted future net cash flows, and so currently our PV-10 is identical to the standardized measure of discounted future net cash flows. Notwithstanding the foregoing, we believe that the presentation of PV-10 is useful to investors because it is a commonly utilized measure in our industry for assessing the value of reserves.
PV-10 is not a substitute for the standardized measure of discounted future net cash flows. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our oil and natural gas reserves.
For a further discussion of our non-GAAP measures, including reconciliations to the most directly comparable GAAP measure, see “Prospectus Summary—Summary Historical Financial and Other Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures.”
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The following summary highlights information contained in more detail elsewhere in this prospectus, is not complete, and does not contain all the information that may be important to you in making an investment decision. Before making an investment decision, you should read this entire prospectus carefully, including the sections entitled “Risk Factors,” “Cautionary Statement Regarding Forward-Looking Statements,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” as well as our consolidated financial statements and the notes thereto appearing elsewhere in this prospectus.
Our Company
Overview
We operate in the oil and gas industry and execute on a three-pronged strategy involving (i) direct drilling operations of operated working interests, (ii) the acquisition of royalty assets, and (iii) the acquisition of non-operated working interest assets. Our direct drilling operations are currently primarily focused on development efforts in the Williston Basin in North Dakota and Montana and the Powder River and Denver Julesburg Basins in Wyoming. Our royalty and working interest acquisitions center around a variety of assets, including mineral interests, leasehold interests, overriding royalty interests, and perpetual royalty interests. These efforts have historically targeted assets in the Williston, Permian, Powder River, Uintah, and DJ Basins. We are agnostic as to geography and prioritize operational and asset potential when executing on our strategy.
We began operations in 2019 with the development of our specialized software system, which we have designed and improved over time to support our ability to identify, analyze, underwrite, transact, and manage our oil and gas assets. In 2019, we acquired our first mineral interest asset and began to generate revenue. In 2020, we expanded our operations and team to include specialists across a variety of key focus areas. From 2020 to 2024, we experienced significant growth in operations. For example, in 2020, the exploration and production (“E&P”) operators of our properties operated 725 gross and 2.8 net productive development wells on the acreage underlying our mineral and royalty interests, and the total acreage underlying our gross and net royalty interests was 177,824 and 1,506, respectively. In the four years since then, the E&P operators of our properties have operated an additional 6,312 gross and 75.1 net productive development wells on the acreage underlying our mineral and royalty interests, of which approximately 463 gross and 43.2 net productive development wells were drilled in 2024 alone. As of December 31, 2024, we had 3,962,065 and 531,120 acres underlying our gross and net royalty interests, respectively, as compared to 177,824 and 1,506 acres underlying our gross and net royalty interests, respectively, at December 31, 2020. Furthermore, our total production for the year ended December 31, 2020 was under 0.2 million Boe as compared to over 4.7 million Boe for the year ended December 31, 2024. In the same period our number of employees grew from 21 at December 31, 2020 to 135 at December 31, 2024. Additionally, we commenced direct drilling operations and spudded our first wells in the third quarter of 2023 and drilled a total of 42 gross and 38.6 net productive development wells in 2024. We expect these direct drilling operations to be a core component of our business strategy going forward.
Since our initial mineral interest asset acquisition in 2019, we have leveraged our specialized software system and experienced management team to identify asset opportunities that fit our desired criteria and potential for returns. While we evaluate and acquire a wide variety of assets, we have historically prioritized assets with potential for high monthly recurring cashflows and primarily target assets that have a potential payback within the short to medium-term and long-term cashflows.
Since 2019, we have completed 3,074 mineral, royalty, and leasehold interest acquisitions from landowners and other mineral interest owners, representing approximately 531,120 net royalty acres (“NRAs”) of royalty assets and 476,473 of net mineral acres (“NMAs”) of leasehold assets as of December 31, 2024. Over that same period, in addition to completing numerous small transactions, we completed more than 56 transactions larger than 1,000 NMAs that account for approximately 72% of our NMAs. We have acquired mineral, royalty, and leasehold interests from individuals, families, trusts, partnerships, small minerals aggregators, minerals brokers, large private minerals companies, private oil and gas E&P companies, and public minerals companies. We also actively manage our portfolio of assets and, as of December 31, 2024, have sold 3,152 NMAs since 2019.
Following the acquisition of an asset, we typically share in the proceeds of the natural resources extracted and sold by a third-party E&P operator. For certain assets, we operate our own direct drilling operations through our direct wholly owned subsidiary, Phoenix Operating LLC, a Delaware limited liability company (“PhoenixOp”).
For the years ended December 31, 2022, 2023, and 2024, we had revenue of $54.6 million, $118.1 million, and $281.2 million, respectively, net income (loss) of $5.7 million, $(16.2) million, and $(24.8) million, respectively, and EBITDA of $29.7 million, $65.9 million, and $150.7 million, respectively. As of December 31, 2022, 2023, and 2024, we had total assets of $157.0 million, $493.2 million, and $1,029.1 million, respectively, total liabilities of $148.3 million, $498.0 million, and $1,063.1 million, respectively (inclusive of total indebtedness of $117.4 million, $447.9 million, and $987.9 million, respectively), and retained earnings (accumulated deficit) of $6.5 million, $(9.7) million, and $(34.5) million, respectively. In 2023 and 2024, we incurred a significant amount of debt in order to accelerate the growth of our business by acquiring additional assets and establishing our direct drilling operations. As a result, our cash flows from operations alone would not have been sufficient to service the required cash interest and principal payment obligations under our then-existing debt in 2023 and 2024. Furthermore, as of December 31, 2024, we estimate that we will need to make approximately $749.3 million and $3,224.8 million in capital expenditures to develop all our proved and probable undeveloped reserves, respectively, and that we will need to raise approximately $658.9 million in additional capital through the end of 2028 to fund such development. Although we expect our cash flows from operations to be sufficient to service cash interest and principal payment obligations under our debt for the foreseeable future, there can be no assurance as to the sufficiency of our cash flows for that purpose, and we do not expect such cash flows alone to be adequate to fund both our debt service obligations and the development of our reserves. Therefore, we expect to require additional capital to fund our growth and may require additional liquidity to service our debt. As a result, we may use the proceeds of additional debt, including the Notes offered hereby, to make interest and principal payments on our existing debt. See “Risk Factors—Risks Related to Our Business and Operations— The acquisition and development of our properties, directly or through our third-party E&P operators, will require substantial capital, and we and our third-party E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all, including as a result of increases in the cost of capital resulting from Federal Reserve policies in the past few years and otherwise,” “Risk Factors—Risks Related to Our Indebtedness—Despite our current level of indebtedness, we will still be able to incur substantially more debt. This could further exacerbate the risks to our financial condition described above,” “Risk Factors—Risks Related to Our Indebtedness—We may not be able to generate sufficient cash to service all of our existing and future indebtedness, including the Notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful,” “Risk Factors—Risks Related to the Notes and this Offering—We may invest or spend the proceeds of this offering in ways with which you may not agree,” “Use of Proceeds,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Market Opportunity
Our royalty and working interest acquisitions generally focus on specific subsets of mineral and leasehold assets in the United States. From a market perspective, we focus on highly attractive and defined basins, currently serviced by top-tier operators, with assets that we believe will generate high near-term cash flow. All the assets we seek to acquire are purchased at what management believes are attractive price points and have a liquidity profile that is desirable in the secondary market. We generally seek to acquire assets that have near-term payback and long-term residual cash flow upside.
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Business Strategy
Our three-pronged strategy centers around (i) direct drilling operations of operated working interests, (ii) the acquisition of royalty assets, and (iii) the acquisition of non-operated working interest assets.
Direct Drilling Operations
We currently run our own direct drilling activities through PhoenixOp. Throughout 2024, we increased the extent to which we run our own direct drilling operations and expect to continue to grow our drilling activities going forward. We intend to actively drill and develop select assets in an effort to maximize value and resource potential, and we will generally seek to increase our production, reserves, and cash flow from operations over time. We have identified a number of potential drilling locations that we believe have the potential for attractive growth and opportunities. In accordance with that business plan, we acquired our second drilling rig in October 2024 and signed an agreement in January 2025 to take possession of our third drilling rig in April 2025.
As we rely more on our own direct drilling operations, our capital expenditures and operating expenses have also increased significantly, and we expect this increase in capital and operating expenses to continue as compared to our previous business model, which relied heavily on royalty and working interest acquisitions. As such, in 2025, we expect to have increased needs for additional capital in excess of cash flows from operating activities in order to fund the growth of our business and the development of our reserves. We expect to require additional outside funding, including through sales of the Notes offered hereby, to successfully execute this business strategy. Although we believe that running our own direct drilling operations will require significantly greater funds than partnering with a third-party operator, we believe that this strategy will provide greater control of cashflow, increased revenue, and larger potential for shorter payback periods as compared to returns on royalty assets and working interest assets. We expect that this shift in our business model will allow us to capture more of the upside from the use of our specialized software system. As of March 31, 2025 we estimate that our direct drilling operations will require approximately $423.6 million in additional capital throughout the rest of 2025 in order to achieve our intended business plan. We expect that these capital needs will be met in the near to medium term by capital contributions to PhoenixOp by us, which we expect to fund from time to time in varying amounts through a combination of cash from operations and the proceeds from loans and offerings of debt securities, including the Notes offered hereby. As of March 31, 2025, we had contributed approximately $192.9 million in cash and $44.8 million in lease assets to PhoenixOp. As of March 31, 2025, we had $202.6 million available for us to borrow under the Adamantium Loan Agreement (assuming Adamantium is able to issue the corresponding amount of Adamantium Securities). We also continue to issue August 2023 506(c) Bonds and have $63.0 million of additional headroom until we reach the announced target offering amount of $750.0 million. In the near term, we intend to raise the target offering amount of the August 2023 506(c) Bonds to $1,500.0 million. Our funding of additional amounts to PhoenixOp will not be subject to specific milestones or triggering events, but instead will be guided by our business judgment in order to execute on our intended business plan. We intend to make such capital contributions to PhoenixOp until such time as PhoenixOp procures its own financing, if any, or has sufficient cash from operations to operate without supplemental financing from us. PhoenixOp is currently a borrower under certain of our loan agreements, including the Fortress Credit Agreement and Adamantium Loan Agreement, and could borrow amounts under such agreements directly. There is currently no committed amount of additional financing under the Fortress Credit Agreement. Although we have issued over $200 million of Adamantium Securities to date, there can be no assurance that we will be successful in issuing additional Adamantium Securities and utilizing then-available commitments under the Adamantium Loan Agreement. See “Risk Factors—Risks Related to Our Business and Operations—The acquisition and development of our properties, directly or through our third-party E&P operators, will require substantial capital, and we and our third-party E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all, including as a result of increases in the cost of capital resulting from Federal Reserve policies in the past few years and otherwise.”
Leases are contributed to PhoenixOp at a value equal to our cost of acquisition of the contributed asset, and we anticipate contributing additional oil and gas properties to PhoenixOp in the future. Leases are generally contributed in order for PhoenixOp to operate extraction activities on such assets with the requisite title and permissions. We expect to only contribute oil and gas properties to PhoenixOp that are located in an area where we own or lease enough continuous productive acreage to support meaningful mineral extraction activities. Whether and when we have properties we decide to contribute to PhoenixOp will depend on, among other things, our ability to acquire properties from multiple owners, the amount and quality of mineral reserves discovered on such properties, the presence of or proximity to third-party operators with existing extraction activities, and the suitability of the area’s topography for drilling and operating producing wells. See “Risk Factors—Risks Related to Our Business and Operations—We, through our investment in PhoenixOp and future assignment of oil and gas properties to PhoenixOp, conduct direct drilling and extraction activities. Such activities pose additional risks to us.”
Royalty and Working Interest Acquisitions
For our royalty and working interest acquisitions, we have developed a process for the identification, acquisition, and monetization of assets. Below is a general illustration of our process:
| • | Our specialized software provides market intelligence to identify and rank potential assets and support our acquisition strategy and functions. |
| • | We make contact with the owner of the asset and begin the conversation on how we can increase the value of the property for the owner. |
| • | We provide the potential seller with a packet detailing our business, industry data, property valuation, and an all-cash offer based on the valuation. |
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| • | Our sales team engages the potential seller to discuss the terms of the sale and the value of the property. |
| • | We handle the closing of the property, and the property is migrated to our portfolio. |
| • | We utilize our land rights to extract natural resources from the property through third-party operators or determine to proceed with our own direct drilling operations. |
| • | We collect a portion of the revenue generated from the natural resources extracted and sold by a third-party operator. Our share of the revenue depends on the type of asset, either mineral rights or non-operated working interests, and the underlying contract with the third-party operator. |
| • | We continue to operate the property to extract the minerals through third-party operators or PhoenixOp until we decide to sell the property rights. |
Separate from the ordinary royalty income assets, we maintain a structural discipline to participate in non-operated working interests, in part for their tax benefits. Due to favorable U.S. Internal Revenue Service (the “IRS”) treatment, marrying this asset class to our pure royalty income creates an augmented “write off” strategy whereby the balanced portfolio effectively creates little to no annual taxable income. Functionally, the transactions we enter into are similar to traditional real estate transactions with respect to the mechanics. A seller agrees to sell to us, a purchase and sale agreement is executed, earnest money is conveyed, and manual diligence and title review is conducted as an audit function prior to closing. Upon closing, the funds are conveyed to the seller and the title is recorded by us in the applicable jurisdiction. Assets can produce for upwards of 20 years; however, there is a considerable regression/depletion curve over the life of the asset. As such, we tend to focus on wells that have recently begun producing or are likely to have new production in the near term. We focus on a closed-loop process from discovery to acquisition to long-term balance sheet ownership. We believe the recurring nature of these cash flows will allow for considerable scale without material increases in fixed overhead.
Our Specialized Software System
Our software system is designed to be scalable and process inputs from a variety of internal and external sources, supports our ability to identify, analyze, underwrite, and formally transact in the purchasing of oil and gas assets. Our software system operates across three key facets of our business:
| • | Asset Discovery – The data-driven system has customized inputs that are selected by management to pull in and incorporate data sets from multiple third-party sources through custom application interfaces that automatically retrieve updated information on a regular basis. For example, the system retrieves detailed land and title data and well-level data, including operator, production metrics, well status, dates of activities, well-specific activities, and historical reporting. The software system compiles these inputs and creates dashboards that can be accessed by management to analyze and review granular data on an asset-by-asset level. These dashboards present certain key information, including, among others, the geography of the asset, the estimated probability of future oil wells, the estimated predictability of the timing and value of cashflows, and local and national oil prices. We believe this process provides us with key market intelligence and insights, tailored to prioritize asset traits curated and targeted by management, to identify and rank potential assets. We believe this provides us with a competitive advantage because we are able to identify potentially valuable assets, based on our own hierarchy and prioritization of asset traits and data inputs, that may otherwise be overlooked by other industry participants. |
| • | Asset Grading and Estimates – The outputs from the asset discovery process are then run through a discounted cash flow model, using management inputs for discount rate and the price of oil to generate asset value and pricing estimates. The software system grades these assets based on management’s desired target criteria for high probability of high near-term cash flow, and generates a summary version of assets to prospect for acquisition for our sales team. The system also generates an acquisition price for each asset, which informs the sales team as to the maximum price that we may be willing to offer in any prospective transaction. This process is used to further characterize high-priority targets for sales and acquisition efforts. |
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| • | Asset Acquisition – Based on management input, the software system then routes the pricing and asset information from the asset grading and estimates process through an automated document generator to create customized, asset-specific document packages for utilization and distribution by our sales team. The workflow for these document packages is then processed and monitored using our internally developed software, which distributes the documents to our operations team for the preparation of an offering and sale package, which is then delivered to the prospective seller. Using relationship management features within our internally developed software, the sales team is able to record notes and each opportunity can be tracked from its original data upload through the lifecycle of the sales process. |
While the data inputs utilized by our software system are largely based on public information, considerable customization and coding has been undertaken to generate a system that we can successfully leverage in our business. This software was designed and built by us to address our specific needs, and we are not aware of a similar competitive product. We rely on trade secret laws to protect our software system and do not own any registered copyright, patent, or other intellectual property rights regarding our software. However, we believe the investment of significant monetary and intellectual resources have created a system that would be difficult to replicate. We currently have no intention of licensing or selling our software. See “Risk Factors—Risks Related to Legal, Regulatory, and Environmental Matters—We do not currently own any registered intellectual property rights relating to our software system and may be subject to competitors developing the same technology.”
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Company Structure
The following chart summarizes our corporate structure and principal indebtedness, as of the date of this prospectus. This chart is provided for illustrative purposes only and may not represent all legal entities affiliated with, or obligations of, the Issuer and its subsidiaries from time to time:
| (1) | The Issuer is a wholly owned subsidiary of, and is controlled by, Phoenix Equity. Phoenix Equity is the Issuer’s sole member and, as such, directs the Issuer’s business and operations, including appointment and compensation of its officers. LJC controls Phoenix Equity and, therefore, indirectly has control over the Issuer’s management. Daniel Ferrari and Charlene Ferrari each own 50% of the voting membership interests in, and are the managers of, LJC. Adam Ferrari, our Chief Executive Officer, the manager of Phoenix Equity, and the son of Daniel and Charlene Ferrari, owns 100% of the economic interests in LJC, but has no voting or managerial interest in LJC. See “Certain Relationships and Related-Party Transactions—Second Amended and Restated Limited Liability Company Agreement of Phoenix Energy One, LLC.” Phoenix Equity was formed primarily to provide an entity to pledge the equity interests of the Issuer as collateral to secure the borrowings under the Fortress Credit Agreement. In connection with the consummation of that transaction, the equityholders in the Issuer immediately prior to the consummation of the transaction exchanged their limited liability company interests in the Issuer for limited liability company interests in Phoenix Equity. As a result, the beneficial ownership of Phoenix Equity immediately after the transaction substantially reflects the beneficial ownership of the Issuer immediately prior to the transaction. Furthermore, following the formation of Phoenix Equity and the exchange of equity interests of the Issuer for equity interests of Phoenix Equity, equity awards that had previously been granted or promised by the Issuer and/or PhoenixOp were converted into equity awards granted by Phoenix Equity. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement” and “Compensation Discussion and Analysis—Details of Our Compensation Program—Equity Compensation.” |
| (2) | See “Security Ownership of Certain Beneficial Owners and Management” and “Management” for a description of our ownership structure and management. |
| (3) | For a description of the terms of the Adamantium Debt, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Adamantium Debt.” |
| (4) | See “Risk Factors” for a discussion of the risks related to our capital structure and your investment in the Notes. The terms of the Notes do not prohibit the Issuer or its subsidiaries from incurring additional indebtedness, which indebtedness may rank senior to the Notes. Furthermore, the Notes will not be guaranteed by any of the Issuer’s subsidiaries or affiliates or any other person. As a result, the Notes will be structurally subordinated to claims of creditors (including trade creditors) and preferred stockholders (if any) of the Issuer’s subsidiaries. See “Description of Notes—Ranking.” |
| (5) | For a description of the terms of the Reg D Bonds, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Reg D/Reg A Bonds.” |
| (6) | For a description of the terms of the Reg A Bonds, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Reg D/Reg A Bonds.” |
| (7) | Our wholly owned subsidiary, Phoenix Capital Group Holdings I, LLC, previously filed an offering statement under Regulation A under the Securities Act (“Regulation A”) in connection with a potential offering of senior subordinated unsecured bonds in an amount not to exceed $75 million annually in the aggregate, the proceeds of which would be loaned to us pursuant to an agreement secured by junior mortgages on certain properties. As of the date of this prospectus, we do not intend to pursue this offering or the qualification of this offering statement. |
| (8) | Firebird Services, LLC is a direct wholly owned subsidiary of PhoenixOp, which currently provides water management and disposal services for the wells operated by PhoenixOp. |
| (9) | For a description of the terms of the Fortress Credit Agreement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement.” |
Company Information
We were originally formed in Delaware on April 23, 2019. On January 23, 2025, we changed our name from “Phoenix Capital Group Holdings, LLC” to “Phoenix Energy One, LLC.” Our principal executive offices are located at 18575 Jamboree Road, Suite 830, Irvine, California 92612, and our telephone number at that address is (303) 749-0074. Our website address is https://phoenixenergy.com. The information contained on or linked to or from our website is not part of, and is not incorporated by reference into, this prospectus or the registration statement of which this prospectus forms a part, and you should not consider such information part of this prospectus or rely on any such information in making your decision whether to purchase the Notes.
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Summary Risk Factors
Investing in the Notes involves numerous risks and uncertainties, including risks associated with our business, operating results, and financial condition. Before investing in the Notes, you should carefully read the sections of this prospectus entitled “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” for an explanation of these risks. These risks include, among others, the following:
Risks Related to Our Business and Operations
| • | The businesses of direct drilling and extraction of minerals and acquisition of mineral rights are highly competitive. If we are unable to successfully compete within these businesses through our direct drilling operations conducted by PhoenixOp, we may not be able to identify and purchase attractive assets and successfully operate our properties. |
| • | We, through our investment in PhoenixOp and future assignment of oil and gas properties to PhoenixOp, conduct direct drilling and extraction activities. Such activities pose additional risks to us. |
| • | Our business is sensitive to the price of oil and gas and declines in prices may adversely affect our financial position, financial results, cash flows, access to capital, and ability to grow. |
| • | We have a limited operating history and have experienced periods of significant business growth in a short time, making it difficult for you to evaluate our business and prospects. If we are unable to manage our business and growth effectively, our business could be materially and adversely affected. |
| • | The acquisition and development of our properties, directly or through our third-party E&P operators, will require substantial capital, and we and our third-party E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all, including as a result of increases in the cost of capital resulting from Federal Reserve policies over the past few years and otherwise. |
| • | Our success relies extensively on our direct operations, through PhoenixOp and various third-party E&P operators, which could have a material adverse effect on our results of operations. |
| • | We rely on our E&P 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. |
| • | Our estimated mineral reserves quantities and future production rates are based on many assumptions that may prove to be inaccurate and they have not been verified by an independent third-party reserve engineering report. Any material inaccuracies in the reserves estimates or the underlying assumptions will materially affect the quantities and present value of our reserves. |
| • | The development of our estimated proved and probable undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. |
| • | Our PV-10 will not necessarily be the same as the current market value of our estimated proved reserves. |
| • | Estimated reserves do not represent or measure the fair value of the respective property or asset and we may sell or divest an asset for much less than the amount of estimated reserves. |
| • | Our future success depends on our ability to replace reserves. |
| • | We rely on our software system to identify attractive assets with oil and gas reserves and there can be no assurance that we will be able to continue to scale this software or that such software will be accurate in identifying assets. |
| • | We have limited control over the activities on properties that we do not operate. |
| • | The substantial majority of the wells in which we have a mineral or royalty interest and all the wells we directly operate are located in the Williston Basin, making us vulnerable to risks associated with concentration of our assets in a limited geographic area. |
| • | Cybersecurity attacks on our technological systems, or those of our third-party vendors, could significantly disrupt our business operations and subject us to liability. |
| • | Limitations or restrictions on our ability to obtain water for our direct drilling and hydraulic fracturing processes may have an adverse effect on our operating results. |
| • | Our hedging activities could result in financial losses and reduce earnings. |
Risks Related to Legal, Regulatory, and Environmental Matters
| • | We are subject to significant governmental regulations, and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, which could restrict our operations, increase costs of conducting our business, and delay our implementation of, or cause us to change, our business strategy. |
| • | We do not currently own any registered intellectual property rights relating to our software system and may be subject to competitors developing the same technology. Third parties may initiate legal proceedings alleging that our use of our software system is infringing or otherwise violating their intellectual property rights, which could lead to costly disputes or disruptions. |
| • | Current and future litigation, regulatory, administrative, or other legal proceedings could have a material adverse effect on our business and results of operations. |
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Risks Related to Our Indebtedness
| • | Our substantial indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the Notes and our other indebtedness. |
| • | Despite our current level of indebtedness, we will still be able to incur substantially more debt. This could further exacerbate the risks to our financial condition described above. |
| • | We will need to repay or refinance a substantial amount of our indebtedness prior to maturity of the Notes. Failure to do so would have a material adverse effect on our business, results of operations, and financial condition. |
| • | The terms of our outstanding indebtedness restrict, and the terms of future indebtedness we may incur may restrict, our current and future operations, particularly our ability to respond to changes in the economy or our industry or to take certain actions, which could harm our long-term interests. |
Risks Related to the Notes and this Offering
| • | Your right to receive payment under the Notes is contractually subordinated to Senior Debt. |
| • | The Notes will be effectively subordinated to the indebtedness under the Fortress Credit Agreement, the secured Adamantium Debt, and any of our other secured indebtedness, in each case, to the extent of the value of the assets securing that indebtedness. |
| • | The Notes are the Issuer’s obligations alone, and will be structurally subordinated to all obligations of the Issuer’s existing and future subsidiaries. |
| • | The terms of the Indenture and the Notes will not necessarily restrict our ability to take actions that may impair our ability to pay interest on and principal of the Notes. |
| • | Holders of Notes will have a limited right to require us to redeem their Notes, and we may not be able to repurchase such Notes when requested. |
| • | Notes may only be transferred with our consent. There is no established trading market for the Notes and an active trading market for the Notes is not expected to develop. |
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THE OFFERING
The following summary describes the principal terms of the Notes and the Indenture (as defined below) and is not intended to be complete. It does not contain all information that may be important to you. Some of the terms and conditions described below are subject to important limitations and exceptions. For a more complete understanding of the Notes and the Indenture, see the section of this prospectus entitled “Description of Notes.” In this summary, the terms “we,” “us,” and “our” each refer to Phoenix Energy One, LLC (the “Issuer”) and its consolidated subsidiaries; provided, however, that references to “we,” “us,” and “our” pertaining to references to rights and obligations under the Notes and the Indenture do not include the Issuer’s subsidiaries. Certain descriptions herein of provisions of the Notes and the Indenture are summaries of such provisions and are qualified herein by reference to the Notes and the Indenture, forms of which are filed as exhibits to the registration statement of which this prospectus forms a part.
| Issuer | Phoenix Energy One, LLC, a Delaware limited liability company. | |
| Notes Offered | We are offering $750,000,000 in aggregate principal amount of Senior Subordinated Notes, comprising the following: | |
| Maturity |
Interest Payment Method | Interest Rate | Aggregate Principal Amount | |||||||||
| 3 Years |
Cash Interest | 9.0% | $ | 140,000,000 | ||||||||
| 3 Years |
Compound Interest | 9.0% | $ | 110,000,000 | ||||||||
| 5 Years |
Cash Interest | 10.0% | $ | 40,000,000 | ||||||||
| 5 Years |
Compound Interest | 10.0% | $ | 40,000,000 | ||||||||
| 7 Years |
Cash Interest | 11.0% | $ | 30,000,000 | ||||||||
| 7 Years |
Compound Interest | 11.0% | $ | 30,000,000 | ||||||||
| 11 Years |
Cash Interest | 12.0% | $ | 170,000,000 | ||||||||
| 11 Years |
Compound Interest | 12.0% | $ | 190,000,000 | ||||||||
| The Notes will be governed by an indenture to be entered into between us and UMB Bank, N.A., as trustee (as amended and supplemented from time to time, the “Indenture”). | ||
| Minimum Purchase Amount |
The Minimum Purchase Amount is $5,000 aggregate principal amount of Notes. An investment in Notes is subject to certain maximum investment limits, some of which are based on financial suitability. See “Plan of Distribution—Financial Suitability Requirements.” You should purchase Notes only if you have substantial financial means and you have no need for liquidity in your investment. | |
| Maturity | The Notes offered hereby will mature three, five, seven, and/or eleven years from the date of initial issuance of such Notes. An available maturity will be selected by you when you make your investment. | |
| Interest | Interest will accrue on the Notes at the rates set forth above for each maturity and interest payment method. An available maturity and related interest rate will be selected by you when you make your investment. | |
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| Interest will accrue on the Notes on the basis of a 360-day year consisting of twelve 30-day months. See “Description of Notes—General.” | ||
| Payment of Interest | Interest on the Notes will be payable monthly in arrears on the tenth day of each month or, if such day is not a business day, the following business day. Interest on the Notes will accrue from and including the date of initial issuance. We will pay interest on the Notes either in cash (with respect to Cash Interest Notes) or by adding such interest to the then-outstanding principal amount of the Notes (with respect to Compound Interest Notes). An available maturity, interest payment method, and related interest rate will be selected by you when you make your investment. | |
| Guarantors | The Notes will not be guaranteed by any of our subsidiaries, parent entities, or other affiliates. | |
| Ranking | The Notes will be the Issuer’s senior subordinated unsecured obligations and will: | |
| • rank contractually senior in right of payment to all of the Issuer’s existing and future indebtedness that is contractually subordinated to the Notes, including the Subordinated Reg D Bonds (as defined below), which as of March 31, 2025 totaled $559.2 million; | ||
| • without giving effect to collateral arrangements, rank equally in right of payment with all of the Issuer’s future senior indebtedness (other than Senior Debt), of which, other than Senior Debt, there is none as of March 31, 2025; | ||
| • be contractually subordinated to any Senior Debt, including indebtedness under the Fortress Credit Agreement, the Adamantium Debt, and the Senior Reg D/Reg A Bonds, which as of March 31, 2025, after giving effect to the borrowing of an additional $25.0 million under the Fortress Credit Agreement in April 2025, totaled $550.2 million; | ||
| • be effectively subordinated to any of the Issuer’s existing or future secured indebtedness and other obligations, including under the Fortress Credit Agreement and the Adamantium Loan Agreement, to the extent of the value of the assets securing such indebtedness, which as of March 31, 2025, after giving effect to the borrowing of an additional $25.0 million under the Fortress Credit Agreement in April 2025, totaled $438.0 million (all of which constitutes Senior Debt as described above); and | ||
| • be structurally subordinated to all of the existing and future liabilities (including trade payables) and preferred equity of each of the Issuer’s subsidiaries, including Adamantium. | ||
| As of March 31, 2025, we had approximately $132.8 million of indebtedness outstanding that is maturing within one year. We plan to repay our indebtedness with cash from operations, the proceeds of debt securities offerings, including August 2023 506(c) Bonds, the Notes offered hereby, and Adamantium Securities (and the corresponding proceeds under the Adamantium Loan Agreement), and other financing sources. See “Use of Proceeds.”
As of March 31, 2025, after giving effect to the borrowing of an additional $25.0 million under the Fortress Credit Agreement in April 2025, we had approximately $438.0 million of secured indebtedness outstanding, consisting of (i) $275.0 million aggregate principal amount outstanding under the Fortress Credit Agreement, which consists of a $100.0 million term loan, borrowed in full on August 12, 2024, a $35.0 million delayed draw term loan facility, borrowed in full on October 11, 2024, a $115.0 million term loan, borrowed in full on December 18, 2024, and a $25.0 million term loan, borrowed in full on April 16, 2025, each of which is secured by a senior security interest in all of the assets of Phoenix Equity and its subsidiaries, and (ii) (A) $163.0 million aggregate principal amount outstanding under the Adamantium Loan Agreement, which provides for up to $407.0 million in aggregate principal amount of borrowings in one or more advances and is secured by mortgages | ||
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| on certain of our properties, which mortgages are junior to the security interest of the Fortress Credit Agreement and other existing and future senior secured indebtedness, and (B) without duplication, $7.0 million aggregate principal amount outstanding under the Adamantium Secured Note, which initially matures in November 2031, has an interest rate of 16.5% per annum, and is secured by Adamantium’s rights under the Adamantium Loan Agreement. Borrowings under the Adamantium Loan Agreement correspond to the receipt by Adamantium of proceeds from any Adamantium Securities issued. The Fortress Credit Agreement, the Adamantium Loan Agreement, and the Adamantium Secured Note will constitute Senior Debt and will rank contractually senior to the Notes. The Adamantium Secured Note will also be structurally senior to the Notes to the extent of the value of Adamantium’s assets, including the collateral securing the Adamantium Loan Agreement. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Adamantium Debt” for more information regarding the Adamantium Loan Agreement and Adamantium Secured Note. | ||
| As of March 31, 2025, we had $156.0 million aggregate principal amount outstanding of Adamantium Bonds pursuant to an offering under Rule 506(c) of Regulation D promulgated under the Securities Act (“Regulation D”) that commenced in September 2023 with maturity dates ranging from five to eleven years from the issue date and interest rates ranging from 13.0% to 16.0% per annum. The Adamantium Bonds will be structurally senior to the Notes to the extent of the value of Adamantium’s assets, including the collateral securing the Adamantium Loan Agreement. Adamantium may, but is not guaranteed to, issue $400.0 million in aggregate principal amount of Adamantium Bonds to fund advances to the Issuer and PhoenixOp pursuant to the Adamantium Loan Agreement. The Adamantium Bonds will also constitute Senior Debt and will rank contractually senior to the Notes. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Adamantium Debt” for more information regarding the Adamantium Bonds. | ||
| As of March 31, 2025, we had $671.2 million aggregate principal amount outstanding of bonds issued pursuant to Regulation D or Regulation A, consisting of: (i) $0.9 million aggregate principal amount outstanding of unsecured bonds offered and sold pursuant to an offering under Rule 506(b) of Regulation D that commenced in July 2020 and terminated in September 2021, with initial maturity dates ranging from one to four years from the issue date and an interest rate of 5.0% per annum (the “2020 506(b) Bonds”); (ii) $1.4 million aggregate principal amount outstanding of unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in October 2020 and terminated in July 2022, with maturity dates ranging from one to four years from the issue date and interest rates ranging from 13.0% to 15.0% per annum (the “2020 506(c) Bonds”); (iii) $10.1 million aggregate principal amount outstanding of unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in July 2022 and terminated in December 2022, with a maturity date of five years from the issue date and an interest rate of 11.0% per annum (the “July 2022 506(c) Bonds” and, together with the 2020 506(b) Bonds and the 2020 506(c) Bonds, the “Senior Reg D Bonds”); (iv) $65.9 million aggregate principal amount outstanding of Series AAA through Series D-1 Bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in December 2022 and terminated in August 2023, with maturity dates ranging from nine months to seven years from the issue date and interest rates ranging from 8.0% to 12.0% per annum (the “December 2022 506(c) Bonds”); (v) $493.3 million aggregate principal | ||
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| amount outstanding of Series U through Series JJ-1 Bonds offered pursuant to an offering under Rule 506(c) of Regulation D that commenced in August 2023 and are being offered on a continuous basis, with maturity dates ranging from one to eleven years from the issue date and interest rates ranging from 9.0% to 14.0% per annum (the “August 2023 506(c) Bonds” and, together with the December 2022 506(c) Bonds, the “Subordinated Reg D Bonds” and, together with the Senior Reg D Bonds, the “Reg D Bonds”); and (vi) $99.6 million aggregate principal amount outstanding of unsecured bonds offered and sold pursuant to an offering under Regulation A, which offering commenced in December 2021 and terminated in December 2024, with a term of three years and an interest rate of 9.0% per annum (the “Reg A Bonds” and, collectively with the Reg D Bonds, the “Reg D/Reg A Bonds”). The Reg D/Reg A Bonds that are not Subordinated Reg D Bonds (the “Senior Reg D/Reg A Bonds”) will constitute Senior Debt and will be contractually senior to the Notes. The Subordinated Reg D Bonds are contractually subordinated to the Senior Reg D/Reg A Bonds and will be contractually subordinated to the Notes. | ||
| See “Prospectus Summary—Company Structure” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness” for more information regarding our outstanding debt for borrowed money. See “Risk Factors—Risks Related to the Notes and this Offering—Your right to receive payment under the Notes is contractually subordinated to Senior Debt,” “Risk Factors—Risks Related to the Notes and this Offering—The Notes are the Issuer’s obligations alone, and will be structurally subordinated to all obligations of the Issuer’s existing and future subsidiaries,” and “Description of Notes—Ranking.” | ||
| Further Issuances | The Indenture will not limit the amount of other indebtedness that we or our subsidiaries may incur. Such indebtedness may be secured indebtedness, be Senior Debt, or otherwise rank senior to the Notes. We reserve the right, from time to time and without the consent of any holders of the Notes, to re-open any series of the Notes on terms identical in all respects to the outstanding Notes of such series (except for the date of issuance, the date interest begins to accrue, and, in certain circumstances, the first interest payment date), so that such additional Notes will be consolidated with, form a single series with, and increase the aggregate principal amount of the Notes of such series. See “Risk Factors—Risks Related to the Notes and this Offering.” | |
| Optional Redemption | The Notes will be redeemable at our option, in whole or in part, at any time and from time to time, at a redemption price equal to the principal amount of such Notes, plus accrued and unpaid interest, if any, to, but excluding, the date of the redemption. See “Description of Notes—Optional Redemption.” | |
| Mandatory Redemption | Subject to the provisions described in “Description of Notes—Subordination,” a holder may require us, at any time and from time to time prior to maturity, to redeem its Notes at a price equal to 95% of the aggregate principal amount of such Notes plus accrued and unpaid interest to, but excluding, the date of redemption, subject to certain exceptions and to an annual cap on all such redemptions of 10% of the aggregate principal amount of all Notes issued and then outstanding, subject to certain limitations. Each tranche of Reg D/Reg A Bonds (except the 2020 506(b) Bonds and the 2020 506(c) Bonds, which do not have a mandatory redemption right) and Adamantium Securities has a similar mandatory redemption right, and amounts redeemed under such debt will not count towards the 10% Limit under the Notes. Furthermore, the principal amount of any Notes requested for redemption by, and redeemed from, our manager, executive officers, or their respective family members during any calendar year will not be included in calculating the 10% Limit with respect to any other holders for such calendar year; however, such redemptions will be included in calculating the 10% Limit with respect to our manager, executive officers, and their respective family members. We may not, however, be able to pay you the required price for Notes you present to us at the time of a mandatory redemption because:
• we may not have enough funds at that time; or
• the terms of our indebtedness may prevent us from making such payment.
Redemption requests for the Notes will be processed in the order they are received by the Issuer without regard to date of issuance, maturity date, interest payment method, or interest rates of the Notes for which redemption has been requested. Except as set out in the preceding sentence with respect to redemption requests for the Notes relative to other redemption requests for the Notes, we intend to process redemption requests for any holder of our debt securities, regardless of which tranche of debt such holder holds, in the order in which such request is received, and do not intend to prioritize redemption requests under the Reg D/Reg A Bonds or the Adamantium Securities over redemption requests under the Notes, or vice versa; however, we are not obligated to do so and may, in the future, determine to honor redemption requests as among the tranches of our debt securities under different criteria, whether prioritizing near-term maturities, higher interest rates, specific interest payment methods, or otherwise. Any such determination will be made in our sole discretion. As a result, redemption requests for the Notes may receive lower priority as compared to redemption requests for our other debt securities. See “Risk Factors—Risks Related to the Notes and this Offering—Your right to receive payment under the Notes is contractually subordinated to Senior Debt” and “Risk Factors—Risks Related to the Notes and this Offering—Holders of Notes will have a limited right to require us to redeem their notes, and we may not be able to repurchase such Notes when requested.”
We will not otherwise be required to make any mandatory redemption or sinking fund payments with respect to the Notes. We will also not be required to offer to purchase any Notes with the proceeds of asset sales, in the event of a change of control, or otherwise. See “Risk Factors—Risks Related to the Notes and this Offering” and “Description of Notes—Mandatory Redemption; Repurchase at the Option of the Holders.” | |
| Covenants | We will issue the Notes under the Indenture, which will contain a covenant limiting our ability to sell all or substantially all of our assets or merge or consolidate with or into other companies. This covenant is subject to a number of important limitations and exceptions, and in many circumstances may not significantly restrict our or our subsidiaries’ ability to take the actions described above. For more details, see “Description of Notes—Covenants.” | |
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| The terms of the Notes and the Indenture do not otherwise contain financial maintenance covenants or covenants that limit the ability of the Issuer or any of its subsidiaries or affiliates to take actions that may negatively impact your investment, such as incurring indebtedness; paying dividends or making other distributions in respect of, or repurchasing or redeeming, capital stock; prepaying, redeeming, or repurchasing indebtedness; issuing preferred stock or similar equity securities; making loans and investments; selling or otherwise disposing of assets; incurring liens; entering into transactions with affiliates; or entering into agreements restricting subsidiaries’ ability to pay dividends. See “Risk Factors—Risks Related to the Notes and this Offering.” | ||
| Events of Default | Under certain circumstances set forth in the Indenture, in connection with an “Event of Default” (as defined below), our obligations under the Notes may be accelerated. Subject to certain exceptions, an Event of Default under the Indenture will constitute (1) a continuing default in the payment of principal or interest on the Notes that is not cured for 60 days, (2) a continuing failure to comply in any material respect with other provisions of the Notes or the Indenture if such failure is not cured or waived within 120 days after receipt of notice, or (3) certain events of bankruptcy or insolvency. See “Description of Notes—Events of Default” for more information. | |
| Use of Proceeds | We estimate that the net proceeds we will receive from this offering will be approximately $734.4 million if we issue and sell the $750.0 million aggregate principal amount of Notes offered pursuant to this prospectus. | |
| We plan to use substantially all of the net proceeds from this offering (i) to make investments in PhoenixOp or to otherwise finance potential drilling and exploration operations, (ii) to purchase mineral rights and non-operated working interests, as well as for additional asset acquisitions, and (iii) for other working capital needs. See “Use of Proceeds” for additional information. | ||
| Form and Denomination | The Notes will be issued in registered form only, on the books and records of the Issuer, in minimum denominations of $1,000. | |
| Transfer; Absence of a Public Market | Notes will be transferable by a holder only with our prior written consent, which we may provide at our sole discretion and determine on an ad hoc basis. See “Description of Notes—Transfer.” The Notes will be a new issue of securities for which there is currently no established public trading market or trading platform. The Notes will not be listed on any securities exchange or automated quotation system. Accordingly, there can be no assurance as to the development of a trading platform or the development or liquidity of any market for the Notes. Therefore, you must be prepared to hold your Notes to maturity. | |
| Plan of Distribution | This offering is being conducted directly by us, without any underwriter or placement agent. The Notes are offered continuously and we intend to close sales of Notes on a weekly basis as described in the section of this prospectus entitled “Plan of Distribution.” | |
| We have engaged Dalmore Group to perform administrative and compliance-related functions in connection with this offering. In connection with such functions, Dalmore Group will receive the Broker-Dealer Fee, which fee could total $5,025,000 if all Notes offered hereby are issued and sold, and certain sales commissions, all of which will be passed on to certain of our non-executive personnel who are licensed registered representatives of Dalmore Group and which fees could total $5,978,000 if all Notes offered hereby are issued and sold. See “Plan of Distribution” for more information, including regarding additional fees and expenses of Dalmore Group related to this offering. | ||
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| Financial Suitability | Investors must generally satisfy minimum financial suitability standards and maximum investment limits. Before purchasing Notes, each investor must represent and warrant that such investor meets the applicable minimum financial suitability standards and maximum investment limits and resides in an approved state. See “Plan of Distribution—Financial Suitability Requirements.” We will post on our website any special suitability standards or other conditions applicable to purchases of Notes in certain states that are not otherwise set forth in this prospectus as amended or supplemented from time to time. | |
| Trustee | UMB Bank, N.A. | |
| Registrar and Paying Agent | The Issuer will initially act as registrar and paying agent for the Notes. | |
| Governing Law | The Indenture and the Notes will be governed by the laws of the State of New York. | |
| Material Tax Considerations; Original Issue Discount | You should consult your tax advisors concerning the U.S. federal income tax consequences of investing in Notes in light of your own specific situation, as well as consequences arising under the laws of any other taxing jurisdiction. | |
| The Compound Interest Notes will (and Cash Interest Notes may) be treated as having been issued with original issue discount (“OID”) for U.S. federal income tax purposes. In the event a Note is issued with OID, a U.S. holder of such Note generally will be required to include OID in gross income (as ordinary income) on an annual basis under a constant yield accrual method, regardless of such U.S. holder’s regular method of accounting for U.S. federal income tax purposes. For more information, see “Certain Material U.S. Federal Income Tax Considerations.” | ||
| Risk Factors | Investing in the Notes involves significant risks. You should carefully read and consider the information beginning on page 19 of this prospectus under the heading “Risk Factors” and all other information in this prospectus or any amendment or supplement to this prospectus before deciding to invest in the Notes. | |
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SUMMARY HISTORICAL FINANCIAL AND OTHER DATA
The following table sets forth our summary historical financial and other data as of the dates and for the periods indicated. The balance sheet data as of December 31, 2024, 2023 and 2022 and the related statements of operations, members’ equity, and cash flows data for the years ended December 31, 2024, 2023 and 2022 have been derived from our audited consolidated financial statements included elsewhere in this prospectus. The summary historical financial and other data set forth below should be read in conjunction with the sections of this prospectus entitled “Risk Factors,” “Cautionary Statement Regarding Forward-Looking Statements,” “Capitalization,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” as well as our consolidated financial statements and the related notes included elsewhere in this prospectus.
Consolidated Statements of Operations Data:
| For the Years Ended December 31, | ||||||||||||
| 2024 | 2023 (As Restated) |
2022 (As Restated) |
||||||||||
| (in thousands) | ||||||||||||
| Revenues |
||||||||||||
| Mineral and royalty revenues |
$ | 152,999 | $ | 118,088 | $ | 54,554 | ||||||
| Product sales |
125,649 | — | — | |||||||||
| Water services |
2,478 | — | — | |||||||||
| Other revenue |
101 | 17 | — | |||||||||
|
|
|
|
|
|
|
|||||||
| Total revenues |
$ | 281,227 | $ | 118,105 | $ | 54,554 | ||||||
|
|
|
|
|
|
|
|||||||
| Operating expenses |
||||||||||||
| Cost of sales |
$ | 63,947 | $ | 19,733 | $ | 9,573 | ||||||
| Depreciation, depletion, amortization, and accretion |
85,977 | 34,228 | 12,144 | |||||||||
| Advertising and marketing |
679 | 4,136 | 1,353 | |||||||||
| Selling, general, and administrative |
29,167 | 14,314 | 5,563 | |||||||||
| Payroll and payroll-related expenses |
27,934 | 12,733 | 6,023 | |||||||||
| Loss on sale of assets |
564 | — | — | |||||||||
| Impairment expense |
564 | 974 | — | |||||||||
|
|
|
|
|
|
|
|||||||
| Total operating expenses |
$ | 208,832 | $ | 86,118 | $ | 34,656 | ||||||
|
|
|
|
|
|
|
|||||||
| Income from operations |
$ | 72,395 | $ | 31,987 | $ | 19,898 | ||||||
|
|
|
|
|
|
|
|||||||
| Other expenses |
||||||||||||
| Interest income |
$ | 705 | $ | 66 | $ | — | ||||||
| Interest expense |
(90,210 | ) | (47,882 | ) | (11,893 | ) | ||||||
| Gain (loss) on financial derivatives |
(5,986 | ) | (32 | ) | (2,239 | ) | ||||||
| Loss on debt extinguishment |
(1,697 | ) | (328 | ) | (92 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Total other expenses |
$ | (97,188 | ) | $ | (48,176 | ) | $ | (14,224 | ) | |||
|
|
|
|
|
|
|
|||||||
| Net income (loss) |
$ | (24,793 | ) | $ | (16,189 | ) | $ | 5,674 | ||||
|
|
|
|
|
|
|
|||||||
Consolidated Balance Sheets Data:
| As of December 31, | ||||||||||||
| 2024 | 2023 (As Restated) |
2022 (As Restated) |
||||||||||
| (in thousands) | ||||||||||||
| Cash and cash equivalents |
$ | 120,814 | $ | 5,428 | $ | 4,607 | ||||||
| Total current assets |
156,714 | 64,284 | 9,790 | |||||||||
| Net oil and gas properties |
865,845 | 423,668 | 144,755 | |||||||||
| Total assets |
1,029,070 | 493,167 | 157,020 | |||||||||
| Total current liabilities |
226,611 | 183,771 | 81,233 | |||||||||
| Long-term debt, net of current portion |
795,215 | 295,167 | 59,481 | |||||||||
| Total liabilities |
1,063,128 | 498,001 | 148,347 | |||||||||
| Members’ equity (deficit) |
(34,058 | ) | (4,834 | ) | 8,673 | |||||||
Consolidated Statements of Cash Flow Data:
| For the Years Ended December 31, | ||||||||||||
| 2024 | 2023 (As Restated) |
2022 (As Restated) |
||||||||||
| (in thousands) | ||||||||||||
| Net cash provided by (used in): |
||||||||||||
| Operating activities |
$ | 95,239 | $ | (1,826 | ) | $ | 18,642 | |||||
| Investing activities |
(437,703 | ) | (278,661 | ) | (91,888 | ) | ||||||
| Financing activities |
457,850 | 281,308 | 77,493 | |||||||||
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Other Financial and Operating Data:
| For the Years Ended December 31, | ||||||||||||
| 2024 | 2023 (As Restated) |
2022 (As Restated) |
||||||||||
| (in thousands) | ||||||||||||
| PV-10 (estimated proved developed reserves)(1) |
$ | 644,098 | $ | 289,809 | $ | 189,885 | ||||||
| PV-10 (estimated proved undeveloped reserves)(1) |
424,595 | 257,472 | — | |||||||||
| PV-10 (estimated total proved reserves)(1) |
1,068,692 | 547,281 | 189,885 | |||||||||
| EBITDA(2) |
150,689 | 65,855 | 29,711 | |||||||||
| (1) | PV-10 differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure, because it is calculated on a pre-tax basis. |
Because the Issuer is a limited liability company and has currently elected to be treated as a partnership for income tax purposes, the pro rata share of taxable income or loss is included in the individual income tax returns of members based on their percentage of ownership. Consequently, no provision for income taxes is made in our standardized measure of discounted future net cash flows, and so currently our PV-10 is identical to the standardized measure of discounted future net cash flows.
PV-10 is not a substitute for the standardized measure of discounted future net cash flows. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our oil and natural gas reserves. See “Non-GAAP Financial Measures.”
The following table includes a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, the most directly comparable financial measure calculated and presented in accordance with GAAP, for the periods presented:
| For the Years Ended December 31, | ||||||||||||
| 2024 | 2023 | 2022 | ||||||||||
| (in thousands) | ||||||||||||
| Estimated proved developed reserves: |
||||||||||||
| Standardized measure of discounted future net cash flows |
$ | 644,098 | $ | 289,809 | $ | 189,885 | ||||||
| Discounted future income taxes |
— | — | — | |||||||||
| PV-10 |
$ | 644,098 | $ | 289,809 | $ | 189,885 | ||||||
| Estimated proved undeveloped reserves: |
||||||||||||
| Standardized measure of discounted future net cash flows |
$ | 424,595 | $ | 257,472 | $ | — | ||||||
| Discounted future income taxes |
— | — | — | |||||||||
| PV-10 |
$ | 424,595 | $ | 257,472 | $ | — | ||||||
| Estimated total proved reserves: |
||||||||||||
| Standardized measure of discounted future net cash flows |
$ | 1,068,692 | $ | 547,281 | $ | 189,885 | ||||||
| Discounted future income taxes |
— | — | — | |||||||||
| PV-10 |
$ | 1,068,692 | $ | 547,281 | $ | 189,885 | ||||||
| (2) | EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income (loss), the most directly comparable GAAP measure. In particular, EBITDA excludes certain material costs, such as interest expense, and certain non-cash charges, such as depreciation, depletion, amortization, and accretion expense, that have been necessary elements of our expenses. Because EBITDA does not account for these expenses, its utility as a measure of our operating performance has material limitations. Other companies may not publish this or similar metrics, and our computation of EBITDA may differ from computations of similarly titled measures of other companies. Therefore, our EBITDA should be considered in addition to, and not as a substitute for, in isolation from, or superior to, our financial information prepared in accordance with GAAP, and should be read in conjunction with our consolidated financial statements and the related notes included elsewhere in this prospectus. See “Non-GAAP Financial Measures.” |
The following table includes a reconciliation of EBITDA to net income (loss), the most directly comparable financial measure calculated and presented in accordance with GAAP, for the periods presented:
| For the Years Ended December 31, | ||||||||||||
| 2024 | 2023 (As Restated) |
2022 (As Restated) |
||||||||||
| (in thousands) | ||||||||||||
| Net income (loss) |
$ | (24,793 | ) | $ | (16,189 | ) | $ | 5,674 | ||||
| Interest Income |
(705 | ) | (66 | ) | — | |||||||
| Interest expense |
90,210 | 47,882 | 11,893 | |||||||||
| Depreciation, depletion, amortization, and accretion expense |
85,977 | 34,228 | 12,144 | |||||||||
|
|
|
|
|
|
|
|||||||
| EBITDA |
$ | 150,689 | $ | 65,855 | $ | 29,711 | ||||||
|
|
|
|
|
|
|
|||||||
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Summary of Reserve, Production, and Operating Data
Summary of Reserves
The following table presents our estimated proved and probable oil, natural gas, and NGL reserves as of each of the dates indicated:
| As of December 31, | ||||||||||||
| 2024(1)(2) | 2023(2)(3) | 2022(4) | ||||||||||
| Estimated proved developed reserves |
||||||||||||
| Oil (Bbl) |
18,624,758 | 7,124,194 | 3,691,722 | |||||||||
| Natural gas (Mcf) |
20,819,874 | 12,250,285 | 7,624,212 | |||||||||
| Natural gas liquids (Bbl) |
2,848,355 | 1,514,761 | — | |||||||||
| Total (Boe)(6:1)(5) |
24,943,093 | 10,680,669 | 4,962,424 | |||||||||
| Estimated proved undeveloped reserves |
||||||||||||
| Oil (Bbl) |
31,197,795 | 24,925,841 | — | |||||||||
| Natural gas (Mcf) |
17,491,089 | 19,565,808 | — | |||||||||
| Natural gas liquids (Bbl) |
4,753,257 | 6,648,747 | — | |||||||||
| Total (Boe)(6:1)(5) |
38,866,233 | 34,835,556 | — | |||||||||
| Estimated proved reserves |
||||||||||||
| Oil (Bbl) |
49,822,554 | 32,050,035 | 3,691,722 | |||||||||
| Natural gas (Mcf) |
38,310,963 | 31,816,093 | 7,624,212 | |||||||||
| Natural gas liquids (Bbl) |
7,601,611 | 8,163,508 | — | |||||||||
| Total (Boe)(6:1)(5) |
63,809,326 | 45,516,225 | 4,962,424 | |||||||||
| Percent proved developed |
39 | % | 23 | % | 100 | % | ||||||
| Estimated probable undeveloped reserves |
||||||||||||
| Oil (Bbl) |
107,769,309 | 74,877,268 | — | |||||||||
| Natural gas (Mcf) |
134,083,603 | 88,184,111 | — | |||||||||
| Natural gas liquids (Bbl) |
— | — | — | |||||||||
| Total (Boe)(6:1)(5) |
130,116,577 | 89,574,620 | — | |||||||||
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| (1) | Estimates of reserves of oil and natural gas as of December 31, 2024 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2024, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $76.32 per Bbl for oil and $2.130 per MMBtu for natural gas at December 31, 2024. Estimates of reserves of NGL as of December 31, 2024 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2024 was $25.22 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. |
| (2) | In early 2023, we established PhoenixOp with the intention that certain leasehold held by us would be developed by PhoenixOp. PhoenixOp executed a contract for a drilling rig with Patterson-UTI Drilling Company on June 20, 2023. This allowed for previously unbooked reserves to be estimated and booked as proved undeveloped in accordance with SEC guidelines for reserves categorization and estimation and in adherence to the five-year rule as set forth by the SEC. |
| (3) | Estimates of reserves of oil and natural gas as of December 31, 2023 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2023, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $78.21 per Bbl for oil and $2.637 per MMBtu for natural gas at December 31, 2023. Estimates of reserves of NGL as of December 31, 2023 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2023 was $19.21 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. |
| (4) | Estimates of reserves of oil and natural gas as of December 31, 2022 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2022, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $94.14 per Bbl for oil and $6.357 per MMBtu for natural gas at December 31, 2022. We had no NGL reserves as December 31, 2022 and, as such, no NGL price was calculated as of December 31, 2022. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. |
| (5) | Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of “oil equivalent.” This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the 12-month average prices for the period ended December 31, 2024 was used, the conversion factor would be approximately 35.8 Mcf per Bbl of oil. |
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Select Production and Operating Statistics
The following table presents information regarding our production of oil, natural gas, and NGL and certain price and cost information for each of the periods indicated:
| For the Years Ended December 31, | ||||||||||||
| 2024 | 2023 | 2022 | ||||||||||
| Production Data: |
||||||||||||
| Bakken |
||||||||||||
| Oil (Bbl) |
3,022,810 | 943,930 | 360,604 | |||||||||
| Natural gas (Mcf) |
1,301,782 | 1,123,859 | 522,523 | |||||||||
| Natural gas liquids (Bbl) |
270,219 | 88,762 | — | |||||||||
| Total (Boe)(6:1)(1) |
3,509,992 | 1,220,003 | 447,691 | |||||||||
| Average daily production (Boe/d)(6:1) |
9,590 | 3,342 | 1,227 | |||||||||
| All Properties |
||||||||||||
| Oil (Bbl) |
3,830,461 | 1,446,928 | 523,416 | |||||||||
| Natural gas (Mcf) |
2,979,341 | 2,152,939 | 1,058,506 | |||||||||
| Natural gas liquids (Bbl) |
415,363 | 201,454 | — | |||||||||
| Total (Boe)(6:1)(1) |
4,742,381 | 2,007,205 | 699,834 | |||||||||
| Average daily production (Boe/d)(6:1) |
12,993 | 5,499 | 1,917 | |||||||||
| Average Realized Prices: |
||||||||||||
| Bakken |
||||||||||||
| Oil (Bbl) |
$ | 71.77 | $ | 71.43 | $ | 80.67 | ||||||
| Natural gas (Mcf) |
$ | 2.12 | $ | 3.47 | $ | 3.77 | ||||||
| Natural gas liquids (Bbl) |
$ | 23.53 | $ | 26.70 | $ | — | ||||||
| All Properties |
||||||||||||
| Oil (Bbl) |
$ | 68.49 | $ | 73.10 | $ | 91.01 | ||||||
| Natural gas (Mcf) |
$ | 1.86 | $ | 3.15 | $ | 6.66 | ||||||
| Natural gas liquids (Bbl) |
$ | 25.22 | $ | 27.50 | $ | — | ||||||
| Average Unit Cost per Boe (6:1): |
||||||||||||
| All Properties |
||||||||||||
| Operating costs, production and ad valorem taxes |
$ | 16.11 | $ | 16.18 | $ | 19.89 | ||||||
| Operating costs excluding taxes |
$ | 10.75 | $ | 10.86 | $ | 12.58 | ||||||
| Percentage of revenue |
26.4 | % | 16.7 | % | 21.9 | % | ||||||
| (1) | “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. |
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Investing in the Notes involves significant risks. Before making an investment decision, you should carefully consider the specific risk factors set forth below, together with the other information included elsewhere in this prospectus. If any of the risks discussed in this prospectus occur, our business, prospects, liquidity, financial condition, and results of operations could be materially impaired, in which case we may be unable to pay the principal of, and interest on, the Notes and you could lose all or part of your investment. Some statements in this prospectus, including statements in the following risk factors, constitute forward-looking statements. See “Cautionary Statement Regarding Forward-Looking Statements.”
Risks Related to Our Business and Operations
The businesses of direct drilling and extraction of minerals and acquisition of mineral rights are highly competitive. If we are unable to successfully compete within these businesses through our direct drilling operations conducted by PhoenixOp, we may not be able to identify and purchase attractive assets and successfully operate our properties.
The key areas in which we face competition include:
| • | acquisition of commercially viable mineral deposits offered for sale by other companies; |
| • | access to capital for financing and operational purposes; |
| • | hiring and retention of personnel to successfully operate drilling and extraction activities, and qualified third-party operators to assist in production activities; |
| • | purchasing, leasing, hiring, chartering, or other procuring of equipment by us and our third-party operators; and |
| • | employment of qualified and experienced management and other mineral professionals. |
Competition in our markets is intense and depends, among other things, on the number of competitors in the market, their financial resources, their degree of geological, geophysical, engineering, and management expertise and capabilities, their pricing policies, their ability to develop properties on time and on budget, their ability to select, acquire, and develop reserves, and their ability to foster and maintain relationships with the relevant authorities.
Our competitors include entities with greater technical, physical, and financial resources than we have. Furthermore, companies and certain private equity firms not previously investing in minerals and their extraction may choose to acquire reserves to establish a firm supply or simply as an investment. If we are unable to successfully compete in operating our wells or acquisition of attractive assets, we may not be able to achieve or maintain profitable operations.
The mineral rights investment business involves high-risk activities with many uncertainties.
Our and our operating partners’ activities relating to our mineral rights investment business are subject to many risks, including unanticipated problems relating to finding mineral rights assets and additional costs and expenses that may exceed current estimates. There can be no assurance that the expenditures we make in the exploration phase will result in the discovery of economic deposits of minerals, or that any investment we make in initially profitable assets will continue to be productive enough for associated revenues to be commercially viable. In addition, drilling and producing operations on the assets we invest in may be curtailed, delayed, or canceled by the operators of our properties as a result of various factors, including:
| • | declines in oil and natural gas prices; |
| • | infrastructure limitations, such as gas gathering and processing constraints; |
| • | the high cost, shortages, or delays in procurement of equipment, materials, and/or services; |
| • | unexpected operational events, adverse weather conditions and natural disasters, facility or equipment malfunctions, and equipment failures or accidents; |
| • | inability to obtain satisfactory title to the assets we acquire and other title-related issues; |
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| • | pipe or cement failures and casing collapses; |
| • | lost or damaged oilfield development and service tools; |
| • | compliance with environmental, health, safety, and other governmental requirements; |
| • | increases in severance taxes; |
| • | regulations, restrictions, moratoria, and bans on hydraulic fracturing; |
| • | unusual or unexpected geological formations, and pressure or irregularities in formations; |
| • | loss of drilling fluid circulation; |
| • | environmental hazards, such as oil, natural gas, or well fluids spills or releases, pipeline or tank ruptures, and discharges of toxic gases; |
| • | fires, blowouts, craterings, and explosions; |
| • | uncontrollable flows of oil, natural gas, or well fluids; |
| • | pipeline capacity curtailments; and |
| • | evolving cybersecurity risks, such as those involving unauthorized access, third-party provider defects and service failures, denial of service attacks, malicious software, data privacy breaches by employees, insiders, or others with authorized access, cyber or phishing attacks, ransomware, social engineering, physical breaches, or other actions. |
In addition to causing curtailments, delays, and cancellations of drilling and producing operations, many of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources, and equipment, pollution, environmental contamination, loss of wells, regulatory penalties, and third-party claims. The insurance we maintain against various losses and liabilities arising from our operations does not cover all operational risks involved in our investments. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition, and results of operations.
We, through our investment in PhoenixOp and future assignment of oil and gas properties to PhoenixOp, conduct direct drilling and extraction activities. Such activities pose additional risks to us.
We, through the operations of PhoenixOp, face numerous risks relating to our drilling activities, including:
| • | failing to place a well bore in the desired target producing zone; |
| • | not staying in the desired drilling zone while drilling horizontally through the formation; |
| • | failing to run casing the entire length of the well bore; and |
| • | not being able to run tools and other equipment consistently through the horizontal well bore. |
Risks we may face while completing our wells include, but are not limited to:
| • | not being able to fracture stimulate the planned number of stages; |
| • | failing to run tools the entire length of the well bore during completion operations; |
| • | not successfully cleaning out the well bore after completion of the final fracture stimulation stage; |
| • | increased seismicity in areas near our completion activities; |
| • | unintended interference of completion activities performed by us or by third parties with nearby operated or non-operated wells being drilled, completed, or producing; and |
| • | failure of our optimized completion techniques to yield expected levels of production. |
Further, many factors may occur that cause us to curtail, delay, or cancel scheduled drilling and completion projects, including, but not limited to:
| • | abnormal pressure or irregularities in geological formations; |
| • | shortages of or delays in obtaining equipment or qualified personnel; |
| • | shortages of or delays in obtaining components used in fracture stimulation processes, such as water and proppants; |
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| • | delays associated with suspending our operations to accommodate nearby drilling or completion operations being conducted by other operators; |
| • | mechanical difficulties, fires, explosions, equipment failures, or accidents, including ruptures of pipelines or storage facilities, or train derailments; |
| • | restrictions on the use of underground injection wells for disposing of wastewater from oil and gas activities; |
| • | political events, public protests, civil disturbances, terrorist acts, or cyber-attacks; |
| • | decreases in, or extended periods of low, crude oil and natural gas prices; |
| • | title problems; |
| • | environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas, or other pollutants into the environment, including groundwater and shoreline contamination; |
| • | adverse climatic conditions and natural disasters; |
| • | spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas, or other pollutants by us or by third-party service providers; |
| • | limitations in infrastructure, including transportation, processing, refining, and exportation capacity, or markets for crude oil and natural gas; and |
| • | delays imposed by or resulting from compliance with regulatory requirements, including permitting. |
As we expand our direct drilling and extraction activities the impact of these risks on our overall business will only grow more significant. See “—The businesses of direct drilling and extraction of minerals and acquisition of mineral rights are highly competitive. If we are unable to successfully compete within these businesses through our direct drilling operations conducted by PhoenixOp, we may not be able to identify and purchase attractive assets and successfully operate our properties,” “—Our business is sensitive to the price of oil and gas and sustained declines in prices may adversely affect our financial position, financial results, cash flows, access to capital, and ability to grow,” “—Properties we acquire for our direct drilling and extraction operations, currently conducted through PhoenixOp, may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with such properties, or obtain protection from sellers against such liabilities,” and “—Our development of successful operations relies extensively on our direct operations, through PhoenixOp and various third-party E&P operators, which could have a material adverse effect on our results of operations.”
We are not insured against all risks associated with our business. We and PhoenixOp may elect to not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented or for other reasons. In addition, some risks such as those stemming from certain environmental hazards are generally not fully insurable.
Losses and liabilities arising from any of the above events could reduce the value of our capital contributions to PhoenixOp, increase our need to provide additional capital to PhoenixOp, and otherwise harm our financial position, which could adversely affect us and our ability to pay our obligations under the Notes.
Our business is sensitive to the price of oil and gas and sustained declines in prices may adversely affect our financial position, financial results, cash flows, access to capital, and ability to grow.
We are in the business of both drilling and extracting oil and gas minerals directly through our operations conducted by PhoenixOp, and purchasing mineral rights and non-operated working interests in land in the United States, including the rights to drill for oil and gas. The prices we receive for our oil and natural gas production heavily influence our revenue, operating results, profitability, access to capital, future rate of growth, and carrying value of our properties. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand, as well as costs and terms of transport to downstream markets.
Historically, the commodities markets have been volatile, and these markets will likely continue to be volatile in the future. For example, in April 2025, oil prices dropped significantly, going from $71.20 per barrel as of April 1, 2025 to $58.21 per barrel as of April 30, 2025. A decline in oil and natural gas prices can have an adverse effect on the value of our interests in the land and revenue from our own direct drilling production, which will materially and adversely affect our ability to generate cash flows and, in turn, our ability to make interest and principal payments on the Notes.
The prices received for oil and natural gas produced on our land, and the levels of the production, depend on numerous factors beyond our control and include the following:
| • | changes in global supply and demand for oil and natural gas; |
| • | the actions of the Organization of the Petroleum Exporting Countries (“OPEC”); |
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| • | political and economic conditions and events in foreign oil, natural gas, and NGL producing countries, including elevated levels of inflation and interest rates, embargoes, and introduction of tariffs on oil and gas products; |
| • | the level of global and domestic oil and natural gas E&P activity and the degree to which consolidation among our customers may affect spending on U.S. drilling and completions in the near-term; |
| • | the level of global and domestic oil and natural gas inventories; |
| • | the level of consumer product demand; |
| • | inclement or hazardous weather conditions and natural disasters; |
| • | the availability of storage for hydrocarbons and technological advances affecting energy consumption and energy supply; |
| • | speculative trading in commodity markets, including expectations about future commodity prices; |
| • | the proximity of our production operations to, and capacity, availability, and cost of, pipelines and other transportation and storage facilities, and other factors that result in differentials to benchmark prices; |
| • | domestic, local, and foreign governmental regulation and taxes; |
| • | fuel and energy conservation measures and technological advances affecting energy consumption; |
| • | armed conflict, political instability, or civil unrest in oil and gas producing regions, including instability in the Middle East and the conflict between Russia and Ukraine, and the related potential effects on laws and regulations or the imposition of economic or trade sanctions; |
| • | changes in regulatory and trade policy, such as tariffs, as well as the potential for general market volatility and political uncertainty; |
| • | the occurrence or threat of epidemic or pandemic diseases, or any government response to such occurrence or threat; and |
| • | the price and availability of alternative fuels. |
These factors and the volatility of oil and natural gas prices make it extremely difficult to predict future crude oil, natural gas, and NGL price movements or to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Certain actions by OPEC and other oil producing nations in the first half of 2020, combined with the impact of the COVID-19 pandemic and a shortage in available storage for hydrocarbons in the United States, contributed to the historic low price for crude oil in April 2020. While the prices for crude oil have generally increased since then, such prices have historically remained volatile, which has adversely affected the prices at which production from our properties is sold, as well as the production activities of operators on our properties, and may continue to do so in the future. This, in turn, has and will materially affect the amount of royalty payments that we receive from our third-party E&P operators and our income from direct drilling operations. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects. In particular, our five-year development plan is based on assumed average oil and natural gas prices of $64.39 per barrel and $3.85 per MMBtu, respectively, and our outlook for 2025 is based on average benchmark commodity prices of $71.98 per barrel for crude oil and $3.94 per Mcf for natural gas, as compared to recent prices of $58.21 per barrel and $3.33 per MMBtu, respectively, as of April 30, 2025. This plan and outlook may need to be adjusted in the future as a result of any material sustained decrease in oil and natural gas prices as compared to our assumptions, which could have a material adverse effect on our business, financial condition, results of operations, and prospects. In addition, in response to a sustained decrease in oil and natural gas prices, we may determine to adjust our overall business plan by adjusting capital expenditures, decreasing drilling operations, and/or reducing production plans, among other actions. Such actions and circumstances would impact our revenue, operating expenses, and liquidity. For example, we may be required to raise additional capital, above our current expectations, in order to fully realize our current or adjusted business plan.
Our revenues, operating results, profitability, and future rate of growth depend primarily on the prices of oil and, to a lesser extent, natural gas that we sell. Any substantial decline in the price of crude oil, natural gas, and NGL or prolonged period of low commodity prices will materially adversely affect our business, financial condition, results of operations, and cash flows. Further, a slowdown in the timing of oil or natural gas production, especially if in connection with a decline in prices, may reduce our ability to collect lease payments from leaseholders, which could limit our ability to make interest and principal payments on the Notes. Prices also affect the amount of cash flow available for capital expenditures and our ability to raise additional capital. In addition, we may need to record asset carrying value write-downs if prices fall. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital, and ability to grow.
We have a limited operating history and have experienced periods of significant business growth in a short time, making it difficult for you to evaluate our business and prospects. If we are unable to manage our business and growth effectively, our business could be materially and adversely affected.
Since our formation in 2019, our business has grown considerably. Our limited operating history and the significant growth in operations and revenue we have experienced since then makes evaluation of our business and prospects difficult. Any growth that we experience in the future will require us to further expand our drilling and extraction activities and our acquisitions. There can be no assurance that growth in our revenue and operations will continue at a similar pace, or that we will be able to manage our growth effectively. Furthermore, the growth of our business places significant demands on our management, including managing increased numbers of personnel, properties, and business relations, such as our E&P operators. If we do not effectively manage the increased obligations brought by the growth of our operations, we may not be able to execute on our business plan, respond to competitive pressures, take advantage of market opportunities, or satisfy delivery requirements, which could have a material adverse effect on our business, financial condition, results of operations, and prospects.
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In addition, we may encounter risks and difficulties experienced by companies whose performance is dependent upon newly acquired assets, such as failing to integrate, or realizing the expected benefits of, such assets. As a result of the foregoing, we may be less successful in achieving consistent results and continue the growth of our business, as compared with companies that have longer operating histories and a more stable size of operations. In addition, we may be less equipped to identify and address risks and hazards in the conduct of our business than those companies that have longer operating histories.
The acquisition and development of our properties, directly or through our third-party E&P operators, will require substantial capital, and we and our third-party E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all, including as a result of increases in the cost of capital resulting from Federal Reserve policies in the past few years and otherwise.
The oil and gas industry is capital-intensive. We make, and will continue to make, substantial capital expenditures in connection with the acquisition of mineral and royalty interests. To date, we have financed capital expenditures primarily with funding from capital contributions, cash generated by operations, borrowings under credit facilities, and issuances of debt securities.
In the future, we may need capital in excess of the amounts we retain in our business, borrow under our existing credit facilities, or through issuances of debt securities. There can be no assurance that we can increase the borrowing amount available under our existing credit facilities or continue to raise sufficient funds through our debt securities issuances.
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, a significant decline in prices for oil and natural gas, rising interest rates, inflationary pressure, and broader economic turmoil may adversely impact our ability to secure financing in the capital markets on favorable terms. 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 financial condition.
Most of our third-party E&P 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 such E&P operators on favorable terms or at all, then we expect the development of our properties would be adversely affected. If the development of our properties is adversely affected, then revenues from our mineral and royalty interests may decline.
Properties we acquire for our direct drilling and extraction operations, currently conducted through PhoenixOp, may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with such properties, or obtain protection from sellers against such liabilities.
Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs, and potential liabilities, including, but not limited to, environmental liabilities. Such assessments are inexact and inherently uncertain. For these reasons, the properties we acquire may not produce as projected. In connection with these assessments we perform a review of the subject properties, but such a review may not reveal all existing or potential problems. While conducting due diligence, we may not review every well, pipeline, or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from any seller for liabilities arising from or attributable to the period prior to our purchase of the property. As a result, we may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
We may encounter obstacles to marketing our minerals, which could adversely impact our revenues and profits.
The marketability of our production will depend upon numerous factors beyond our control, including the availability and capacity of natural gas gathering systems, pipelines, and other transportation and processing facilities owned by third parties.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices, and the increased competitiveness of alternative energy sources could reduce demand for oil and natural gas. Additionally, the increased competitiveness of alternative energy sources (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells, and biofuels) could reduce demand for oil and natural gas and, therefore, our revenues.
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The marketing of our production can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation. The availability of markets for our production is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market mineral deposits.
If we have difficulty selling the minerals we discover, our profits may decline, and we may not be able to purchase other assets.
A limited number of operators currently generate a significant portion of our revenue and accounts receivable, and we may not have contracts or agreements directly with such operators.
A large portion of our current mineral rights and lease holdings are serviced by a limited number of third-party E&P operators and, as a result, we generate a significant portion of our revenue and accounts receivable from a limited number of third-party E&P operators. For the year ended December 31, 2024, one third-party E&P operator made up 21% of our consolidated revenue, as compared to one third-party E&P operator that made up 11% of our consolidated revenue for the year ended December 31, 2023, and four third-party E&P operators that made up 16%, 16%, 15%, and 14% of our consolidated revenue for the year ended December 31, 2022. Similarly, as of December 31, 2024, we had concentrations in accounts receivable of 17%, 15%, and 13% with three third-party E&P operators, as compared to 26% and 14% with two third-party E&P operators as of December 31, 2023, and 34% and 10% with two third-party E&P operators as of December 31, 2022. Our revenue and accounts receivable are generally derived from our diverse holdings of mineral rights and lease holdings and are generally not generated pursuant to agreements directly between us and the operators of the properties underlying our mineral rights and lease holdings. These interests generate revenue from the sale of crude oil and natural gas, which is paid monthly to us by various third-party oil and gas operators once any extracted crude oil and natural gas is delivered by such operators to purchasers. Those purchasers remit payment for production to the operators of the wells pursuant to sales agreements entered into among the purchasers and such operators, and the operators, in turn, remit payment to the owners in accordance with their ownership percentage in each well (or unit of wells). As is typical in the oil and gas industry, the third-party oil and gas operators generally remit payment to the interest owners pursuant to statute or orders from the oil and gas commission of the state in which the particular well (or unit of wells) is located. For example, the majority interest holders of a unit would petition to appoint a particular operator from the oil and gas commission of the state in which the unit is located (e.g., the Wyoming Oil and Gas Commission, North Dakota Industrial Commission, Texas Railroad Commission (the “Texas RRC”), Montana Board of Oil and Gas Conservation, and Utah Division of Oil, Gas and Mining, among others). If the request is granted by the commission, the operator would become the designated operator for the unit and would be required to remit payments to the interest holders of the unit pursuant to permits or pooling orders from such commission. While our revenue and accounts receivable relating to our mineral rights and lease holdings are derived from a significant number of different units that are subject to different leases and pooling orders from various state oil and gas commissions, the incapacity or loss of one of the operators that generate a significant portion of our revenue and accounts receivable could negatively impact our revenue and accounts receivable and could result in a reduction or delay in revenue generated from the related mineral rights and lease holdings while a replacement operator is selected and designated. Further, although typical in the oil and gas industry, as we do not always have contracts or agreements directly with these operators, we do not always determine or control the rights, payments, discounts, or other terms related to leases or the extraction and sale of assets from the properties underlying our mineral rights and lease holdings.
Our development of successful operations relies extensively on our direct operations, through PhoenixOp and various third-party E&P operators, which could have a material adverse effect on our results of operations.
A significant portion of our assets consist of mineral and royalty interests. We utilize and will continue to utilize third-party E&P operators to perform the drilling and extraction operations on our assets to extract the natural resources we rely on to generate revenue. The success of our business operations depends on the timing of drilling activities and success of our direct operations and third-party E&P operators. In each of the years ended December 31, 2024, 2023, and 2022, we received revenue from over 100 third-party E&P operators, with approximately 35% of our consolidated revenue coming from the top ten third-party E&P operators in 2024, approximately 60% of our consolidated revenue coming from the top nine third-party E&P operators in 2023, and approximately 61% of our consolidated revenue coming from the top four third-party E&P operators in 2022. If we or our third-party E&P operators are not successful in the development, exploitation, production, and exploration activities relating to our ownership interests, or are unable or unwilling to perform, our financial condition and results of operation would be materially adversely affected.
With respect to our investments in which we have a non-operated working interest, third-party E&P operators will make decisions in connection with their operations, which may not be in our best interests. We may have no ability to exercise influence over the operational decisions of our third-party E&P operators, including the setting of capital expenditure budgets and drilling locations and schedules. Dependence on our unaffiliated E&P operators could prevent us from realizing target returns for those locations. The success and timing of development activities by our operators will depend on several factors that are largely outside of our control, including: the capital costs required for drilling activities by our E&P operators, which could be significantly more than anticipated; the ability of our operators to access capital; prevailing mineral prices and other factors generally affecting the industry operating environment; the timing of capital expenditures; their expertise and financial resources; approval of other participants in drilling wells; selection of drilling technology; the availability of storage for hydrocarbons; and the rate of production of reserves, if any.
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Furthermore, our E&P operators are dependent on various supplies and equipment, as well as qualified personnel, to carry out our extraction operations. Any shortage, unavailability, or increase in the cost of such supplies, personnel, equipment, and parts could have a material adverse effect on their ability to carry out operations and therefore limit or increase the cost of production and, ultimately, our profitability.
The challenges and risks faced by our third-party E&P operators and contractors may be similar to or greater than our own, including with respect to their ability to service their debt, remain in compliance with their debt instruments, and, if necessary, access additional capital. Commodity prices and/or other conditions have in the past caused, and may in the future cause, mineral operators to file for bankruptcy. The insolvency of third-party E&P operators or contractors of any of our properties, their failure to adequately perform, or their breach of applicable agreements could reduce our production and revenue or result in our liability to governmental authorities for compliance with environmental, safety, and other regulatory requirements or to such operators’ suppliers and vendors. Finally, with regards to any third-party E&P operator, they may have the right, if another non-operator fails to pay its share of costs because of its insolvency or otherwise, to require us to pay its proportionate share of the defaulting party’s share of costs.
We rely on our E&P 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 and royalty interests, we rely on the E&P operators of our properties to notify us and state regulators 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 in conjunction with our specialized software to evaluate operations and cash flows, as well as to predict expected production and possible future locations. To the extent we do not timely receive this information or the information is incomplete or incorrect, our financial and operational information 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. If any of such third-parties’ 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 materially adversely affect our business.
Our estimated mineral reserves quantities and future production rates are based on many assumptions that may prove to be inaccurate and they have not been verified by an independent third-party reserve engineering report. Any material inaccuracies in the reserves estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.
It is not possible to measure underground accumulation of crude oil, natural gas, or NGL in an exact way. Numerous uncertainties are inherent in estimating quantities of mineral reserves. The process of estimating mineral reserves is complex, requiring significant expertise, decisions, and assumptions in the evaluation of available geological, engineering, and economic data for each reservoir, including assumptions regarding future natural gas and oil prices, subsurface characterization, production levels, and operating and development costs. For example, our estimates of our reserves are based on the unweighted first-day-of-the-month arithmetic average commodity prices over the prior 12 months in accordance with SEC guidelines. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of those estimates. Sustained lower prices will cause the 12-month unweighted arithmetic average of the first-day-of-the-month price for each of the 12 months preceding to decrease over time as the lower prices are reflected in the average price, which may result in the estimated quantities and present values of our reserves being reduced. To the extent that prices become depressed or decline materially from current levels, such conditions could render uneconomic a portion of our proved and probable reserves, and we may be required to write down our proved and probable reserves.
Additionally, we do not have an independent third-party reserve engineering report that verifies our estimates of mineral reserves quantities. We rely on our own internal team to estimate our mineral reserves, only employing third parties in limited capacities to assess the reasonableness and appropriateness of our approach and methodology to estimate our reserves. Lack of an independent third-party reserve engineering report means there is no independent complete analysis of the accuracy of mineral reserve estimates and their present value.
Furthermore, SEC rules require that, subject to limited exceptions, proved and probable undeveloped reserves may only be recorded if they relate to wells scheduled to be drilled within five years after the date of booking. This rule may limit our potential to record additional proved and probable undeveloped reserves as we pursue our drilling program through PhoenixOp. To the extent that prices become depressed or decline materially from current levels, such condition could render uneconomic a number of our identified drilling locations, and we may be required to write down our proved and probable undeveloped reserves if we do not drill those wells within the required five-year time frame or choose not to develop those wells at all.
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As a result, estimated quantities of reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to our reserves estimates. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of minerals attributable to any particular group of properties, the classifications of reserves based on risk of non-recovery, and estimates of future net cash flows.
In addition, estimates of probable reserves, and the future cash flows related to such estimates, are inherently imprecise and are more uncertain than estimates of proved reserves, and the future cash flows related to such estimates, but have not been adjusted for risk due to that uncertainty. Because of such uncertainty, estimates of probable reserves, and the future cash flows related to such estimates, may not be comparable to estimates of proved reserves, and the future cash flows related to such estimates, and should not be summed arithmetically with estimates of proved reserves and the future cash flows related to such estimates. When producing an estimate of the amount of minerals that are recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration, and development, price changes, and other factors. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves. See “Business—Our Oil and Natural Gas Properties—Evaluation and Review of Estimated Proved and Probable Reserves.”
The development of our estimated proved and probable undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
Recovery of proved and probable undeveloped reserves requires significant capital expenditures and successful drilling operations. As of December 31, 2024, approximately 61% of our total estimated proved reserves and 100% of our total estimated probable reserves were undeveloped. Furthermore, as of December 31, 2024, we had 130.1 million Boe in total estimated probable undeveloped reserves, which is approximately 2.0 times our total proved reserves. Our reserves estimates assume that substantial capital expenditures will be made to develop non-producing reserves. As of December 31, 2024, we estimate that we will need to make approximately $749.3 million and $3,224.8 million in capital expenditures to develop all our proved and probable undeveloped reserves, respectively. Estimates of capital expenditures are subject to fluctuations in oil and natural gas prices, equipment availability, labor markets, and other factors that we may not foresee or control. As such, we cannot be sure that the estimated costs attributable to our reserves are accurate.
We anticipate that over the next several years our cash flows from operations alone will not be sufficient to finance the development of our estimated proved and probable undeveloped reserves over that period. As a result, we expect that we will need to raise additional capital to develop our reserves. However, we cannot be certain that additional financing will be available to us on acceptable terms, or at all. See “—The acquisition and development of our properties, directly or through our third-party E&P operators, will require substantial capital, and we and our third-party E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all, including as a result of increases in the cost of capital resulting from Federal Reserve policies in the past few years and otherwise.” Additionally, sustained or further declines in commodity prices may require use to revise the future net revenues of our estimated proved and probable undeveloped reserves and may result in some projects becoming uneconomical. Further, our drilling efforts may be delayed or unsuccessful and actual reserves may prove to be less than current reserves estimates, which could have a material adverse effect on our financial condition, future cash flows, and results of operations.
The ability to develop our reserves is subject to a number of uncertainties, which could defer our drilling more than five years from the date undeveloped reserves were first assigned to a drilling location. Alternatively, our estimated reserves may not be ultimately developed or produced. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to remove the associated volumes from our reported proved reserves. In addition, because
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undeveloped reserves may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any undeveloped reserves that are not developed within this five-year time frame or to reclassify the category of the applicable reserves. A removal or reclassification of reserves could reduce the quantity and present value of our natural gas and oil reserves, which would adversely affect our business and financial condition.
We may experience delays in the payment of royalties and be unable to replace third-party E&P operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of such E&P operators on those leases declare bankruptcy.
We may experience delays in receiving royalty payments from our E&P operators, including as a result of delayed division orders received by our E&P operators. A failure on the part of the E&P 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 E&P operator. However, we might not be able to find a replacement E&P 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. In addition, the outgoing E&P operator could be subject to a proceeding under Title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt E&P operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another E&P operator. For example, certain of our E&P operators historically have undergone restructurings under the Bankruptcy Code and any future restructurings of our E&P operators may impact their future operations and ability to make royalty payments to us. If the E&P operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new E&P operator, the replacement E&P operator may not achieve the same levels of production or sell oil or natural gas at the same price as the E&P operator we replaced.
Our PV-10 will not necessarily be the same as the current market value of our estimated proved reserves.
You should not assume that our PV-10 is the current market value of our estimated proved reserves. We currently base the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months. Actual future net revenues from our reserves will be affected by factors such as:
| • | actual prices we receive for natural gas and oil; |
| • | actual cost of development and production expenditures; |
| • | the amount and timing of actual production; |
| • | transportation and processing; and |
| • | changes in governmental regulations or taxation. |
The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing and amount of actual future net revenues from proved reserves and, thus, their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our business or the natural gas and oil industry in general. Actual future prices and costs may differ materially from those used in the present value estimate.
Estimated reserves do not represent or measure the fair value of the respective property or asset and we may sell or divest an asset for much less than the amount of estimated reserves.
Estimated proved reserves and estimated probable reserves do not represent or measure the fair value of the respective properties or the fair market value at which a property or properties could be sold. In the event of any such sale, proceeds to us may be significantly less than the value of the estimated reserves. The development of our estimated proved and probable undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Estimates of probable reserves, and the future cash flows related to such estimates, are inherently imprecise and are more uncertain than estimates of proved reserves and the future cash flows related to such estimates but have not been adjusted for risk due to such uncertainty.
Our future success depends on our ability to replace reserves.
Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that
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we acquire additional properties containing proved reserves, conduct successful exploration and development activities, or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as our reserves are produced. Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost. We may acquire significant amounts of unproved property to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We seek to acquire both proved and producing properties as well as undeveloped acreage that we believe will enhance growth potential and increase our earnings over time. However, we cannot assure you that all of these properties will contain economically viable reserves or that we will not abandon our initial investments. Additionally, we cannot assure you that unproved reserves or undeveloped acreage that we acquire will be profitably developed, that new wells drilled on our properties will be productive, or that we will recover all or any portion of our investments in our properties and reserves.
We rely on our software system to identify attractive assets with oil and gas reserves and there can be no assurance that we will be able to continue to scale this software or that such software will be accurate in identifying assets.
As of the date of this prospectus, we have built and operated our software system on a relatively limited scale. While we believe that our development and testing to date has proven the concept of our software, there can be no assurance that, as we commence larger-scale operations, we will not incur unexpected costs or hurdles that might restrict the desired scale of our intended operations or negatively impact our business prospects, financial condition, and results of operation. In addition, due to the limited and changing scale of use, there can be no assurance that the software will be accurate on an ongoing or continuous basis. If our software is unable to scale or to adopt to the changing nature of our operations, or is inaccurate, our ability to successfully invest in commercially viable mineral deposits and PhoenixOp’s ability to successfully extract minerals from assets transferred to it by us could be significantly impacted and our business and operating results may suffer.
We may be unable to realize all of the anticipated benefits from our acquisitions or successfully integrate future acquisitions of mineral rights into our business.
Our ability to achieve the anticipated benefits of our completed and future acquisitions of mineral rights will depend in part upon whether we can integrate the acquired assets into our existing business in an efficient and effective manner. We may not be able to accomplish this integration process successfully. The successful acquisition of producing properties requires an assessment of several factors, including:
| • | recoverable reserves; |
| • | future oil and natural gas prices and their appropriate differentials; |
| • | availability and cost of transportation of production to markets; |
| • | availability and cost of drilling equipment and of skilled personnel for our third-party operators; |
| • | development and operating costs of PhoenixOp and our third-party E&P operators, including potential environmental and other liabilities; and |
| • | regulatory, permitting, and similar matters. |
The accuracy of these assessments is inherently uncertain, and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, in conjunction with the use of our specialized software, we perform a review of the subject properties that we believe to be generally consistent with industry practices, given the nature of our interests. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of such problems. Even if we identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. We depend on acquisitions to grow our reserves, production, and cash flows.
There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Additionally, acquisition opportunities vary over time. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain the necessary financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently hold assets, which could result in unforeseen difficulties. In addition, if we acquire interests in new geographic regions, we may be subject to additional and unfamiliar legal and regulatory requirements. Moreover, the success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing business. The process of integrating acquired businesses may involve unforeseen difficulties, including delays, and may require a disproportionate amount of our managerial and financial resources.
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No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or successfully acquire identified targets. Our failure to successfully integrate the acquired assets into our existing operations, achieve cost savings, or minimize any unforeseen difficulties could materially and adversely affect our financial condition, results of operations, and cash flows. The inability to effectively manage these acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations, and cash flows.
Our E&P operators’ identified potential drilling locations, which are scheduled out over many years, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Proved and probable undeveloped drilling locations represent a significant part of our growth strategy. However, we do not fully control the development of these locations that we do not directly operate. The ability of our third-party E&P 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, the generation of additional seismic or geological information, seasonal conditions and inclement weather, regulatory changes and approvals, oil and gas prices, costs, negotiation of agreements with third parties, drilling results, lease expirations, and the availability of water. Further, our E&P 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 E&P operators, or us, to know conclusively prior to drilling whether mineral reserves will be present or, if present, whether such resources will be present in sufficient quantities to be economically viable. Even if sufficient amounts of such resources exist, our E&P 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 E&P 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 and ours.
There is no guarantee that the conclusions our E&P 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 E&P 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. For example, several E&P operators have previously announced that newer wells drilled close in proximity to already producing wells have produced less oil and gas than forecast. Because of these uncertainties, we do not know if the potential drilling locations identified will ever be drilled or if our E&P operators will be able to produce oil and/or gas from these or any other potential drilling locations. As such, the actual drilling activities of our E&P operators may materially differ from those presently identified, which could adversely affect our business, results of operations, 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 through our specialized software. As a result, our E&P operators may have reached different conclusions about the potential drilling locations on our properties, and our E&P operators control the ultimate decision as to where and when a well is drilled.
Acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. Our E&P operators’ failure to drill sufficient wells to hold acreage may result in the deferral of prospective drilling opportunities.
Leases on crude oil and natural gas properties typically have a term of three 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 E&P 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.
We have limited control over the activities on properties that we do not operate.
Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety, and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third- party E&P operator could decide to shut-in or curtail
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production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of decreases in oil and gas prices. These limitations and our dependence on the E&P operators and third-party working interest owners for these projects could cause us to incur unexpected future costs, lower production, and materially and adversely affect our financial condition, results of operations, and cash flows.
We have completed numerous acquisitions of mineral and royalty interests for which separate financial information is not required or provided.
We have completed numerous acquisitions of mineral and royalty interests that are not “significant” under Rule 3-05 of Regulation S-X (“Rule 3-05”). Therefore, we are not required to, and have elected not to, provide separate historical financial information in our public filings relating to those acquisitions. While these acquisitions are not individually or collectively significant for purposes of Rule 3-05, they have or will have an impact on our financial results and their aggregated effect on our business and results of operations may be material.
The substantial majority of the wells in which we have a mineral or royalty interest and all the wells we directly operate are located in the Williston Basin, making us vulnerable to risks associated with concentration of our assets in a limited geographic area.
The substantial majority of the wells in which we have a mineral or royalty interest and all the wells we directly operate are geographically concentrated in the Williston Basin. As a result, we may be disproportionately exposed to various factors, including, among others:
| • | the impact of regional supply and demand factors; |
| • | delays or interruptions of production from wells in such areas caused by governmental regulation, including changes to field wide rules; |
| • | processing or transportation capacity constraints; |
| • | market limitations; |
| • | availability of equipment and personnel; |
| • | water shortages or other drought-related conditions; or |
| • | interruption of the processing or transportation of natural gas. |
This concentration in a limited geographic area also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife, and unexpected events that may occur in the region, such as natural disasters, seismic events, industrial accidents, or labor difficulties. Any one of these factors has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs, and prevent development of lease inventory before expirations. Any of the risks described above could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Cybersecurity attacks on our technological systems, or those of our third-party vendors, could significantly disrupt our business operations and subject us to liability.
Our business, like other companies in the oil and gas industry, has become increasingly dependent upon digital technologies. We utilize digital technologies to, among other things, process and record financial and operating data, communicate with our business partners, analyze mineral deposits information, and estimate quantities of mineral reserves. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the United States. Deliberate attacks on, or security breaches in, our systems or infrastructure, the systems or infrastructure of third parties, or cloud-based applications could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions, and third-party liability.
There is no guarantee that our security measures will provide absolute security. We may not be able to anticipate, detect, or prevent cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until launched, and because attackers are increasingly using techniques designed to circumvent controls and avoid detection. We and our third-party service providers may therefore be vulnerable to security events that are beyond our control, and we may be the target of cyber-attacks, as well as physical attacks, which could result in the unauthorized access to our information systems or data, the data of our E&P operators, and our employees, or significant disruption to our business. These attacks could adversely impact our business operations, our revenue and profits, our ability to comply with legal, contractual, and regulatory requirements, our reputation and
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goodwill, and could result in legal risk, enforcement actions, and litigation. As cyberattacks continue to evolve, we may be required to expend significant additional resources to respond to cyberattacks, to continue to modify or enhance our protective measures, or to investigate and remediate any information systems and related infrastructure security vulnerabilities. Additionally, the continuing and evolving threat of cybersecurity attacks has resulted in evolving legal and compliance matters, including increased regulatory focus on prevention, which could require us to expend significant additional resources to meet such requirements.
Security incidents can also occur as a result of non-technical issues, such as physical theft. More recently, advancements in artificial intelligence (“AI”) may pose serious risks for many of the traditional tools used to identify individuals, including voice recognition (whether by machine or the human ear), facial recognition, or screening questions to confirm identities. In addition, generative AI systems may also be used by malicious actors to create more sophisticated cyberattacks (i.e., more realistic phishing or other attacks). The advancements in AI could lead to an increase in the frequency of identity fraud or cyberattacks (whether successful or unsuccessful), which could cause us or our E&P operators to incur increasing costs, including costs associated with additional personnel, protection technologies and policies and procedures, and third-party experts and consultants. If any of these security breaches were to occur, we could suffer disruptions to our operations and other aspects of our business.
Our inability to retain or obtain key personnel could directly affect our efficiency and profitability.
Our future success depends on retaining the services of our planned management team. Our executive officers possess a unique and comprehensive knowledge of our industry and related matters that are vital to our success within the industry. The knowledge, leadership, and technical expertise of these individuals would be difficult to replace. The loss of one or more of our officers could have a material adverse effect on our operating and financial performance, including our ability to develop and execute our long-term business strategy.
We may incur losses as a result of title defects in the properties that we acquire.
It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease or other interest in a specific mineral interest. The existence of a material title deficiency can render a lease or other interest worthless and can adversely affect our results of operations and financial condition. The failure of title on a lease, in a unit, or in any other mineral interest may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
If the E&P 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 and royalty interests are conveyed to us by asset assignment, and we 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 third-party E&P operators at its discretion, the E&P operator of the underlying property has the right to investigate and verify the title and ownership of mineral and royalty 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 E&P operator may suspend payment of the related royalty. If an E&P operator of our properties is not satisfied with the documentation we provide to validate our ownership, such E&P operator may suspend our royalty or mineral interest right payment until such issues are resolved, at which time we would receive in full payments that would have been made during the suspension, without interest. Certain of our third-party E&P operators impose significant documentation requirements for title transfer and may suspend royalty payments for significant periods of time. During the time that an E&P 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 oil or natural gas related to such mineral or royalty interest. Placement of a significant amount of our royalty interests in suspense may have a material advance effect on our business and results of operations.
Our decommissioning costs are unknown and may be substantial and may force us to divert resources from our other operations.
We may become responsible for costs associated with abandoning and reclaiming wells, facilities, and pipelines (“decommissioning costs”) we use for production of oil, natural gas, and NGL reserves. We accrue a liability for decommissioning costs associated with our wells but have not established any cash reserve account for these potential costs in respect of any of our properties. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.
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Limitation or restrictions on our ability to obtain water for our direct drilling and hydraulic fracturing processes may have an adverse effect on our operating results.
Water is an essential component of shale oil and natural gas development during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third-party competition for water in localized areas, or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. In addition, treatment and disposal of water is becoming more highly regulated and restricted. Thus, our costs for obtaining and disposing of water could increase significantly. In addition, the use, treatment, and disposal of water has become a focus of certain investors and other stakeholders who may seek to engage with us on this and other environmental matters, which may result in activism, negative reputational impacts, increased costs, or other adverse effects on our business, results of operations, and financial condition. The inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our E&P operations and have a corresponding adverse effect on our business, results of operations, and financial condition.
Weather conditions, which could become more frequent or severe due to climate change, could adversely affect our ability to conduct drilling, completion, and production activities in the areas where we operate.
Exploration and development activities and equipment of PhoenixOp and our third-party operators operating on our lands can be adversely affected by severe weather, such as well freeze-offs, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Our and our third-party operators’ planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated, or insured against. In addition, demand for oil and gas are, to a degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. These constraints could delay or temporarily halt our operations and materially increase our operating and capital costs, which could have a material adverse effect on our business, financial condition, and results of operations.
Our hedging activities could result in financial losses and reduce earnings.
To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently have entered, and may in the future enter, into derivative contracts for a portion of our future oil and natural gas production, including fixed price swaps, collars, and basis swaps. We have not designated and do not plan to designate any of our derivative contracts as hedges for accounting purposes and, as a result, record all derivative contracts on our balance sheet at fair value with changes in fair value recognized in current period earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative contracts. Derivative contracts also expose us to the risk of financial loss in some circumstances, including when:
| • | production is less than expected; |
| • | the counterparty to the derivative contract defaults on its contract obligation; or |
| • | the actual differential between the underlying price in the derivative contract or actual prices received are materially different from those expected. |
In addition, these types of derivative contracts can limit the benefit we would receive from increases in the prices for oil and natural gas.
Risks Related to Legal, Regulatory, and Environmental Matters
We are subject to significant governmental regulations, and governmental authorities can delay or deny permits and approvals or change legal requirements governing our operations, which could restrict our operations, increase costs of conducting our business, and delay our implementation of, or cause us to change, our business strategy.
The current and future operations of our business and that of the third-party E&P operators on our land are and will be governed by complex and stringent federal, state, local, and other laws and regulations, including:
| • | laws and regulations governing mineral concession acquisition, prospecting, development, mining, production, transportation, marketing, and sales; |
| • | laws and regulations related to exports, taxes, and fees; |
| • | labor standards and regulations related to occupational health and mine safety; |
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| • | environmental standards and regulations related to waste disposal, pollution clean-up, toxic substances, land use, and environmental protection; and |
| • | other matters. |
Federal, state, and local agencies may assert overlapping authority to regulate in these areas. In addition, certain of these laws and regulations may apply retroactively and may impose strict or joint and several liability on us for events or conditions over which we and our predecessors had no control, without regard to fault, legality of the original activities, or ownership or control by third parties.
Companies engaged in exploration activities often experience increased costs and delays in production and other schedules as a result of the need to comply with applicable laws, regulations, and permits. Costs of compliance may increase, and operational delays or restrictions may occur, as existing laws and regulations are revised or reinterpreted, or as new laws and regulations become applicable to our operations. Government authorities and other organizations continue to study health, safety, and environmental aspects of mineral operations, including those related to air, soil, and water quality, ground movement or seismicity, and natural resources. Government authorities have also adopted or proposed new or more stringent requirements for permitting, well construction, and public disclosure or environmental review of, or restrictions on, mineral operations. Such requirements or associated litigation could result in potentially significant added costs to comply, delay, or curtail our exploration, development, disposal, or production activities, and preclude us from carrying out our exploration program, which could have a material adverse effect on our expected production, other operations, and financial condition.
To operate in compliance with these laws and regulations, we and our third-party E&P operators must obtain and maintain permits, approvals, and certificates from federal, state, and local government authorities for a variety of activities. These permits are generally subject to protest, appeal, or litigation, which could in certain cases delay or halt projects, production of wells, and other operations. Failure to comply with laws and regulations, including obtaining and maintaining permits, approvals, and certificates, may result in enforcement actions, including the forfeiture of claims, or orders issued by regulatory or judicial authorities requiring operations to cease or be curtailed, the assessment of administrative, civil, and criminal fines and penalties and liability for noncompliance, costs of corrective action, cleanup or restoration, including capital expenditures, installation of additional equipment, or remedial actions, compensation for personal injury, property damage or other losses, and the imposition of injunctive or declaratory relief restricting or limiting our operations.
Our operations may also be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Such restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies, and qualified personnel, which may lead to periodic shortages when drilling is allowed. Permanent restrictions imposed to protect threatened or endangered species or their habitat could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.
The development and enactment of climate change legislation and regulation regarding emissions of greenhouse gases (“GHGs”) could adversely affect the mineral industry and reduce demand for the oil and natural gas that we produce.
The energy industry is affected from time to time in varying degrees by political developments and a wide range of federal, tribal, state, and local statutes, rules, orders, and regulations that may, in turn, affect the operations and costs of the companies engaged in the energy industry. In response to findings that emissions of GHGs present an endangerment to public health and the environment, the U.S. Environmental Protection Agency (the “EPA”) has adopted regulations under existing provisions of the Clean Air Act of 1970 (as amended, the “CAA”) that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that already emit conventional pollutants above a certain threshold. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which may include operations on our properties. Further, the Infrastructure Investment and Jobs Act and the Inflation Reduction Act of 2022 (the “IRA 2022”) includes billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and supporting infrastructure, and carbon capture and sequestration. Additionally, the IRA 2022 includes a charge for methane emissions from specific types of facilities that emit 25,000 metric tons of carbon dioxide equivalent or more per year, and although the IRA 2022 generally provides for a conditional exemption under certain circumstances, the change applies to emissions that exceed an established emissions threshold for each type of covered facility. On November 12, 2024, the EPA finalized the methane emissions charge rule, implementing the IRA 2022. To the extent the methane emissions charge rule is implemented as originally promulgated, it could increase the operating costs of our E&P operators and adversely affect our business.
Additional GHG regulation could also result from the agreement crafted during the United Nations climate change conference in Paris, France, in December 2015 (the “Paris Agreement”). Under the Paris Agreement, the United States committed to reducing its
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GHG emissions by 26-28% by the year 2025 as compared with 2005 levels; however, in January 2025, President Trump issued an executive order directing the United States’ withdrawal from the Paris Agreement. As a result, the effect of the Paris Agreement on our business is uncertain. Moreover, in November 2021, at the U.N. Framework Convention on Climate Change 26th Conference of the Parties, the United States and the European Union advanced a Global Methane Pledge to reduce global methane emissions at least 30% from 2020 levels by 2030, which over 100 countries have signed. While Congress has from time to time considered legislation to reduce emissions of GHGs, comprehensive legislation aimed at reducing GHG emissions has not yet been adopted at the federal level.
In the absence of comprehensive federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap-and-trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact us, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and gas produced from our properties. Restrictions on emissions of methane or carbon dioxide, such as restrictions on venting and flaring of natural gas, that may be imposed in various states, as well as state and local climate change initiatives, such as increased energy efficiency standards or mandates for renewable energy sources, could adversely affect the oil and gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact oil and gas assets. Finally, it should be noted that climate change may have significant physical effects, such as increased frequency and severity of storms, freezes, floods, drought, hurricanes, and other climatic events; if any of these effects were to occur, they could have a material adverse effect on us.
Our and third-party E&P operators’ exploration and development activities are subject to environmental risks, which could expose us and E&P operators we work with to significant liability and delay, suspension, or termination of our or the third-party E&P operators’ operations.
Our operations, through PhoenixOp and our third-party E&P operators, are subject to all of the hazards and operating risks associated with drilling for and production of crude oil, natural gas, and NGL, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of crude oil, natural gas, NGL, and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses, and environmental hazards, such as crude oil and NGL spills, natural gas leaks and ruptures, or discharges of toxic gases.
In addition, their operations are subject to risks associated with hydraulic fracturing, These risks include 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 us or our E&P 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, which in turn could have a material adverse effect on our financial condition, results of operations, and cash flows.
The exploration and possible future development phases of our business and the business of the E&P operators we work with are and will be subject to federal, state, and local environmental regulation. These regulations mandate, among other things, the maintenance of air and water quality standards and land reclamation. They also set out limitations on the generation, transportation, storage, and disposal of solid and hazardous waste. Future environmental legislation may require stricter standards and enforcement, increased fines and penalties for non-compliance, more stringent environmental assessments, and a heightened degree of responsibility for companies and their officers, directors, and employees. Future changes in environmental regulations, if any, may adversely affect our operations and the operations of the E&P operators on our land. If we fail to comply with any of the applicable environmental laws, regulations, or permit requirements, we could face regulatory or judicial sanctions. Penalties imposed by either the courts or administrative bodies could delay or stop our operations or the operations of the third-party E&P operators on our land or require considerable capital expenditures. Furthermore, certain groups opposed to exploration and mining may attempt to interfere with our operations through the legal or regulatory process or by engaging in disruptive protest activities.
Environmental hazards unknown to us, which have been caused by previous or existing owners or operators of the properties, may exist on the properties in which we hold an interest. Our properties could be located on or near the site of a Federal Superfund cleanup project, and that environmental cleanup or other environmental restoration procedures could remain to be completed or mandated by law, which may result in unexpected liabilities, with total costs that are difficult to predict.
The Comprehensive Environmental, Response, Compensation and Liability Act (“CERCLA”) and comparable state statutes impose strict joint and several liability on current and former owners and operators of sites and on persons who disposed of or
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arranged for the disposal of hazardous substances found at such sites. It is not uncommon for the government to file claims requiring cleanup actions, demands for reimbursement for government-incurred cleanup costs, or natural resource damages, or for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of solid waste and hazardous waste and authorize the imposition of substantial fines and penalties for noncompliance, as well as requirements for corrective actions. CERCLA, RCRA, and comparable state statutes can impose liability for clean-up of sites and disposal of substances found on exploration, mining, and processing sites long after activities on such sites have been completed.
The CAA restricts the emission of air pollutants from many sources, including mining and processing activities. The mining operations conducted by third parties on our land may produce air emissions, including fugitive dust and other air pollutants from stationary equipment, storage facilities, and the use of mobile sources such as trucks and heavy construction equipment, which are subject to review, monitoring, and/or control requirements under the CAA and state air quality laws. In undeveloped properties, third-party operators may be required to obtain permits before work can begin, and, in properties with existing facilities, our operators may need to incur capital costs in order to remain in compliance. In addition, permitting rules may impose limitations on their production levels or result in additional capital expenditures in order to comply with the rules.
The National Environmental Policy Act requires federal agencies to integrate environmental considerations into their decision-making processes by evaluating the environmental impacts of their proposed actions, including issuance of permits to mining facilities, and assessing alternatives to those actions. If a proposed action could significantly affect the environment, the agency must prepare a detailed statement known as an Environmental Impact Statement (“EIS”). The EPA, other federal agencies, and any interested third parties will review and comment on the scoping of the EIS and the adequacy of and findings set forth in the draft and final EIS. This process can cause delays in issuance of required permits or result in changes to a project to mitigate its potential environmental impacts, which can in turn adversely impact the economic feasibility of a proposed project.
The Clean Water Act (the “CWA”) and comparable state statutes impose restrictions and controls on the discharge of pollutants into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA regulates storm water mining facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. The CWA and comparable state statutes provide for civil, criminal, and administrative penalties for unauthorized discharges of pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.
The Safe Drinking Water Act (the “SDWA”) and the Underground Injection Control (the “UIC”) program promulgated thereunder regulate the drilling and operation of subsurface injection wells. The EPA directly administers the UIC program in some states and in others the responsibility for the program has been delegated to the state. The program requires that a permit be obtained before drilling a disposal or injection well. Violation of these regulations and/or contamination of groundwater by mining-related activities may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third-party claims may be filed by neighboring landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.
There can be no assurance that our defense of such claims will be successful. A successful claim against us or any of the third parties we contract with could have an adverse effect on our business prospects, financial condition, and results of operation.
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We or our third-party E&P operators could be subject to environmental lawsuits.
The oil and natural gas business involves a variety of operating hazards and risks, such as well blowouts, pipe failures, casing collapse, explosions, uncontrollable flows of oil, natural gas, or well fluids, fires, spills, pollution, releases of toxic gas, and other environmental hazards and risks. These hazards and risks could result in substantial losses to us from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources, and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties, and suspension of operations. In addition, we may be liable for environmental damages caused by previous owners of property purchased by us. Environmental hazards and damages resulting from such incidents may have adverse consequences beyond our land and neighboring landowners and other third parties could file claims based on environmental statutes and common law for personal injury and property damage allegedly caused by the release of hazardous substances or other waste material into the environment on or around our properties. There can be no assurance that our defense of such claims will be successful. A successful claim against us or any of the third parties we contract with to conduct operations on our land could have an adverse effect on our business prospects, financial condition, and results of operation.
We do not currently own any registered intellectual property rights relating to our software system and may be subject to competitors developing the same technology.
As of the date of this prospectus, we do not own any registered intellectual property rights for our software system used in our mineral rights discovery, grading and estimates, and acquisition. We rely on trade secret laws to protect our software. There can be no assurance that these protections will be available in all cases or will be adequate to prevent third parties from copying, reverse engineering, or otherwise obtaining and using our software. We substantially rely on this software to identify profitable assets ahead of our competitors. If an existing competitor or anyone else replicates our software, then we may be unable to successfully compete and may be unable to identify, acquire, and invest in attractive assets, which would have a material adverse effect on our business and our ability to repay any of our debts, including the obligations under the Notes.
Third parties may initiate legal proceedings alleging that our use of our software system is infringing or otherwise violating their intellectual property rights, which could lead to costly disputes or disruptions.
Our commercial success depends in part on our ability to continue to develop and use our proprietary mineral exploration software system without infringing the intellectual property or proprietary rights of third parties. However, from time to time, we may be subject to legal proceedings and claims in the ordinary course of business with respect to intellectual property. Intellectual property disputes can be costly to defend and may cause our business, operating results, and financial condition to suffer. As the applied science industry and investments in mineral rights in the United States expand, the risk increases that there may be patents issued to third parties that relate to our software of which we are not aware or that we must challenge to continue our operations as currently contemplated. Whether merited or not, we may face allegations that we or parties indemnified by us have infringed or otherwise violated the patents, trademarks, copyrights, or other intellectual property rights of third parties. Such claims may be made by competitors seeking to obtain a competitive advantage or by other parties. We may also face allegations that our employees have misappropriated the intellectual property or proprietary rights of their former employers or other third parties.
It may be necessary for us to initiate litigation to defend ourselves in order to determine the scope, enforceability, and validity of third-party intellectual property or proprietary rights, or to establish our respective rights. Regardless of whether claims that we are infringing patents or other intellectual property rights have merit, such claims can be time-consuming, can divert management’s attention and financial resources, and can be costly to evaluate and defend. Results of any such litigation are difficult to predict and may require us to stop commercializing or using our products or technology, obtain licenses, modify our solutions and technology while we develop non-infringing substitutes, incur substantial damages or settlement costs, or face a temporary or permanent injunction prohibiting us from marketing or providing the affected products and solutions. If we require a third-party license, it may not be available on reasonable terms or at all, and we may have to pay substantial royalties or upfront fees or grant cross-licenses to intellectual property rights for the use of our software. We may also have to redesign our software so it does not infringe third-party intellectual property rights, which may not be possible or may require substantial monetary expenditures and time, during which our technology may not be available for use. Even if we have an agreement to indemnify us against such costs, the indemnifying party may be unable to uphold its contractual obligations. If we cannot or do not obtain a third-party license to the infringed technology, license the technology on reasonable terms, or obtain similar technology from another source, our operations could be adversely impacted.
Further, some third parties may be able to sustain the costs of complex litigation more effectively than we can because they have substantially greater resources. Even if resolved in our favor, litigation or other legal proceedings relating to intellectual property claims may cause us to incur significant expenses and could distract our technical and management personnel from their normal responsibilities. In addition, there could be public announcements of the results of hearings, motions, or other interim proceedings or developments, and if securities analysts or investors perceive these results to be negative, it could have a material adverse effect on
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our business. Moreover, any uncertainties resulting from the initiation and continuation of any legal proceedings could have a material adverse effect on our ability to raise the funds necessary to continue our operations. Assertions by third parties that we violate their intellectual property rights could therefore have a material adverse effect on our business, financial condition, and results of operations.
We could be subject to changes in our tax rates, the adoption of new tax legislation, or exposure to additional tax liabilities.
Current economic and political conditions make tax rates in any jurisdiction subject to significant change. Our future effective tax rates could also be affected by changes in the valuation of our deferred tax assets and liabilities, or changes in tax laws or their interpretation, including changes in tax laws affecting our products and solutions and the oil and gas industry more generally. We are also subject to the examination of our tax returns and other documentation by the IRS and state tax authorities. We regularly assess the likelihood of an adverse outcome resulting from these examinations to determine the adequacy of our provision for taxes. There can be no assurance as to the outcome of these examinations or that our assessments of the likelihood of an adverse outcome will be correct. If our effective tax rates were to increase or if the ultimate determination of our taxes owed is for an amount in excess of amounts previously accrued, this could materially and adversely impact our financial condition and results of operations.
Current and future litigation, regulatory, administrative, or other legal proceedings could have a material adverse effect on our business and results of operations.
Lawsuits and regulatory, administrative, or other legal proceedings that have arisen or may arise, including, but not limited to, in connection with our oil and gas operations and the financing thereof, can involve substantial costs, including the costs associated with investigation, litigation, and possible settlement, judgment, penalty, or fine. In addition, such matters may be time-consuming to defend or prosecute and may require a commitment of management and personnel resources that will be diverted from our normal business operations. There can be no assurance that costs associated with such matters will not exceed the limits of any applicable insurance policies that we may have. Moreover, we may be unable to continue to maintain any insurance at a reasonable cost, if at all, or to secure additional coverage, which may result in costs being uninsured. Our business, financial condition, and results of operations could be adversely affected if a matter is adversely determined and, irrespective of a final determination, any such matter could significantly impact our reputation and ability to conduct our business.
General Risks
Our business could be adversely affected by unfavorable economic and political conditions.
Our future business and operations are sensitive to general business and economic conditions in the United States. National and regional economies and financial markets have become increasingly interconnected, which increases the possibilities that conditions in one country, region, or market might adversely impact companies in a different country, region, or market. Major economic or political disruptions, such as trade disputes between the United States and other countries, the slowing economy in China, the conflict between Hamas and Israel in Gaza, the war in Ukraine and sanctions on Russia, and a potential economic slowdown in the United Kingdom and Europe, may have global negative economic and market repercussions. While we do not have or intend to have operations in those countries, such disruptions may nevertheless cause fluctuations in oil prices, which could impact our ability to generate cash flows and, in turn, make interest and principal payments to you. Additionally, the resulting political instability and societal disruption from these events and other factors, such as declining business and consumer confidence, may contribute to an economic slowdown and a recession. If the economic climate in the United States or abroad deteriorates, worldwide demand for oil and natural gas products could diminish, which could impact our and our E&P operators’ operations, affect our ability and the ability of our E&P operators to continue operations, and ultimately materially adversely impact our results of operations, financial condition, and cash flows.
Other significant factors that are likely to continue to affect commodity prices in future periods include, but are not limited to, the effect of U.S. energy, monetary, and trade policies and the new administration’s energy and environmental policies, all of which are beyond our control. Our business may also be adversely impacted by any future government rule, regulation, or order that may impose production limits, as well as pipeline capacity and storage constraints. We cannot predict the ultimate impact of these factors on our business, financial condition, and cash flows.
The lingering effects of the COVID-19 pandemic or any other future global or domestic health crisis and uncertainty in the financial markets may adversely affect our ability to generate revenues.
The COVID-19 pandemic and other public health emergencies historically have had a material adverse effect on oil and gas businesses, due to governmental restrictions, associated repercussions, and operational challenges to supply and demand for oil and natural gas and the economy generally. The impacts of public health emergencies, including the COVID-19 pandemic, are uncertain and hard to predict. Although there has been economic recovery and higher oil prices through the year ended December 31, 2023,
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such negative impact may continue well beyond the containment of the COVID-19 pandemic or any other public health emergency. While oilfield activity has improved considerably and global inventories have rapidly normalized with continued demand growth since the low point experienced in 2020, considerable uncertainty remains. An extended period of global supply chain and economic disruption, as well as significantly decreased demand for oil and gas, due to the COVID-19 pandemic, any future public health emergencies, or otherwise, could have a material adverse effect on our business, access to sources of liquidity, and financial condition. Additionally, extended disruptions to the global economy are likely to cause fluctuations in oil prices and the timing of oil production, which could have a material adverse effect on our ability to generate cash flow, which in turn could limit our ability to pay principal and interest on the Notes.
Inflation could adversely impact our ability to control costs, including the operating expenses and capital costs of our third-party operating partners.
Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, the imposition of new tariffs, geopolitical issues, high levels of inflation, the availability and cost of credit and the U.S. financial market, and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. Although inflation in the United States had been relatively low for many years, there was a significant increase in inflation beginning in the second half of 2021, which continued through 2023, and while such inflation moderation moderated in 2024, inflation remains higher than the 2.0% inflation target of the U.S. Federal Reserve as of the first quarter of 2025. We continue to develop plans to address these pressures and protect our access to commodities and services. Nevertheless, we expect for the foreseeable future to experience supply chain constraints and inflationary pressure on operating costs.
High inflation may cause our third-party operators to experience increasing costs for their operations, including oilfield services and equipment and increased personnel costs. Our operating partners may pass on such increased costs to us and have a negative effect on our business and financial condition. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates multiple times in an effort to curb inflationary pressure on the costs of goods and services across the United States, which has had the effects of raising the cost of capital and depressing economic growth, either of which, or the combination thereof, could hurt the financial results of our business. We cannot predict any future trends in the rate of inflation and any continued significant increase in inflation, to the extent we are unable to recover higher costs through higher prices and revenues for our products, would negatively impact our business, financial condition, and results of operations.
Increased attention to environmental, social, and governance (“ESG”) matters may impact our business.
Businesses across all industries are facing increasing scrutiny from stakeholders related to their ESG practices. If we do not adapt to or comply with investor or stakeholder expectations and standards, which are evolving, or if we are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, we may suffer from reputational damage and our business, financial condition, and results of operations could be materially and adversely affected. Increasing attention to climate change, increasing societal expectations on businesses to address climate change, and potential consumer use of substitutes to energy commodities may result in increased costs, reduced demand for our hydrocarbon products, reduced profits, increased investigations and litigation, and negative impacts on our ability to access capital markets.
In addition, organizations that provided information to investors on corporate governance and related matters have developed rating processes for evaluating business entities on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders. Such ratings are used by some investors to inform their investment and voting decisions.
Additionally, certain investors use these scores to benchmark businesses against their peers. If we are perceived as lagging, our investors may engage with such third-party organizations to require improved ESG disclosure or performance.
Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas and related infrastructure projects. Although the impact of future Trump Administration policies is currently unknown, 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, financial condition, results of operations, and cash flows.
Investment in new business ventures could prove unsuccessful and adversely affect our business, financial condition, and results of operations.
In the future, we may invest in new business ventures. Such endeavors may involve risks and uncertainties, including greater-than-expected liabilities and expenses, as well as economic and regulatory challenges associated with operating in new businesses, regions, or countries. Investment into new business ventures may expose the company to additional risks that could delay or prevent us from completing an investment or otherwise limit our ability to fully realize the anticipated benefits of an investment. The failure of any significant investment could adversely affect our business, financial condition, and results of operations.
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Risks Related to Our Indebtedness
Our substantial indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the Notes and our other indebtedness.
We have a significant amount of indebtedness. We may not generate sufficient cash flow from operations, or have future borrowings available under credit facilities or other sources of financing, to enable us to repay our indebtedness, including the Notes, or to fund our other liquidity needs. As of March 31, 2025, after giving effect to the borrowing of an additional $25.0 million under the Fortress Credit Agreement in April 2025, we had approximately $1,109.4 million of indebtedness outstanding, which comprised $275.0 million outstanding under the Fortress Credit Agreement, $163.0 million outstanding under the Adamantium Loan Agreement (and corresponding amount of Adamantium Securities), $571.7 million of Reg D Bonds outstanding, and $99.6 million of Reg A Bonds outstanding. Furthermore, the Fortress Credit Agreement provides for an $8.5 million tranche of loans that represents a contingent principal obligation that is only due and payable (together with accrued interest thereon) upon certain conditions occurring, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing by the obligors thereunder. See “Capitalization” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness.”
Specifically, our high level of indebtedness could have important consequences to holders of Notes, including:
| • | making it more difficult for us to satisfy our obligations with respect to the Notes and our other indebtedness, and if we fail to comply with these requirements, an event of default could result; |
| • | limiting our ability to obtain additional financing to fund future working capital, capital expenditures, investments, acquisitions, or other general corporate requirements; |
| • | requiring a substantial portion of our cash flows to be dedicated to debt service payments instead of other purposes, thereby reducing the amount of cash flows available for working capital, capital expenditures, investments, acquisitions, and other general corporate purposes; |
| • | increasing our vulnerability to general adverse economic and industry conditions; |
| • | exposing us to the risk of increased interest rates, as borrowings under the Fortress Credit Agreement are at variable rates of interest; |
| • | limiting our flexibility in planning for and reacting to changes in the industry in which we compete and to changing business and economic conditions; |
| • | placing us at a disadvantage compared to other, less leveraged competitors or competitors with better access to capital resources, and generally affecting our ability to compete; and |
| • | increasing our cost of borrowing. |
Any such consequences could have a material adverse effect on our business, results of operations, and financial condition.
Despite our current level of indebtedness, we will still be able to incur substantially more debt. This could further exacerbate the risks to our financial condition described above.
We may incur significant additional indebtedness in the future. The Indenture will not contain any limitations on our ability to incur additional indebtedness, including Senior Debt. Although the Fortress Credit Agreement contains, and the terms of future indebtedness we incur may contain, restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and the additional indebtedness incurred in compliance with these restrictions could be substantial. If we incur any additional Senior Debt, the holders of that indebtedness will be entitled to repayment in full from any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution, or other winding up of our company prior to any payment to holders of Notes. If we incur any additional indebtedness that ranks equally with the Notes, subject to collateral arrangements, the holders of that indebtedness will be entitled to share ratably with you in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution, or other winding up of our company. In either case, this could reduce the amount of proceeds paid to you. These restrictions also will not prevent us from incurring obligations that do not constitute indebtedness. If new indebtedness or other obligations are added to our current indebtedness levels, the related risks that we now face would increase.
We may not be able to generate sufficient cash to service all of our existing and future indebtedness, including the Notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.
As a result of our substantial indebtedness, a significant amount of our cash flow will be required to pay interest and principal on our outstanding indebtedness. Our ability to make scheduled payments on or refinance our indebtedness, including the Notes, depends
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on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and to certain financial, business, legislative, regulatory, and other factors beyond our control. We may be unable to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal of, premium, if any, and interest on our indebtedness, including the Notes, or to service our other obligations.
We recorded net losses of $24.8 million and $16.2 million for the years ended December 31, 2024 and 2023, respectively, and net income of $5.7 million for the year ended December 31, 2022. In 2023 and 2024, we incurred a significant amount of debt in order to accelerate the growth of our business by acquiring additional assets and establishing our direct drilling operations. As a result, our cash flows from operations alone would not have been sufficient to service required cash interest and principal payment obligations under our then-existing debt in 2023 and 2024. Furthermore, as of December 31, 2024, we estimate that we will need to make approximately $749.3 million and $3,224.8 million in capital expenditures to develop all our proved and probable undeveloped reserves, respectively, and that we will need to raise approximately $658.9 million in additional capital through the end of 2028 to fund such development. Although we expect our cash flows from operations to be sufficient to service cash interest and principal payment obligations under our debt for the foreseeable future, there can be no assurance as to the sufficiency of our cash flows for that purpose, and we do not expect such cash flows alone to be adequate to fund both our debt service obligations and the development of our reserves. Therefore, we expect to require additional capital to fund our growth and may require additional liquidity to service our debt. As a result, we may use the proceeds of additional debt, including the Notes offered hereby, to make interest and principal payments on our existing debt. See “—Risks Related to Our Business and Operations—The acquisition and development of our properties, directly or through our third-party E&P operators, will require substantial capital, and we and our third-party E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all, including as a result of increases in the cost of capital resulting from Federal Reserve policies in the past few years and otherwise,” “—Despite our current level of indebtedness, we will still be able to incur substantially more debt. This could further exacerbate the risks to our financial condition described above,” “—Risks Related to the Notes and this Offering—We may invest or spend the proceeds of this offering in ways with which you may not agree,” “Use of Proceeds,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
If our cash flows from operations and capital resources are insufficient to fund our debt service obligations, we could face substantial liquidity problems and could be forced to reduce or delay investments and capital expenditures or to dispose of material assets or operations, seek additional debt or equity capital, or restructure or refinance our indebtedness, including the Notes. We may not be able to effect any such alternative measures on commercially reasonable terms or at all and, even if successful, those alternative actions may not allow us to meet our scheduled debt service obligations. If we cannot make scheduled payments on our indebtedness, we will be in default and holders of such indebtedness could declare all outstanding principal of, premium on, and interest, if any, on such indebtedness to be due and payable, and the lenders under any revolving or delayed draw credit facilities, including the Fortress Credit Agreement, could terminate their commitments to loan money to us. As a result of a default, any secured lenders could foreclose against the assets securing their borrowings and we could be forced into bankruptcy or liquidation. All of these events could result in your losing all or a part of your investment in the Notes.
Furthermore, the Fortress Credit Agreement restricts, and our future indebtedness may restrict, our ability to dispose of assets and use the proceeds from such dispositions and may also restrict our ability to raise debt or equity capital to be used to repay other indebtedness when it becomes due. We may not be able to consummate those dispositions or to obtain proceeds in an amount sufficient to meet any debt service obligations then due.
We will need to repay or refinance a substantial amount of our indebtedness prior to maturity of the Notes. Failure to do so could have a material adverse effect on our business, results of operations, and financial condition.
We are offering Notes with maturities ranging from three to eleven years from the date of initial issuance. As of March 31, 2025, after giving effect to the borrowing of an additional $25.0 million under the Fortress Credit Agreement in April 2025, we had approximately $565.7 million of indebtedness maturing within three years, including all amounts under the Fortress Credit Agreement, $649.0 million of indebtedness maturing within five years, $786.2 million of indebtedness maturing within seven years, and $1,109.4 million of indebtedness maturing within eleven years. Furthermore, the Fortress Credit Agreement provides for an $8.5 million tranche of loans that represents a contingent principal obligation that is only due and payable (together with accrued interest thereon) upon certain conditions occurring, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing by the obligors thereunder. The terms of the Adamantium Securities, the Reg A Bonds, the Subordinated Reg D Bonds, and the July 2022 506(c) Bonds contain mandatory redemption provisions providing the holders thereof with the ability to request redemption of their bonds at any time prior to maturity at a price equal to 100% (with respect to the Adamantium Secured Note), 90% (with respect to the July 2022 506(c) Bonds), or 95% (with respect to the Adamantium Bonds, the Reg A Bonds, and the Subordinated Reg D Bonds) of the principal amount being redeemed. The amount of such redemption is limited (i) on an annual basis to 10% of the aggregate principal amount of Adamantium Bonds, Reg A Bonds, or Subordinated Reg D Bonds, as applicable, then issued and outstanding and (ii) $5.0 million in aggregate principal amount of the Adamantium Secured Note in any 12-month period. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness.” Consequently, prior to the maturity of the Notes, we will need to repay, refinance, replace, or otherwise extend the maturity of a substantial amount of our existing indebtedness. Our ability to repay, refinance, replace, or extend will be dependent on, among other things, business conditions, our financial performance, and the general condition of the financial markets. If a financial disruption were to occur at the time that we are required to repay such indebtedness, we could be forced to undertake alternate financings, negotiate for an extension of the maturity of such indebtedness, or sell assets and delay capital expenditures in order to generate proceeds that could be used to repay such indebtedness. We cannot assure you that we will be able to consummate any such transaction on terms that are commercially reasonable, on terms acceptable to us, or at all. Our failure to repay, refinance, replace, or otherwise extend the maturity of our indebtedness could result in an event of default under the documents governing our indebtedness, which could lead to an acceleration or repayment of substantially all of our outstanding indebtedness.
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The terms of our outstanding indebtedness restrict, and the terms of future indebtedness we may incur may restrict, our current and future operations, particularly our ability to respond to changes in the economy or our industry or to take certain actions, which could harm our long-term interests.
The agreements governing certain of our existing indebtedness contain, and the agreements governing future indebtedness we may incur may contain, a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability to:
| • | incur additional indebtedness and guarantee indebtedness; |
| • | pay dividends or make other distributions in respect of, or repurchase or redeem, our capital stock; |
| • | prepay, redeem, or repurchase certain indebtedness; |
| • | make loans and investments; |
| • | sell or otherwise dispose of assets; |
| • | incur liens; |
| • | enter into transactions with affiliates; |
| • | designate any of our subsidiaries as unrestricted subsidiaries; |
| • | enter into agreements restricting our subsidiaries’ ability to pay dividends; |
| • | consolidate, merge, sell, or otherwise dispose of all or substantially all of our assets; and |
| • | prepay subordinated or junior lien indebtedness, including the Notes. |
In addition, the Fortress Credit Agreement contains financial covenants that require us to maintain (a) a maximum total secured leverage ratio (i) as of the last day of any fiscal quarter ending on or before December 31, 2025 of less than or equal to 2.00 to 1.00 (commencing with the fiscal quarter ending December 31, 2024) and (ii) as of the last day of any fiscal quarter ending on or after March 31, 2026 of less than or equal to 1.50 to 1.00, (b) a minimum current ratio as of the last day of each calendar month of (i) 0.90 to 1.00 from September 30, 2024 through October 31, 2024, (ii) 0.80 to 1.00 from November 30, 2024 through November 30, 2025, (iii) 0.90 to 1.00 from December 31, 2025 through December 31, 2026, and (iv) 1.00 to 1.00 for each calendar month ending thereafter, and (c) a minimum asset coverage ratio as of the last day of any fiscal quarter (i) ending during the period from June 30, 2024 through December 31, 2024, of at least 2.00 to 1.00, (ii) ending during the period from March 31, 2025 through September 30, 2025, of at least 1.70 to 1.00, and (iii) ending during the period from December 31, 2025 and thereafter, of at least 2.00 to 1.00. Our ability to meet the financial covenant could be affected by events beyond our control.
Furthermore, subject to certain conditions, the Reg A Bonds require that we offer to purchase all or any amount of the outstanding Reg A Bonds at a price equal to the then outstanding principal on the Reg A Bonds being repurchased plus any accrued but unpaid interest on such Reg A Bonds, upon a change of control.
These restrictions may affect our ability to service our indebtedness or grow in accordance with our strategy. As a result of all of these restrictions, we may be:
| • | limited in how we conduct our business; |
| • | unable to raise additional indebtedness or equity financing to operate during general economic or business downturns; or |
| • | unable to compete effectively or to take advantage of new business opportunities. |
A breach of the covenants under any such indebtedness could result in a default under the applicable indebtedness. Such a default may allow the creditors to accelerate the related indebtedness and may result in the acceleration of any other indebtedness to which a cross-acceleration or cross-default provision applies. In addition, an event of default under the Fortress Credit Agreement or any other revolving or delayed draw credit facilities would permit the lenders under those facilities to terminate all commitments to extend further credit thereunder.
Furthermore, if we were unable to repay the amounts due and payable under any secured indebtedness, including the Fortress Credit Agreement, those lenders could proceed against the collateral granted to them, including our available cash, to secure that indebtedness, subject to the provisions of any outstanding intercreditor arrangements. In the event our lenders accelerate the repayment of our borrowings, we and our subsidiaries may not have sufficient assets to repay that indebtedness.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Borrowings under the Fortress Credit Agreement are, and borrowings under indebtedness we may incur in the future may be, at variable rates of interest and expose us to interest rate risk. If interest rates were to increase, our debt service obligations on the
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variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash flows, including cash available for servicing our indebtedness, including the Notes, will correspondingly decrease. In the future, we may enter into interest rate swaps that involve the exchange of floating- for fixed-rate interest payments in order to reduce interest rate volatility or risk. However, we may not maintain interest rate swaps with respect to any of our variable rate indebtedness, and any swaps we enter into may not fully or effectively mitigate our interest rate risk.
Risks Related to the Notes and this Offering
Your right to receive payment under the Notes is contractually subordinated to Senior Debt.
The Notes will be the Issuer’s senior subordinated unsecured obligations and will:
| • | rank contractually senior in right of payment to all of the Issuer’s existing and future indebtedness that is contractually subordinated to the Notes, including the Subordinated Reg D Bonds; |
| • | without giving effect to collateral arrangements, rank equally in right of payment with all of the Issuer’s existing and future senior indebtedness (other than Senior Debt); |
| • | be contractually subordinated to any Senior Debt, including indebtedness under the Fortress Credit Agreement, the Adamantium Debt, and the Senior Reg D/Reg A Bonds; |
| • | be effectively subordinated to any of the Issuer’s existing or future secured indebtedness and other obligations, including under the Fortress Credit Agreement and the Adamantium Loan Agreement, to the extent of the value of the assets securing such indebtedness; and |
| • | be structurally subordinated to all of the existing and future liabilities (including trade payables) and preferred equity of each of the Issuer’s subsidiaries, including Adamantium. |
Upon any payment or distribution to creditors of the Issuer in respect of an insolvency event, the holders of Senior Debt will be entitled to be paid in full from the assets of the Issuer before any payment may be made pursuant to the Notes. Until the Senior Debt is paid in full, any distribution to which holders of the Notes would be entitled shall instead be made to holders of Senior Debt. As a result, in the event of an insolvency of the Issuer, holders of Senior Debt may recover more, ratably, than the holders of Notes.
In addition, the subordination provisions in the Indenture will provide:
| • | customary turnover provisions by the Trustee and the holders of the Notes for the benefit of the holders of Senior Debt; |
| • | that the Issuer may not make any payment in respect of the Notes if (a) a payment default on Senior Debt has occurred and is continuing or (b) any other default occurs and is continuing on any series of Senior Debt that permits holders of that series of Senior Debt to accelerate its applicable maturity and the Trustee receives a notice of such default from the Issuer or the holders of any Senior Debt, in each case, until such default is cured or waived; |
| • | that the holders of the Notes and the Trustee are prohibited, without the prior consent of such holders of Senior Debt, from taking any enforcement action in relation to the Notes for a period of 90 days after delivery of notice of an event of default under the Indenture to the holders of Senior Debt; and |
| • | that if the Issuer fails to pay the principal of or accrued and unpaid interest, if any, on a Note, on the due date, because of the subordination provisions of the Indenture, the failure shall not constitute a default or event of default under the Indenture. |
The Indenture will also provide that, except under very limited circumstances, only the Trustee will have standing to bring an enforcement action in respect of the Notes. Moreover, the Indenture restricts the rights of holders of the Notes to initiate insolvency proceedings or take legal actions against the Issuer, and by accepting any Note each such holder will be deemed to have agreed to these restrictions. As a result of these restrictions, holders of the Notes will have limited remedies and recourse under the Notes in the event of a default by the Issuer.
As of March 31, 2025, after giving effect to the borrowing of an additional $25.0 million under the Fortress Credit Agreement in April 2025, $550.2 million of our outstanding indebtedness would have constituted Senior Debt. Furthermore, the Fortress Credit Agreement provides for an $8.5 million tranche of loans that represents a contingent principal obligation that is only due and payable (together with accrued interest thereon) upon certain conditions occurring, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing by the obligors thereunder. For a description of the terms of the Fortress Credit Agreement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement.”
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The Notes will be effectively subordinated to the indebtedness under the Fortress Credit Agreement, the Adamantium Loan Agreement, the Adamantium Secured Note, and any of our other secured indebtedness to the extent of the value of the assets securing that indebtedness.
The Notes will not be secured by any of our or our subsidiaries’ assets. As a result, the Notes will be effectively subordinated to the indebtedness under the Fortress Credit Agreement, the Adamantium Loan Agreement, the Adamantium Secured Note, and any of our other secured indebtedness with respect to the assets that secure that indebtedness. As of March 31, 2025, after giving effect to the borrowing of an additional $25.0 million under the Fortress Credit Agreement in April 2025, we had $438.0 million of outstanding secured indebtedness associated with our borrowings under the Fortress Credit Agreement and the Adamantium Loan Agreement. Furthermore, the Fortress Credit Agreement provides for an $8.5 million tranche of loans that represents a contingent principal obligation that is only due and payable (together with accrued interest thereon) upon certain conditions occurring, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing by the obligors thereunder. For a description of the terms of the Fortress Credit Agreement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement.”
In addition, we may incur additional secured indebtedness in the future. The effect of this subordination is that, upon a default in payment on, or the acceleration of, any of our secured indebtedness, or in the event of bankruptcy, insolvency, liquidation, dissolution, or reorganization of the Issuer, the proceeds from the sale of such assets securing our secured indebtedness will be available to repay obligations on the Notes only after all obligations under the Fortress Credit Agreement, the Adamantium Loan Agreement, and any of our other secured indebtedness have been paid in full, and holders of the Notes will participate ratably in our remaining assets with all holders of our unsecured indebtedness that are deemed to be of the same class as the Notes, and potentially with all of our other general creditors, based upon the respective amounts owed to each holder or creditor. As a result, holders of the Notes may receive less, ratably, than the holders of secured indebtedness in the event of our bankruptcy, insolvency, liquidation, dissolution, or reorganization.
The Notes are the Issuer’s obligations alone, and will be structurally subordinated to all obligations of the Issuer’s existing and future subsidiaries.
The Notes are the Issuer’s obligations alone, and not the obligation of any of its subsidiaries. None of the Issuer’s existing or future subsidiaries will guarantee the Notes, and therefore will have no obligation, contingent or otherwise, to pay amounts due under the Notes or to make any funds available to pay those amounts, whether by dividend, distribution, loan, or other payment. The Notes therefore will be structurally subordinated to all indebtedness and other obligations of any of the Issuer’s subsidiaries such that, in the event of insolvency, liquidation, reorganization, dissolution, or other winding up of any such subsidiary, all of that subsidiary’s creditors (including trade creditors) would be entitled to payment in full out of that subsidiary’s assets before the Issuer would be entitled to any payment from that subsidiary (and, therefore, the Issuer’s creditors, including holders of the Notes, to participate in those assets).
In particular, Adamantium, the Issuer’s wholly owned subsidiary, has issued $204.4 million of Adamantium Securities as of March 31, 2025. The holders of the Adamantium Securities will therefore be entitled to payment in full out of Adamantium’s assets in the event of an insolvency, liquidation, reorganization, dissolution, or other winding up of Adamantium, including Adamantium’s primary asset—the Adamantium Loan Agreement. Borrowings under the Adamantium Loan Agreement are secured by mortgages on certain of our properties, which mortgages are junior to the security interest of the Fortress Credit Agreement and other existing and future senior secured indebtedness. The Adamantium Loan Agreement can be amended or waived without the consent of the holders of the Adamantium Securities or any other holders of our debt, including the Notes. Any such amendment may be adverse to the interests of holders of Notes.
The Indenture will not restrict the Issuer’s subsidiaries from incurring additional indebtedness and will not contain any limitation on the amount of other liabilities, such as trade payables, that may be incurred by these subsidiaries. Any additional indebtedness incurred by the Issuer’s subsidiaries will increase the risks described above.
As of December 31, 2024, the Issuer’s subsidiaries held approximately $332.7 million, or 32.3%, of our total consolidated assets and approximately $75.8 million, or 7.1%, of our total consolidated liabilities, and accounted for approximately $128.1 million, or 45.6%, of our consolidated revenue for the year ended December 31, 2024 (all amounts presented exclude intercompany balances).
We conduct some or all of our operations through subsidiaries and may not have access to sufficient cash to make payments on the Notes.
We are a holding company with limited direct operations. Substantially all of our operations are conducted through our subsidiaries. Our most significant assets are the equity interests we hold in our subsidiaries. Accordingly, our ability to meet outstanding debt service, including with respect to the Notes, and satisfy other obligations is dependent on the generation of cash flow
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by our subsidiaries and their ability to make such cash available to us, whether by dividend, debt repayment, or otherwise. Our subsidiaries do not have any obligation to pay amounts due on the Notes or our other indebtedness or to make funds available for that purpose. Our subsidiaries may not be able to, or may not be permitted to, make distributions to enable us to make payments in respect of our indebtedness, including the Notes. Each subsidiary is a separate and distinct legal entity, and, under certain circumstances, legal and contractual restrictions may limit our ability to obtain cash from our subsidiaries. While the Fortress Credit Agreement limits, and future indebtedness we incur may limit, the ability of our subsidiaries to incur consensual restrictions on their ability to pay dividends or make other intercompany payments to us, these limitations are subject to qualifications and exceptions. In the event that we do not receive distributions from our subsidiaries, we may be unable to make required principal and interest payments on our indebtedness, including the Notes.
The terms of the Indenture and the Notes will not necessarily restrict our ability to take actions that may impair our ability to pay interest on and principal of the Notes.
Although the Indenture will include covenants that will restrict us from taking certain actions, the terms of these covenants will include important exceptions that you should review carefully before investing in the Notes. Among other things, the Indenture will not require us or any of our subsidiaries to maintain any financial ratios, maintain a sinking fund, or repurchase debt securities in the event of a change of control or asset sale, and will not limit our or our subsidiaries’ ability to incur indebtedness, pay dividends or make other distributions in respect of, or repurchase or redeem, capital stock, prepay, redeem, or repurchase indebtedness, issue preferred stock or similar equity securities, make loans and investments, sell or otherwise dispose of assets, incur liens, enter into transactions with affiliates, or enter into agreements restricting subsidiaries’ ability to pay dividends. Such actions may adversely affect our ability to perform our obligations under the Indenture and the Notes and could intensify the related risks that we face.
You will not have the benefit of an independent review of the terms of the Notes, the prospectus, or our company as would customarily be performed in underwritten securities offerings.
In a traditional underwritten securities offering, investment banks acting as underwriters or placement agents undertake a due diligence exercise with the issuer, including business, financial, legal, and accounting analysis, and review the prospectus for material misstatements or omissions. The investment banks in an underwritten securities offering also assist with structuring the terms of the securities, including pricing, and engaging with investors.
We are offering the Notes without an underwriter or placement agent. Therefore, you will not have the benefit of an independent review of the terms of the Notes, the prospectus, or our company. Accordingly, you should consult your own investment, tax, financial, and other professional advisors prior to deciding whether to invest in the Notes.
We may redeem your Notes at our option, which may adversely affect your return.
As described under “Description of Notes—Optional Redemption,” we have the right to redeem the Notes in whole or in part at any time at a redemption price of 100.0% of the principal amount being redeemed, plus accrued and unpaid interest. We may choose to exercise these redemption rights when prevailing interest rates are relatively low. As a result, you may not be able to reinvest the redemption proceeds in a comparable security at an effective interest rate as high as that of the Notes.
Holders of Notes will have a limited right to require us to redeem their Notes, and we may not be able to repurchase such Notes when requested.
Subject to the provisions described in “Description of Notes—Subordination,” a holder may require us, at any time and from time to time prior to maturity, to redeem its Notes at a price equal to 95% of the aggregate principal amount of such Notes plus accrued and unpaid interest to, but excluding, the date of redemption, subject to certain exceptions and to the 10% Limit. Redemption requests for the Notes will be processed in the order they are received by the Issuer without regard to date of issuance, maturity date, interest payment method, or interest rates of the Notes for which redemption has been requested.
The terms of the Adamantium Securities, the Reg A Bonds, the Subordinated Reg D Bonds, and the July 2022 506(c) Bonds contain mandatory redemption provisions providing the holders thereof with the ability to request redemption of their bonds at any time prior to maturity at a price equal to 100% (with respect to the Adamantium Secured Note), 90% (with respect to the July 2022 506(c) Bonds), or 95% (with respect to the Adamantium Bonds, the Reg A Bonds, and the Subordinated Reg D Bonds) of the principal amount being redeemed. The amount of such redemption is limited (i) on an annual basis to 10% of the aggregate principal amount of Adamantium Bonds, Reg A Bonds, or Subordinated Reg D Bonds, as applicable, then issued and outstanding and (ii) $5.0 million in aggregate principal amount of the Adamantium Secured Note in any 12-month period. No amounts redeemed under such debt will count towards the 10% Limit under the Notes. Redemption requests for the Notes will be processed in the order they are received by the Issuer without regard to date of issuance, maturity date, interest payment method, or interest rates of the Notes for which redemption has been requested. Except as set out in the preceding sentence with respect to redemption requests for the Notes relative to other redemption requests for the Notes, we intend to process redemption requests for any holder of our debt securities, regardless of which tranche of debt such holder holds, in the order in which such request is received, and do not intend to prioritize redemption requests under the Reg D/Reg A Bonds or Adamantium Securities over redemption requests under the Notes, or visa versa; however, we are not obligated to do so and may, in the future, determine to honor redemption requests as among the tranches of our debt securities under different criteria, whether prioritizing near-term maturities, higher interest rates, specific interest payment methods, or otherwise. Any such determination will be made in our sole discretion. As a result, redemption requests for the Notes may receive lower priority as compared to redemption requests for our other debt securities. See “—Your right to receive payment under the Notes is contractually subordinated to Senior Debt” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness.”
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Our affiliates are not prohibited from owning the Notes or our other indebtedness and may, from time to time, have their Notes or other indebtedness redeemed by us in accordance with the terms of the applicable indebtedness or otherwise. The principal amount of any Notes requested for redemption by, and redeemed from, our manager, executive officers, or their respective family members (an “executive redemption request”) during any calendar year will not be included in calculating the 10% Limit with respect to a redemption request made by any other holder (a “non-executive redemption request”) for such calendar year; however, such redemptions will be included in calculating the 10% Limit with respect to an executive redemption request. As a result, in no circumstance will an executive redemption request decrease the 10% Limit with respect to a non-executive redemption request, but a non-executive redemption request will decrease the 10% Limit with respect to an executive redemption request. For example, if the 10% Limit at the time of a redemption request is $10.0 million, and an executive redemption request is made for $7.5 million aggregate principal amount of Notes and such Notes are redeemed by the Issuer, the 10% Limit remains at $10.0 million for any non-executive redemption requests; however, the 10% Limit for a subsequent executive redemption request would become $2.5 million. Conversely, if the 10% Limit at the time of a redemption request is $10.0 million, and a non-executive redemption request is made for $7.5 million aggregate principal amount of Notes and such Notes are redeemed by the Issuer, the 10% Limit for a subsequent redemption request, whether an executive redemption request or a non-executive redemption request, would become $2.5 million. Therefore, we may be required to purchase up to 20% of the then-outstanding Notes pursuant to the 10% Limit in any calendar year to the extent that executive redemption requests made prior to any non-executive redemption request reach the 10% Limit in such calendar year and subsequent non-executive redemption requests also reach the 10% Limit in such calendar year.
The source of funds for any purchase of the Notes would be our available cash or cash generated from our operations or other sources, including borrowings, sales of assets, or sales of equity. We may not be able to repurchase the Notes upon a redemption request because we may not have sufficient financial resources to purchase all of the Notes requested for redemption. We may require additional financing from third parties to fund any such purchases, and we may be unable to obtain financing on satisfactory terms or at all. Further, our ability to repurchase the Notes may be limited or prohibited by contract or by law. In order to retain funds sufficient to satisfy redemption requests we may have to avoid taking certain actions that would otherwise be beneficial to us.
We will not otherwise be required to redeem the Notes at the request of any holder, whether upon a change of control, in connection with an asset sale or casualty event, at the holder’s option, or otherwise. As a result, holders should expect to hold their Notes until maturity. Although we will pay a fixed rate of interest on the Notes, holders may have to forego opportunities to apply the amounts invested in the Notes in other ways, including in a more lucrative investment.
Notes may only be transferred with our consent. There is no established trading market for the Notes and an active trading market for the Notes is not expected to develop.
The Notes will be a new issue of securities with no established trading market or trading platform. Notes will be transferable by a holder only with our prior written consent, which we may provide at our sole discretion and determine on an ad hoc basis. See “Description of Notes—Transfer.” We do not intend to apply to list the Notes on any securities exchange or over-the-counter market, or to arrange for quotation on any automated dealer quotation system, and we do not expect an active trading market for the Notes to develop.
Even if we permit transfers and obtain a listing or quotation in the future, we do not know the extent to which investor interest will lead to the development and maintenance of a liquid trading market. If a trading market were to develop, future trading prices of the Notes may be volatile and will depend on many factors, including:
| • | the number of holders of Notes; |
| • | prevailing interest rates; |
| • | our operating performance and financial condition; |
| • | the interest of securities dealers in making a market for them; and |
| • | the market for similar securities. |
As a result, an active trading market may not develop for the Notes. If no trading platform is established, or an active trading market does not develop or is not maintained, the market price and liquidity of the Notes would be adversely affected. In that case, you may not be able to sell your Notes at a particular time, at a favorable price, or at all. Therefore, you must be prepared to hold your Notes to maturity and should not purchase Notes unless you understand, and know you can bear, all of the investment risks involving the Notes.
Even if an active trading market for the Notes does develop, there is no guarantee that it will continue. Historically, the market for non-investment grade debt has been subject to severe disruptions that have caused substantial volatility in the prices of securities similar to the Notes. The market, if any, for the Notes may experience similar disruptions, and any such disruptions may adversely affect the liquidity in that market or the prices at which you may sell your Notes. In addition, subsequent to their initial issuance, the Notes may trade at a discount from their initial offering price, depending upon prevailing interest rates, the market for similar Notes, our performance, and other factors.
Notes with longer terms may expose holders to higher risk than those with shorter terms. Likewise, Compound Interest Notes may expose holders to higher risk than Cash Interest Notes.
We are offering Notes with maturities ranging from three to eleven years, and we are offering Notes for which we will pay interest in cash (i.e., Cash Interest Notes) and Notes for which we will pay interest by adding such interest to the then-outstanding principal amount of the Notes (i.e., Compound Interest Notes).
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By necessity, a Note with a longer term will be subject to and affected by the potential risks to our company, our significant indebtedness, the Notes, and this offering (including those described in this “Risk Factors” section) for a longer period of time than a shorter-term Note, resulting in a greater chance of an adverse event occurring prior to maturity of a longer-termed Note.
Likewise, holders of Cash Interest Notes will receive cash interest payments monthly, while holders of Compound Interest Notes will not receive any payments on their Notes until maturity or earlier redemption at the option of the Issuer. As a result, holders of Compound Interest Notes will not gain any liquidity from their investment and will subject both the principal and interest on their Notes to the increased risks described above.
Noteholders must rely on us as note registrar and paying agent under the Indenture.
The Issuer will initially act as paying agent and registrar for the Notes, and will be responsible for making payments on the Notes and maintaining an ownership register. We may have a conflict of interest in serving as the paying agent and registrar, and the absence of a third-party paying agent or registrar may result in less protection to noteholders. For example, if we suffer any successful cyberattacks on our systems, such attacks may effect our records of noteholders, resulting in unauthorized access to your information and even potential loss of records for your Notes.
We may invest or spend the proceeds of this offering in ways with which you may not agree.
Although we intend to use the proceeds from this offering as described under “Use of Proceeds,” we will not be contractually obligated to do so and will retain broad discretion over the use of proceeds from this offering. You may not agree with the manner in which our management chooses to allocate and use the net proceeds. Our management may use the proceeds for purposes that may not increase our profitability or otherwise ensure our ability to pay interest on, and principal of, the Notes. In addition, pending our use of the proceeds, we may invest the proceeds primarily in instruments that do not produce significant income or that may lose value.
Fraudulent transfer and conveyance laws may permit a court to void the Notes and, if that occurs, you may not receive any payments on the Notes.
Fraudulent transfer and conveyance laws may apply to the issuance of the Notes. Under bankruptcy laws and other fraudulent transfer or conveyance laws, the Notes could be avoided as a fraudulent transfer or conveyance if the Issuer (a) issued the Notes with the intent of hindering, delaying, or defrauding creditors or (b) received less than reasonably equivalent value or fair consideration in return for issuing the Notes and, in the case of clause (b) only, one of the following is also true at the time thereof:
| • | the Issuer was insolvent or rendered insolvent by reason of the issuance of the Notes; |
| • | the issuance of the Notes left the Issuer with an unreasonably small amount of capital or assets to carry on the business engaged in or contemplated; |
| • | the Issuer intended to, or believed that the Issuer would, incur indebtedness beyond our ability to pay such indebtedness as it matures; or |
| • | the Issuer was a defendant in an action for money damages, or had a judgment for money damages docketed against the Issuer, if, in either case, the judgment is unsatisfied after final judgment. |
The measures of insolvency for purposes of fraudulent conveyance or fraudulent transfer laws vary depending upon the law of the state or jurisdiction that is being applied, such that we cannot be certain as to: (1) the standards a court would use to determine whether or not the Issuer was insolvent at the relevant time, or, regardless of the standard that a court uses, that it would not determine that the Issuer was indeed insolvent on that date; (2) that any payments to the holders of the Notes did not constitute preferences, fraudulent conveyances, or fraudulent transfers on other grounds; or (3) that the issuance of the Notes would not be subordinated to the Issuer’s other indebtedness. In general, however, a court would deem an entity insolvent if:
| • | the sum of its indebtedness, including contingent and unliquidated liabilities, was greater than the fair value of all of its assets; |
| • | the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing indebtedness, including contingent liabilities, as they become absolute and mature; or |
| • | it could not pay its indebtedness as it became due. |
If a court were to find that the issuance of the Notes was a fraudulent transfer or conveyance, the court could void the payment obligations under the Notes, subordinate the Notes to presently existing and future indebtedness of the Issuer, or require the holders of
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the Notes to repay any amounts received. In the event of a finding that a fraudulent transfer or conveyance occurred, you may not receive any repayment on the Notes. Further, the avoidance of the Notes could result in an event of default with respect to our other indebtedness that could result in acceleration of that indebtedness.
In addition, any payment by the Issuer pursuant to the Notes made at a time the Issuer was found to be insolvent could be voided and required to be returned to the or to a fund for the benefit of the Issuer’s creditors if such payment is made to an insider within a one-year period prior to a bankruptcy filing or within 90 days for any outside party and such payment would give such insider or outsider party more than such party would have received in a distribution under the Bankruptcy Code, in a hypothetical Chapter 7 case.
Finally, as a court of equity, the bankruptcy court may subordinate the claims in respect of the Notes to other claims against the Issuer under the principle of equitable subordination if the court determines that (1) the holder of the Notes engaged in some type of inequitable conduct, (2) the inequitable conduct resulted in injury to our other creditors or conferred an unfair advantage upon the holders of the Notes, and (3) equitable subordination is not inconsistent with the provisions of the Bankruptcy Code.
If a bankruptcy petition was filed by or against us, the allowed claim for the Notes may be less than the principal amount of the Notes stated in the Indenture.
If a bankruptcy petition was filed by or against us under the Bankruptcy Code after the issuance of the Notes, the claim by any holder of the Notes for the principal amount thereof may be allowed in an amount equal to the sum of:
| • | the original issue price of the Notes; and |
| • | that portion of the stated principal amount of the Notes that exceeds the issue price thereof, if any, that does not constitute “unmatured interest” for the purposes of the Bankruptcy Code. |
Any such discount that was not amortized as of the date of the bankruptcy filing would constitute unmatured interest, which is not allowable as part of a bankruptcy claim under the Bankruptcy Code. Accordingly, holders of the Notes under these circumstances may receive an amount that is less than the principal amount thereof stated in the Indenture.
The Compound Interest Notes will be, and the Cash Interest Notes may be, issued with original issue discount for U.S. federal income tax purposes.
Because stated interests on the Compound Interest Notes will be paid in the form of an increase in the principal amount of the Compound Interest Notes, no stated interest payments on the Compound Interest Notes will be treated as “qualified stated interests” for U.S. federal income tax purposes. As a result, the Compound Interest Notes will be treated as having been issued with OID for U.S. federal income tax purposes in an amount in an amount equal to the excess of the total payments of principal and stated interest on the Compound Interest Notes over their issue price. In addition, Cash Interest Notes may be issued with OID for U.S. federal income tax purposes. In the event a Note is issued with OID, U.S. holder of such Note generally will be required to include OID in gross income (as ordinary income) on an annual basis under a constant yield accrual method, regardless of such U.S. holder’s regular method of accounting for U.S. federal income tax purposes. As a result, such U.S. holder will generally include any OID in income in advance of the receipt of cash attributable to such income. For more information, see “Certain Material U.S. Federal Income Tax Considerations.”
Risks Relating to Our Status as a Public Reporting Company
We will incur significant increased costs and become subject to additional regulations and requirements as a result of becoming a public reporting company, and our management will be required to devote substantial time to new compliance matters.
As a public reporting company, we will incur significant legal, regulatory, finance, accounting, investor relations, and other expenses that we have not incurred as a private company, including costs associated with public company reporting requirements. We also have incurred and will continue to incur costs associated with the Sarbanes-Oxley Act of 2002 (“SOX”) and the Dodd-Frank Wall Street Reform and Consumer Protection Act, and related rules implemented by the SEC. The expenses incurred by public reporting companies for reporting and corporate governance purposes have been increasing. We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly, although we are currently unable to estimate these costs with any degree of certainty. Our management will need to devote a substantial amount of time to ensure that we comply with all of these requirements, diverting the attention of management away from revenue-producing activities. These laws and regulations also could make it more difficult or costly for us to obtain certain types of insurance, including director and officer liability insurance, and we may be forced to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. These laws and regulations could also make it more difficult for us to attract and retain qualified persons to serve as our executive officers. Furthermore, if we are unable to satisfy our obligations as a public reporting company, we could be subject to fines, sanctions, and other regulatory action and potentially civil litigation.
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Furthermore, there is no minimum amount of Notes that must be sold before the proceeds received from the sale of a Note in this offering may be used by us in our operations. As a result, if we sell substantially less than all of the Notes we are offering, the costs we incur to comply with the rules of the SEC regarding financial reporting and other fixed costs (such as those relating to this offering) will be a larger percentage of our revenue and may reduce our financial performance and our ability to fulfil our obligations under the Notes.
Failure to comply with requirements to design, implement, and maintain effective internal controls could have a material adverse effect on our business.
We have not previously been required to evaluate our internal control over financial reporting in a manner that meets the standards of public reporting companies required by Section 404(a) of SOX (“Section 404”). As a public reporting company, we will be subject to significant requirements for enhanced financial reporting and internal controls. The process of designing and implementing effective internal controls is a continuous effort that requires us to anticipate and react to changes in our business and the economic and regulatory environments and to expend significant resources to maintain a system of internal controls that is adequate to satisfy our reporting obligations as a public reporting company. If we are unable to establish or maintain appropriate internal financial reporting controls and procedures, it could cause us to fail to meet our reporting obligations on a timely basis, result in material misstatements in our consolidated financial statements, and harm our results of operations. In addition, we will be required, pursuant to Section 404, to furnish a report by management on, among other things, the effectiveness of our internal control over financial reporting in the second annual report following the completion of this offering. This assessment will need to include disclosure of any material weaknesses identified by our management in our internal control over financial reporting. The rules governing the standards that must be met for our management to assess our internal control over financial reporting are complex and require significant documentation, testing, and possible remediation. Testing and maintaining internal controls may divert our management’s attention from other matters that are important to our business.
In connection with the implementation of the necessary procedures and practices related to internal control over financial reporting, we may identify deficiencies that we may not be able to remediate in time to meet the deadline imposed by SOX for compliance with the requirements of Section 404. In addition, we may encounter problems or delays in completing the remediation of any deficiencies identified by us or our independent registered public accounting firm in connection with the issuance of their attestation report. Our testing, or the subsequent testing (if required) by our independent registered public accounting firm, may reveal deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses. Any material weaknesses could result in a material misstatement of our annual or quarterly financial statements or disclosures that may not be prevented or detected.
Specifically, in connection with the audits of our financial statements as of and for the years ended December 31, 2022, 2023, and 2024, our auditors identified several material weaknesses, including material weaknesses concerning our internal control over financial reporting. These material weaknesses in internal controls were caused by inadequate separation of duties of our management within key financial areas. Other material weaknesses that were identified pertained to our lack of testing over our accounting systems, absence of a board of directors or an audit committee, improper use of accrual accounting, improper controls over the depletion calculation of proved and probable undeveloped reserves, and our use of an inadequate payroll reporting system. Any steps we take to enhance our internal control environment and address the underlying cause of our material weaknesses may not be sufficient to remediate such material weaknesses or to avoid the identification of additional material weaknesses in the future.
We may not be able to conclude on an ongoing basis that we have effective internal control over financial reporting in accordance with Section 404, or our independent registered public accounting firm may not issue an unqualified opinion. If we are unable to remediate the identified material weaknesses, identify additional material weaknesses in the future, or otherwise fail to maintain an effective system of internal controls, or our independent registered public accounting firm is unable to provide us with an unqualified report (to the extent it is required to issue a report), investors could lose confidence in our reported financial information, which could have a material adverse effect on our business, results of operations, and financial condition.
We identified certain misstatements to our previously issued financial statements and have restated certain of our consolidated financial statements, which may create additional risks and uncertainties.
On September 12, 2024, our management determined that our audited consolidated financial statements for the fiscal year ended December 31, 2022 (the “GAAS 2022 Audited Financial Statements”), contained in our Annual Report on Form 1-K for that year, which was filed in compliance with our offerings under Regulation A, should no longer be relied upon due to certain errors in the GAAS 2022 Audited Financial Statements as addressed in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 250. We previously filed our Annual Report on Form 1-K for the fiscal year ended December 31, 2023 (the “2023 Form 1-K”) with the SEC on April 30, 2024, which filing contained corrected financial information for the fiscal year ended December 31, 2022. On September 26, 2024, we amended our 2023 Form 1-K (the “Form 1-K/A”) to reflect that we had restated the GAAS 2022 Audited Financial Statements.
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Subsequently, on March 7, 2025, our management concluded that each of (i) of our previously issued audited consolidated financial statements as of and for the fiscal years ended December 31, 2023 and 2022 (the “2023 and 2022 Audited Financial Statements”) contained in the Form 1-K/A and (ii) our previously issued unaudited condensed consolidated financial statements for the fiscal semiannual periods ended June 30, 2024 and 2023 (the “Semiannual Unaudited Financial Statements” and, together with the 2023 and 2022 Audited Financial Statements, the “Existing Financial Statements”) contained in our Semiannual Report on Form 1-SA/A for the fiscal semiannual period ended June 30, 2024 (the “Form 1-SA/A”), filed with the SEC on September 26, 2024, should no longer be relied upon due to certain errors in the Existing Financial Statements, as addressed in FASB ASC Topic 250. In the Existing Financial Statements, we had immediately expensed debt issuance costs related to our unregistered bond offerings rather than amortizing them over the weighted-average term of the bonds, which resulted in overstated advertising and marketing expense, selling, general, and administrative expense, and payroll and payroll-related expense, and understated interest expense and loss on debt extinguishment. Additionally, in the Existing Financial Statements, we had previously expensed all interest costs, rather than capitalizing interest incurred on expenditures made in connection with our exploration and development projects as permitted under ASC 835-20, “Capitalized Interest,” resulting in us overstating our interest expense and understating our oil and gas properties, in corresponding amounts. Accordingly, on March 27, 2025, we further amended the Form 1-K/A and Form 1-SA/A to reflect that we had restated the Existing Financial Statements.
As a result of the restatements, we may become subject to a number of additional risks and uncertainties and unanticipated costs for accounting, legal, and other fees and expenses. We may become subject to legal proceedings brought by regulatory or governmental authorities, or other proceedings, as a result of the errors or the related restatements, which could result in a loss of investor confidence or other reputational harm, additional defense, and other costs. In addition, we cannot assure you that additional restatements of financial statements will not arise in the future. Any of the foregoing impacts, individually or in aggregate, may have a material adverse effect on our business, financial position, and results of operations.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
This prospectus contains forward-looking statements, which are statements regarding all matters that are not historical facts. They appear in a number of places throughout this prospectus and include statements regarding our current views, hopes, intentions, beliefs, or expectations concerning, among other things, our results of operations, financial condition, liquidity, prospects, growth, strategies, and position in the markets and the industries in which we operate. These forward-looking statements are generally identifiable by forward-looking terminology such as “guidance,” “expect,” “believe,” “anticipate,” “outlook,” “could,” “target,” “project,” “intend,” “plan,” “seek,” “estimate,” “should,” “will,” “would,” “approximately,” “predict,” “potential,” “may,” “continue,” and “assume,” as well as the negative version of such words, variations of such words, and similar expressions referring to the future.
Forward-looking statements are based on our beliefs, assumptions, and expectations, taking into account currently known market conditions and other factors. Our ability to predict results or the actual effect of future events, actions, plans, or strategies is inherently uncertain and involves certain risks and uncertainties, many of which are beyond our control. Our actual results and performance could differ materially from those set forth or anticipated in our forward-looking statements. Factors that could cause our actual results to differ materially from the expectations we describe in our forward-looking statements include, but are not limited to, the factors listed below and in the section of this prospectus entitled “Risk Factors.” When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. You are cautioned that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure you that such statements will be realized or that the forward-looking events and circumstances will occur. All forward-looking statements in this prospectus are made only as of the date this prospectus, based on information available to us as of the date of this prospectus, and we caution you not to place undue reliance on forward-looking statements in light of the risks and uncertainties associated with them.
The matters summarized below and elsewhere in this prospectus could cause our actual results and performance to differ materially from those set forth or anticipated in forward-looking statements:
| • | changes in the markets in which we compete; |
| • | increasing costs of capital expenditures to acquire and develop properties; |
| • | the continued success of our E&P operators; |
| • | delays in development of and higher capital expenditures in our estimated proved and probable undeveloped reserves; |
| • | developments in governmental regulations; |
| • | deviations between the current market value of estimated proved reserves and the present value of future net revenues from our proved reserves; |
| • | changes in current or future commodity prices; |
| • | the fact that reserve estimates depend on many assumptions that may turn out to be inaccurate and that any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves; |
| • | our ability to replace reserves; |
| • | cybersecurity attacks; |
| • | the development of our software and its ability to continue identifying productive assets; |
| • | our current or future levels of indebtedness; |
| • | repayment of our current or future indebtedness; |
| • | current and future litigation or other regulatory, administrative, or other legal proceedings; |
| • | the restatement of our financial statements; and |
| • | the other factors set forth in the section entitled “Risk Factors.” |
Except as required by law, we are under no duty to, and we do not intend to, update or review any of our forward-looking statements after the date of this prospectus, whether as a result of new information, future events or developments, or otherwise.
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Assuming we issue and sell all of the Notes offered by this prospectus, we estimate that the net proceeds we will receive from this offering will be $734.4 million, after deducting the Broker-Dealer Fee (calculated assuming $250.0 million aggregate principal amount of Notes sold per year following effectiveness of the registration statement of which this prospectus forms a part, which fee could total $5,025,000 if all Notes offered hereby are issued and sold), the sales commissions to be paid to certain of our non-executive personnel as compensation with respect to the sale of Notes (which fees could total $5,978,000 if all Notes offered hereby are issued and sold), and estimated offering expenses of approximately $4.6 million. Our net proceeds would increase to the extent we are able to sell Notes more quickly because of the structure of the Broker-Dealer Fee. See “Plan of Distribution—Broker-Dealer Compensation and Expenses.” We have not made any arrangement to place any of the proceeds from this offering in an escrow, trust, or similar account.
We currently expect to use the net proceeds from this offering (i) to make investments in PhoenixOp or to otherwise finance potential drilling and exploration operations, (ii) for continued acquisitions of mineral rights and non-operated working interests, as well as additional asset acquisitions, and (iii) for other general working capital needs, such as the payment of executive and employee salaries, general overhead, and operating costs, including payments on our debt, and the acquisition of assets in the oil and gas space that are not mineral rights or non-operated working interests. Our actual use of offering proceeds will depend on many considerations, including market conditions, but we currently expect to use the net proceeds from this offering as follows assuming we issue and sell all of the Notes offered by this prospectus:
| Expected Uses of Proceeds |
Approximate Percentage of Proceeds Used |
Approximate Amount of Proceeds Used |
||||||
| Investments in PhoenixOp |
70.0 | % | $ | 514,077,900 | ||||
| Acquisitions of mineral rights and non-operated working interests |
20.0 | % | 146,879,400 | |||||
| Working capital, other asset acquisitions, and general corporate purposes |
10.0 | % | 73,439,700 | |||||
|
|
|
|
|
|||||
| Total |
100.0 | % | $ | 734,397,000 | ||||
|
|
|
|
|
|||||
As of March 31, 2025, we had approximately $132.8 million of indebtedness maturing within one year, as described below:
| Series |
Interest Rate | Amount | ||||||
| Reg A Bonds |
9.0 | % | $ | 40,020,000 | ||||
| 2020 506(b) Bonds |
5.0 | % | 940,000 | |||||
| 2020 506(c) Bonds |
13.0%-15.0 | % | 1,448,000 | |||||
| December 2022 506(c) Bonds—Series B |
10.0 | % | 5,862,000 | |||||
| August 2023 506(c) Bonds—Series U, AA, and FF |
9.0%-10.0 | % | 84,497,000 | |||||
|
|
|
|||||||
| Total |
$ | 132,767,000 | ||||||
|
|
|
|||||||
We currently intend to utilize the net proceeds from this offering in the order set out in the preceding paragraph. However, the expected use of net proceeds from this offering represents our intentions based upon our present plans and business conditions, which could change in the future as our plans and business conditions evolve. In addition to the potential net proceeds from this offering of Notes, we have cash flow from operations, as well as multiple current and potential sources of financing, including under the Adamantium Loan Agreement and our offerings of debt securities pursuant to Regulation D, that can be utilized for the purposes described above, and so we cannot accurately predict whether and in what amounts the net proceeds from this offering of the Notes will be applied. In particular, to the extent we use any proceeds from this offering of the Notes to repay outstanding indebtedness, we cannot accurately predict which indebtedness we may repay with such proceeds, and in what amounts. We may find it necessary or advisable to use the net proceeds of this offering for other purposes, and we will have broad discretion in the application and specific allocations of the net proceeds of this offering. See “Risk Factors—Risks Related to the Notes and this Offering—We may invest or spend the proceeds of this offering in ways with which you may not agree.”
Furthermore, we will receive cash proceeds from this offering in varying amounts from time to time as Notes are sold, which makes it difficult for us to precisely calculate the allocation of net proceeds. Further, the Notes will have varying lengths of maturity, interest rates, and interest payment methods as described elsewhere in this prospectus, which makes it impossible to predict with any accuracy how much of the proceeds will be used to make payments of interest or principal on the Notes in any given year.
There is no minimum number or amount of Notes that we must sell to receive and use the proceeds from this offering, and we cannot assure you that all or any portion of the Notes will be sold. In the event that we do not raise sufficient proceeds from this offering, we may adjust our use of proceeds by limiting the speed of growth, delaying or canceling certain purchases or initiatives related to our drilling and production operations, and streamlining our operations, or we could terminate this offering and determine to pay back some or all of our debt, including the Notes. This might result in the Notes being repaid prior to maturity. See “Risk Factors.”
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The following table sets forth, as of December 31, 2024, our cash and cash equivalents and consolidated capitalization:
| • | on an actual basis; and |
| • | on an as-adjusted basis to give effect to the following, in each case, as if they had occurred on December 31, 2024: |
| • | the issuance of an additional $41.2 million of Adamantium Securities (and a corresponding amount borrowed under the Adamantium Loan Agreement) between January 1, 2025 and March 31, 2025; |
| • | the issuance of an additional $126.7 million of August 2023 506(c) Bonds between January 1, 2025 and March 31, 2025; |
| • | additional borrowings under the Fortress Credit Agreement of $25.0 million made after March 31, 2025; |
| • | the issuance of the Notes offered hereby; and |
| • | the repurchase or retirement of outstanding indebtedness between January 1, 2025 and March 31, 2025. |
You should read this table in conjunction with the information presented under the sections of this prospectus entitled “Summary—Summary Historical Consolidated Financial Information and Other Data,” “Use of Proceeds,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” as well as our consolidated financial statements and related notes included elsewhere in this prospectus.
| As of December 31, 2024 | ||||||||
| Actual | As-Adjusted | |||||||
| (in thousands) | ||||||||
| Cash and cash equivalents(1) |
$ | 120,814 | $ | 967,265 | ||||
| Debt: |
||||||||
| Fortress Credit Agreement(2) |
250,000 | 275,000 | ||||||
| Reg A Bonds(3) |
104,884 | 99,577 | ||||||
| Reg D Bonds: |
||||||||
| 2020 506(b) Bonds(4) |
940 | 940 | ||||||
| 2020 506(c) Bonds(5) |
2,098 | 1,448 | ||||||
| July 2022 506(c) Bonds(6) |
10,457 | 10,147 | ||||||
| December 2022 506(c) Bonds(7) |
68,974 | 65,888 | ||||||
| August 2023 506(c) Bonds(8) |
415,354 | 493,290 | ||||||
| Adamantium Securities(9) |
135,180 | 163,048 | ||||||
| Notes offered hereby(10) |
— | 750,000 | ||||||
|
|
|
|
|
|||||
| Total debt |
$ | 987,887 | $ | 1,859,338 | ||||
|
|
|
|
|
|||||
| Total members’ deficit |
$ | (34,058) | $ | (34,058) | ||||
|
|
|
|
|
|||||
| Total capitalization |
$ | 953,829 | $ | 1,825,280 | ||||
|
|
|
|
|
|||||
| (1) | As-adjusted reflects cash and cash equivalents as of December 31, 2024 after giving effect to (i) proceeds received from the issuance of additional Adamantium Securities and August 2023 506(c) Bonds between January 1, 2025 and March 31, 2025, (ii) cash used to repurchase or retire outstanding indebtedness between January 1, 2025 and March 31, 2025, and (iii) net proceeds received from the issuance of Notes assuming the entire amount offered hereby is issued and sold. As-adjusted cash and cash equivalents does not reflect the use of any such proceeds for capital expenditures or other corporate purposes, including repayment of debt. See “Use of Proceeds.” |
| (2) | The Fortress Credit Agreement provides for a $100.0 million term loan facility, borrowed in full on August 12, 2024, a $35.0 million delayed draw term loan facility, which was fully drawn on October 11, 2024, a $115.0 million term loan facility, borrowed in full on December 18, 2024, and a $25.0 million term loan facility, borrowed in full on April 16, 2025. The Fortress Credit Agreement also provides for an $8.5 million tranche of loans that represents a contingent principal obligation that is only due and payable (together with accrued interest thereon) upon certain conditions occurring, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing by the obligors thereunder. All obligations under the Fortress Credit Agreement are secured on a first-lien priority basis, subject to certain |
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| exceptions and excluded assets, by security interests in, and mortgages on, substantially all personal property and owned real property of Phoenix Equity and its subsidiaries. $150.0 million of the lenders’ commitments under the Fortress Credit Agreement and the loans thereunder are due and payable on December 31, 2026. The remainder of lenders’ commitments under the Fortress Credit Agreement and the loans thereunder are scheduled to terminate and mature, and be due and payable, on December 18, 2027. The Fortress Credit Agreement will constitute Senior Debt and will be contractually senior to the Notes. For a description of the terms of the Fortress Credit Agreement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement.” |
| (3) | The Reg A Bonds have a term of three years from the issue date and an interest rate of 9.0% per annum. The outstanding Reg A Bonds mature between April 2025 and June 2027. The Reg A Bonds will constitute Senior Debt and will be contractually senior to the Notes. For a description of the terms of the Reg A Bonds, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Reg D/Reg A Bonds.” |
| (4) | The 2020 506(b) Bonds have initial maturity dates ranging from one to four years from the issue date and an interest rate of 5.0% per annum. The outstanding 2020 506(b) Bonds mature in May 2025. The 2020 506(b) Bonds will constitute Senior Debt and will be contractually senior to the Notes. For a description of the terms of the 2020 506(b) Bonds, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Reg D/Reg A Bonds.” |
| (5) | The 2020 506(c) Bonds have maturity dates ranging from one to four years from the issue date and interest rates ranging from 13.0% to 15.0% per annum. The outstanding 2020 506(c) Bonds mature between September 2025 and June 2027. The 2020 506(c) Bonds will constitute Senior Debt and will be contractually senior to the Notes. For a description of the terms of the 2020 506(c) Bonds, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Reg D/Reg A Bonds.” |
| (6) | The July 2022 506(c) Bonds have a maturity date of five years from the issue date and an interest rate of 11.0% per annum. The outstanding July 2022 506(c) Bonds mature between July 2027 and December 2027. The July 2022 506(c) Bonds will constitute Senior Debt and will be contractually senior to the Notes. For a description of the terms of the July 2022 506(c) Bonds, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Reg D/Reg A Bonds.” |
| (7) | The December 2022 506(c) Bonds have maturity dates ranging from one to seven years from the issue date and interest rates ranging from 8.0% to 12.0% per annum. The outstanding December 2022 506(c) Bonds mature between April 2025 and October 2030. The December 2022 506(c) Bonds will be contractually subordinated to the Notes. For a description of the terms of the December 2022 506(c) Bonds, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Phoenix Reg D/Reg A Bonds.” |
| (8) | The August 2023 506(c) Bonds have maturity dates ranging from one to eleven years from the issue date and interest rates ranging from 9.0% to 14.0% per annum. The outstanding August 2023 506(c) Bonds mature between April 2025 and March 2036. The August 2023 506(c) Bonds are contractually subordinated to the Senior Reg D/Reg A Bonds and will be contractually subordinated to the Notes. For a description of the terms of the August 2023 506(c) Bonds, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Reg D/Reg A Bonds.” |
| (9) | Includes $156.0 million aggregate principal amount of Adamantium Bonds and $7.0 million aggregate principal amount of the Adamantium Secured Note. The Adamantium Bonds have maturity dates ranging from five to eleven years from the issue date and interest rates ranging from 13.0% to 16.0% per annum. The outstanding Adamantium Bonds mature between January 2029 and March 2036. The Adamantium Secured Note initially matures in November 2031, has an interest rate of 16.5% per annum, and is secured by Adamantium’s rights under the Adamantium Loan Agreement. The Adamantium Securities will be structurally senior to the Notes to the extent of the value of Adamantium’s assets, including the collateral securing the Adamantium Loan Agreement. Adamantium may, but is not guaranteed to, issue $400.0 million in aggregate principal amount of Adamantium Bonds to fund advances to the Issuer and PhoenixOp pursuant to the Adamantium Loan Agreement. The Adamantium Debt will constitute Senior Debt and will be contractually senior to the Notes. For a description of the terms of the Adamantium Debt, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Adamantium Debt.” |
| (10) | Represents the aggregate principal amount of the Notes offered hereby. There is no minimum number or amount of Notes that we must sell to receive and use the proceeds from this offering, and we cannot assure you that all or any portion of the Notes will be sold. In the event that we do not raise sufficient proceeds from this offering, we may adjust our use of proceeds by limiting the speed of growth, delaying or canceling certain purchases or initiatives related to our drilling and production operations, and/or streamlining our operations, or we could terminate this offering and/or determine to pay back some or all of our debt, including the Notes. This might result in the Notes being repaid prior to maturity. See “Risk Factors—Risks Related to the Notes and this Offering—We may invest or spend the proceeds of this offering in ways with which you may not agree” and “Risk Factors—Risks Related to the Notes and this Offering—We may redeem your Notes at our option, which may adversely affect your return.” |
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following management’s discussion and analysis of financial condition and results of operations in conjunction with “Prospectus Summary—Summary Historical Financial and Other Data,” our consolidated financial statements, and the related notes thereto included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs, and expected performance. These forward-looking statements are dependent upon events, risks, and uncertainties that may be outside of our control. Our actual results could differ materially from those disclosed in these forward-looking statements. Factors that could cause or contribute to such differences include those described in “Risk Factors,” “Cautionary Statement Regarding Forward-Looking Statements,” and elsewhere in this prospectus. Our historical results are not necessarily indicative of the results that may be expected for any period in the future.
Overview
We operate in the oil and gas industry and execute on a three-pronged strategy involving (i) direct drilling operations of operated working interests (ii) the acquisition of royalty assets, and (iii) the acquisition of non-operated working interest assets. Our direct drilling operations are currently primarily focused on development efforts in the Williston Basin in North Dakota and Montana and the Powder River and Denver Julesburg Basins in Wyoming. Our royalty and working interest acquisitions center around a variety of assets, including mineral interests, leasehold interests, overriding royalty interests, and perpetual royalty interests. These efforts have historically targeted assets in the Williston, Permian, Powder River, Uintah, and DJ Basins. We are agnostic as to geography and prioritize operational and asset potential when executing on our strategy.
We began operations in 2019 with the development of our specialized software system, which we have designed and improved over time to support our ability to identify, analyze, underwrite, transact, and manage our oil and gas assets. In 2019, we acquired our first mineral interest asset and began to generate revenue. In 2020, we expanded our operations and team to include specialists across a variety of key focus areas. From 2020 to 2024, we experienced significant growth in operations. For example, in 2020, the E&P operators of our properties operated 725 gross and 2.8 net productive development wells on the acreage underlying our mineral and royalty interests, and the total acreage underlying our gross and net royalty interests was 177,824 and 1,506, respectively. In the four years since then, the E&P operators of our properties have operated an additional 6,312 gross and 75.1 net productive development wells on the acreage underlying our mineral and royalty interests, of which approximately 463 gross and 43.2 net productive developments wells were drilled in 2024 alone. As of December 31, 2024, we had 3,962,065 and 531,120 acres underlying our gross and net royalty interests, respectively, as compared to 177,824 and 1,506 acres underlying our gross and net royalty interests, respectively, at December 31, 2020. Furthermore, our total production for the year ended December 31, 2020 was under 0.2 million Boe as compared to over 4.7 million Boe for the year ended December 31, 2024. In the same period, our number of employees grew from 21 at December 31, 2020 to 135 at December 31, 2024. Additionally, we commenced direct drilling operations and spudded our first wells in the third quarter of 2023 and drilled a total of 42 gross and 38.6 net productive development wells in 2024. We expect these direct drilling operations to be a core component of our business strategy going forward.
Since our initial mineral interest asset acquisition in 2019, we have leveraged our specialized software system and experienced management team to identify asset opportunities that fit our desired criteria and potential for returns. While we evaluate and acquire a wide variety of assets, we have historically prioritized assets with potential for high monthly recurring cashflows and primarily target assets that have a potential payback within the short to medium term and long-term cashflows.
Since 2019, we have completed 3,074 mineral, royalty, and leasehold interest acquisitions from landowners and other mineral interest owners, representing approximately 531,120 NRAs of royalty assets and 476,473 of NMAs of leasehold assets as of December 31, 2024. Over that same period, in addition to completing numerous small transactions, we completed more than 56 transactions larger than 1,000 NMAs that account for approximately 72% of our NMAs. We have acquired mineral, royalty, and leasehold interests from individuals, families, trusts, partnerships, small minerals aggregators, minerals brokers, large private minerals companies, private oil and gas E&P companies, and public minerals companies. We also actively manage our portfolio of assets and, as of December 31, 2024, have sold 3,152 NMAs since 2019.
Following the acquisition of an asset, we typically share in the proceeds of the natural resources extracted and sold by a third-party E&P operator. For certain assets, we operate our own direct drilling operations through PhoenixOp. See “Risk Factors—Risks Related to Our Business and Operations—We, through our investment in PhoenixOp and future assignment of oil and gas properties to PhoenixOp, conduct direct drilling and extraction activities. Such activities pose additional risks to us.”
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For the years ended December 31, 2022, 2023, and 2024, we had revenue of $54.6 million, $118.1 million, and $281.2 million, respectively, net income (loss) of $5.7 million, $(16.2) million, and $(24.8) million, respectively, and EBITDA of $29.7 million, $65.9 million, and $150.7 million, respectively. As of December 31, 2022, 2023, and 2024 we had total assets of $157.0 million, $493.2 million, and $1,029.1 million, respectively, total liabilities of $148.3 million, $498.0 million, and $1,063.1 million, respectively (inclusive of total indebtedness of $117.4 million, $447.9 million, and $987.9 million, respectively), and retained earning (accumulated deficit) of $6.5 million, $(9.7) million, and $(34.5) million, respectively. In 2023 and 2024, we incurred a significant amount of debt in order to accelerate the growth of our business by acquiring additional assets and establishing our direct drilling operations. As a result, our cash flows from operations alone would not have been sufficient to service required cash interest and principal payment obligations under our then-existing debt in 2023 and 2024. Furthermore, as of December 31, 2024, we estimate that we will need to make approximately $749.3 million and $3,224.8 million in capital expenditures to develop all our proved and probable undeveloped reserves, respectively, and that we will need to raise approximately $658.9 million in additional capital through the end of 2028 to fund such development. Although we expect our cash flows from operations to be sufficient to service cash interest and principal payment obligations under our debt for the foreseeable future, there can be no assurance as to the sufficiency of our cash flows for that purpose, and we do not expect such cash flows alone to be adequate to fund both our debt service obligations and the development of our reserves. Therefore, we expect to require additional capital to fund our growth and may require additional liquidity to service our debt. As a result, we may use the proceeds of additional debt, including the Notes offered hereby, to make interest and principal payments on our existing debt. See “Risk Factors—Risks Related to Our Business and Operations—The acquisition and development of our properties, directly or through our third-party E&P operators, will require substantial capital, and we and our third-party E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all, including as a result of increases in the cost of capital resulting from Federal Reserve policies in the past few years and otherwise,” “Risk Factors—Risks Related to Our Indebtedness—Despite our current level of indebtedness, we will still be able to incur substantially more debt. This could further exacerbate the risks to our financial condition described above,” “Risk Factors—Risks Related to Our Indebtedness—We may not be able to generate sufficient cash to service all of our existing and future indebtedness, including the Notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful,” “Risk Factors—Risks Related to the Notes and this Offering—We may invest or spend the proceeds of this offering in ways with which you may not agree” and “Use of Proceeds.”
Our Segments
We operate under three segments: mineral and non-operating; operating; and securities. Our mineral and non-operating segment comprises our operations for the acquisition of mineral interests and non-operated working interests in oil and gas properties, through which we share in the proceeds of the natural resources extracted and sold by the operator. Our operating segment comprises our operations related to our drilling, extraction, and production activities, which today are conducted through PhoenixOp. Our securities segment comprises our operations related to our capital raising activities associated with our debt securities offerings. Our management evaluates our performance and allocates resources based in part on segment operating profit, which is calculated as total segment revenue less operating expenses attributable to the segment, which includes allocated corporate costs.
Sources of Our Revenue
Our revenues have historically primarily constituted mineral and royalty payments received from our E&P operators based on the sale of crude oil, natural gas, and NGL production from our interests. In 2024, we commenced sales of crude oil, natural gas, and NGL and began generating product sales in our operating segment through our wholly owned subsidiary, PhoenixOp, which was formed for the purposes of drilling, extracting, and operating producing wells. Product sales accounted for over 45% of our total revenues for the year ended December 31, 2024, and we expect to derive a greater portion of our total revenues from product sales of crude oil, natural gas, and NGL to PhoenixOp’s customers in the future. Our revenues may vary significantly from period to period because of changes in commodity prices, production mix, and volumes of production sold by our E&P operators, including PhoenixOp. We also derive revenues from performing saltwater disposal services on wells operated by PhoenixOp, as well as redemption fees charged to investors, generally in connection with the early redemption of their investments. Other revenue in the securities segment is derived almost exclusively from intersegment interest expense to the mineral and non-operating segment and the operating segment, and is eliminated in consolidation.
Principal Components of Our Cost Structure
As a mineral, royalty, and non-operated working interest owner, we may incur lease operating expenses and our proportionate share of production, severance, and ad valorem taxes. In those circumstances, revenues are recognized net of production taxes and post-production expenses. Through PhoenixOp’s operations, we also incur certain production costs, including gathering, processing, and transportation costs, which are presented as a component of cost of sales on our consolidated statements of operations. Shared corporate costs that are overhead in nature and not directly associated with any one of our segments, including certain general and administrative expenses, executive or shared-function payroll costs, and certain limited marketing activities, are allocated to our segments based on usage and headcount, as appropriate. Cost of sales and depreciation, depletion, and amortization are not applicable to the securities segment.
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Cost of Sales
Lease Operating Expenses
We incur lease operating expenses through: (i) our ownership of non-operated working interests, paying our pro rata share of cost of labor, equipment, maintenance, saltwater disposal, workover activity, and other miscellaneous costs; and (ii) PhoenixOp, where such costs are directly incurred through our own drilling and extraction activities. We generally expect that these expenses will increase as our number of mineral interest and non-operated working interests in oil and gas properties increase, and as our operating activities on wells operated by PhoenixOp continue to increase.
Production and Ad Valorem Taxes
Production taxes are paid at fixed rates on produced crude oil, natural gas, and NGL based on a percentage of revenues from our volume of products sold, established by federal, state, or local taxing authorities. Where we utilize third-party operators, the E&P companies that operate on our interests withhold and pay our pro rata share of production taxes on our behalf. We directly pay ad valorem taxes in the counties where our properties are located. Ad valorem taxes are generally based on the appraised value of our crude oil, natural gas, and NGL properties. We generally expect that these expenses will increase as our number of mineral interest and non-operated working interests in oil and gas properties increase, as we commence oil and gas operating activities on operated properties, and as production from such properties increases.
Production Costs
Production costs include gathering, processing, and transportation costs that we incur to gather and transport our oil and gas production to a point of sale. We generally expect that these costs will increase as our activities in our operating segment increase and as our oil and gas operating activities result in increased production volumes. For example, our production costs increased throughout 2024 as our oil and gas operating activities came online and PhoenixOp operated production from our first operated properties.
Depreciation, Depletion, and Amortization
Depreciation, depletion, and amortization is the systematic expensing of the capitalized costs incurred to acquire, explore, and develop crude oil, natural gas, and NGL. We follow the successful efforts method of accounting, pursuant to which we capitalize the costs of our proved crude oil, natural gas, and NGL mineral interest properties, which are then depleted on a unit-of-production basis based on proved crude oil, natural gas, and NGL reserve quantities. Our estimates of crude oil, natural gas, and NGL reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data, as well as the projection of future rates of production. Any significant variance in these assumptions could materially affect the estimated quantity of the reserves, which could affect the rate of depletion related to our crude oil, natural gas, and NGL properties. Depreciation, depletion, and amortization also includes the expensing of office leasehold costs and equipment. We expect depletion to continue to increase in subsequent periods as our gross production of oil, gas, and other products increases.
Selling, General, and Administrative Expense
Selling, general, and administrative expenses consist of costs incurred related to overhead, office expenses, and fees for professional services such as audit, tax, legal, and other consulting services. In connection with this offering, we expect to incur additional costs related to being a public company. See “—Factors Affecting the Comparability of Our Financial Condition and Results of Operations.”
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General and administrative expenses are allocated directly to a segment when there is a clear cost-benefit relationship between the expense and the segment that received the benefit. All other costs are aggregated within pools and allocated to each segment using a level-of-effort formula. We expect general and administrative expense to continue to increase period over period as we continue to grow and capitalize on opportunities within each segment; however, we do expect the percentage of growth to begin to decline as our business matures.
Payroll and Payroll-Related Expense
Payroll and payroll-related expenses consist of personnel costs for executive and employee compensation and related benefits. Payroll and payroll-related expenses are allocated directly to the segment associated with a respective employee, with the exception of corporate personnel, whose costs are allocated to the segments based on a reasonable level-of-effort formula. We expect payroll expenses to continue to increase period over period as we continue to grow; however, we do expect the percentage of growth to begin to decline as our business matures.
Advertising and Marketing Expense
We incur advertising and marketing costs primarily in our securities segment. Advertising and marketing costs include third-party services related to public relations, market research, and the development of strategic initiatives, brand messaging, and communication materials that are produced for our investors to generate greater awareness and promote investor engagement. We expect advertising and marketing costs to vary from period to period as we undertake targeted campaigns or initiatives. Advertising and marketing costs are expensed as incurred.
Interest Expense
We have financed a significant portion of our working capital requirements and acquisitions with borrowings under credit facilities and the issuance of debt securities. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under credit facilities and holders of our debt securities and amortization of debt discount and debt issuance costs in interest expense in our consolidated statements of operations. Interest expense is primarily incurred within the securities segment and allocated to the mineral and non-operating segment and the operating segment based on the carrying value of the oil and gas properties owned by the respective segment at the balance sheet date. Allocated intersegment interest expense is eliminated in consolidation. We expect interest expense to continue to increase period over period as we raise additional capital to meet our objectives.
How We Evaluate Our Operations
We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:
| • | volumes of oil, natural gas, and NGL produced; |
| • | number of producing wells, spud wells, and permitted wells; |
| • | commodity prices; and |
| • | revenue and EBITDA. |
Volumes of Oil, Natural Gas, and NGL Produced
In order to track and assess the performance of our assets, we monitor and analyze our production volumes from our mineral and royalty interests. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.
Producing Wells, Spud Wells, and Permitted Wells
In order to track and assess the performance of our assets, we monitor the number of permitted wells, spud wells, completions, and producing wells on our mineral and royalty interests in an effort to evaluate near-term production growth.
Commodity Prices
Historically, oil, natural gas, and NGL prices have been volatile and may continue to be volatile in the future. During the past five years, the posted price for West Texas Intermediate (“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. Over the same period, the Henry Hub spot market for natural gas has ranged from a low of $1.21 per MMBtu in November 2024 to a high of $23.86 per MMBtu in February 2021. Recently, in April 2025, oil and natural gas prices dropped significantly, going from $71.20 per barrel and $3.95 per MMBtu as of April 1, 2025 to $58.21 per barrel and $3.33 per MMBtu as of April 30, 2025, respectively. Lower prices may not only decrease our revenues, but also potentially the amount of oil, natural gas, and NGL that our operators can produce economically. See “Risk Factors—Risks Related to Our Business and Operations—Our business is sensitive to the price of oil and gas and sustained declines in prices may adversely affect our financial position, financial results, cash flows, access to capital, and ability to grow.”
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. 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 American Petroleum Institute gravity, and the presence and concentration of impurities, such as sulfur. Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.
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Natural Gas. The U.S. New York Mercantile Exchange (“NYMEX”) price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual 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 Btu 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 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 limitations on transportation in certain regions, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets.
NGL. NGL pricing is generally tied to the price of oil, but varies based on differences in liquid components and location.
EBITDA
We calculate EBITDA by adding back to net income (loss), interest income and expense and depreciation, depletion, amortization, and accretion expense for the respective periods. EBITDA is a non-GAAP supplemental financial measure used by our management to understand and compare our operating results across accounting periods, for internal budgeting and forecasting purposes, and to evaluate financial performance and liquidity, in each case, without regard to financing methods, capital structure, or historical cost basis. EBITDA is presented as supplemental disclosure as we believe it provides useful information to investors and others in understanding and evaluating our results, prospects, and liquidity period over period, including as compared to results of other companies. EBITDA does not represent and should not be considered an alternative to, or more meaningful than, net income (loss), income from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with GAAP as measures of financial performance. EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Other companies may not publish this or similar metrics, and our computation of EBITDA may differ from computations of similarly titled measures of other companies.
Factors Affecting the Comparability of Our Financial Condition and Results of Operations
Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, primarily for the following reasons:
Acquisitions
As of December 31, 2024, we had completed 3,074 acquisitions from landowners and other mineral interest owners. There is typically a lag (e.g., six to eighteen months) between when acquisitions are made and when those investments generate meaningful revenue. As a result, many of the investments we made in 2023 began generating revenue in 2024, and we anticipate the same delayed effect will occur from 2024 to 2025 and in the future as we continue to invest in new opportunities. We intend to pursue potential accretive acquisitions of additional mineral and royalty interests by capitalizing on our specialized software, as well as our management team’s expertise and relationships. 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 make may reduce, rather than increase, our cash flows and ability to make further investments in our business and satisfy our debt obligations, including with respect to the Notes. Additionally, it is possible that we will effect divestitures of certain of our assets. Any such acquisitions or divestitures affect the comparability of our results of operations from period to period.
Supply, Demand, Market Risk, and Their Impact on Oil Prices
Commodity prices are the most significant factor impacting our revenues, profitability, operating cash flows, the amount of capital we invest in our business, and redemption of our debt. The oil industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2021 through December 31, 2024, prices for crude oil reached a high of $123.70 per Bbl and a low of $47.47 per Bbl. Over the same time period, natural gas prices reached a high of $23.86 per MMBtu and a low of $1.21 per MMBtu. These prices experience large swings, sometimes on a day-to-day or week-to-week basis. For the year ended December 31, 2024, the average NYMEX crude oil and natural gas prices were $76.63 per Bbl and $2.19 per MMBtu, respectively, representing decreases of 1.2% and 13.5%, respectively, from the average NYMEX prices for the year ended December 31, 2023. For the year ended December 31, 2023, the average NYMEX crude oil and natural gas prices were $77.58 per Bbl and $2.53 per MMBtu, respectively, representing decreases of 18.3% and 60.7%, respectively, from the average NYMEX prices for the year ended December 31, 2022. Recently, in April 2025, oil and natural gas prices dropped significantly, going from $71.20 per barrel and $3.95 per MMBtu as of April 1, 2025 to $58.21 per barrel and $3.33 per MMBtu as of April 30, 2025, respectively.
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Commodity prices over that time period have been volatile and will likely continue to be volatile in the future. Crude oil prices over that time period were impacted by a variety of factors affecting current and expected supply and demand dynamics, including strong demand for crude oil, domestic supply reductions, OPEC control measures, market disruptions resulting from broader macroeconomic drivers, such as the Russia-Ukraine war, sanctions on Russia, and conflicts and tensions in the Middle East. More recently, we believe that commodity prices, including crude oil prices, have been impacted by uncertainties regarding U.S. trade policies and concerns over slowing economic growth and resulting reductions in estimated oil consumption. Market prices for NGL are influenced by the components extracted, including ethane, propane, and butane and natural gasoline, among others, and the respective market pricing for each component. Other factors impacting supply and demand include weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, and the strength of the U.S. dollar, as well as other factors, the majority of which are outside of our control.
We expect commodity price volatility to continue given the complex global dynamics of supply and demand that exist in the market. See “Risk Factors—Risks Related to Our Business and Operations—Our business is sensitive to the price of oil and gas and sustained declines in prices may adversely affect our financial position, financial results, cash flows, access to capital, and ability to grow” for further discussion on how volatility in commodity prices could impact us.
We are currently monitoring our operations and industry developments, including our drilling operations and production plans, in light of recent changes in the commodity price environment and industry volatility. While we believe the company is well-positioned to navigate a lower-price environment, in the event of a prolonged period of lower commodity prices, our cash flows from operations would decrease and we may determine to adjust our business plan by adjusting capital expenditures, decreasing drilling operations, and/or reducing production plans, among other actions. Such actions and circumstances would also impact our revenue, operating expenses, and liquidity. For example, we may also be required to raise additional capital, above our current expectations, in order to fully realize our current or adjusted business plan.
We are also monitoring the impact of the tariffs announced by the United States federal government in 2025. While there is significant uncertainty as to the duration of these and any further tariffs, and the impacts these tariffs and any corresponding retaliatory tariffs will have on the oil and gas industry and on commodity prices, we do not currently expect that the financial impact of the tariffs will be material to capital expenditures or operating expenses in 2025. We expect the primary impact of the tariffs to be on certain drilling input costs, such as steel casing.
Reporting and Compliance Expenses
In connection with this offering, we expect to incur incremental non-recurring costs related to our transition to being a public company, including the costs of this offering and the costs associated with the initial implementation of our improved internal controls and testing. We also expect to incur additional significant and recurring expenses as a public reporting company, such as expenses associated with SEC reporting requirements, including annual and quarterly reports, SOX compliance expenses, costs associated with the employment of additional personnel, increased independent auditor fees, increased legal fees, investor relations expenses, and increased director and officer insurance expenses. Certain of these general and administrative expenses are not included in our historical financial statements.
Derivatives
To reduce the impact of fluctuations in oil, NGL, and natural gas prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil, NGL, and natural gas production through various transactions that limit the risks of fluctuations of future prices. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flows from operations.
Impairment
We evaluate our producing properties for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. When assessing proved properties for impairment, we compare the expected undiscounted future cash flows of the proved properties to the carrying amount of the proved properties to determine recoverability. If the carrying amount of proved properties exceeds the expected undiscounted future cash flows, the carrying amount is written down to the properties’ estimated fair value, which is measured as the present value of the expected future cash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, and a risk-adjusted discount rate. The proved property impairment test is primarily impacted by future commodity prices, changes in estimated reserve quantities, estimates of future production, overall proved property balances, and depletion expense. If pricing conditions decline or are depressed, or if there is a negative impact on one or more of the other components of the calculation, we may incur proved property impairments in future periods. For example, commodity prices remain volatile and have generally decreased over the course of 2025. As a result, we may be required to incur such impairments in future periods.
Debt and Interest Expense
We have a significant amount of debt and may incur significantly more in the future to finance, among other things, acquisitions, investments in PhoenixOp, and payments on our debt. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Increases in interest rates as a result of inflation and a potentially recessionary economic environment in the United States could have a negative effect on the demand for oil and natural gas, as well as our borrowing costs.
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PhoenixOp
Our wholly owned subsidiary, PhoenixOp, was formed to manage and conduct drilling, extraction, and related oil and gas operating activities. PhoenixOp commenced the spudding of its first wells in the third quarter of 2023. The first five wells completed by PhoenixOp began production in the first quarter of 2024, and the next five wells began production in the second quarter of 2024. As of December 31, 2024, PhoenixOp placed an additional 22 wells in production, and had an additional 39 wells in various stages of development. Given its limited operations in 2023, PhoenixOp’s revenue was $1.2 million for that year. For the year ended December 31, 2024, PhoenixOp’s operations increased and its revenue was $125.6 million. As more wells continue to commence production, and more properties are contributed to PhoenixOp for potential future production, we expect to derive a greater portion of our total revenues from PhoenixOp and our operating segment. We believe these operations represent a significant source of potential revenue growth. In addition, as PhoenixOp is an E&P operator, it incurs greater operating costs related to drilling, extraction, and related oil and gas operating activities than our mineral and non-operating activities. As a result, we expect our operating costs to increase as PhoenixOp’s operations expand and become a greater portion of our overall business. These operations continue to execute well against our business plan and we expect these trends to continue in 2025. We are currently monitoring PhoenixOp operations and industry developments in light of recent changes in the commodity price environment. While we believe these operations are well-positioned to navigate a lower-price environment, we may reduce operations, such as reducing rigs or completion crews, in response to prolonged periods of decreased commodity prices, which would reduce our revenue generated by PhoenixOp and could have an adverse effect on our business, financial condition, results of operations, and cash flows from operations.
2025 Outlook
The following table presents our current estimates of certain financial and operating results for the full year of 2025. These forward-looking statements reflect our expectations as of the date of this prospectus, and are subject to substantial uncertainty. Our results are inherently unpredictable, may fluctuate significantly, and may be materially affected by many factors, such as fluctuations in commodity prices, changes in global economic and geopolitical conditions, and changes in governmental regulations, among others. The following estimates are based on, among other things, our anticipated capital expenditures and drilling and operations programs, our ability to drill and complete wells consistent with our expectations, certain drilling, completion, and equipping cost assumptions, and certain well performance assumptions. In addition, achieving these estimates and maintaining the required drilling activity to achieve these estimates will depend on the availability of capital, the existing regulatory environment, commodity prices and differentials, rig and service availability, and actual drilling results, as well as other factors. Factors that could cause or contribute to changes of such estimates include those described in the sections entitled “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statement” presented elsewhere in this prospectus. If any of these risks and uncertainties actually occur or the assumptions underlying our estimates are incorrect, our actual operating results, costs and activities may be materially and adversely different from our expectations or guidance. For example, we are currently monitoring our operations and industry developments in light of recent changes in the commodity price environment and industry volatility. While we believe the company is well-positioned to navigate a lower-price environment, a prolonged period of commodity prices below those assumed for purposes of our business plan and current estimates would have an adverse effect on our business, financial condition, results of operations, cash flows from operations, and 2025 outlook. If we adjust our business plan in response to such events, we may subsequently revise our 2025 outlook to reduce our expected ranges. For example, in such event, our expected ranges for revenue, net income, EBITDA, and production would likely decrease. Further, our total outstanding debt may increase to the extent we are required to raise additional capital, above our current expectations, in order to fully realize our current or adjusted business plan. In addition, investors should recognize that the reliability of any guidance diminishes in as much as it involves estimates for figures farther in the future, and so the farther we are from the end of 2025 the more likely that our actual results will differ materially from our guidance. In light of the foregoing, investors are urged to put our guidance in context and not to place undue reliance upon it.
| As of and for the Year Ending December 31, 2025 |
||||||||
| (dollars in thousands) | Lower Range | Upper Range | ||||||
| Revenue(1) |
$ | 595,000 | $ | 625,000 | ||||
| Total operating expenses |
442,000 | 430,000 | ||||||
| Net income |
10,000 | 35,000 | ||||||
| Interest expense, net |
143,000 | 160,000 | ||||||
| Depreciation, depletion, amortization, and accretion expense |
157,000 | 180,000 | ||||||
|
|
|
|
|
|||||
| EBITDA(2) |
$ | 310,000 | $ | 375,000 | ||||
|
|
|
|
|
|||||
| Total outstanding debt(3) |
$ | 1,550,000 | $ | 1,800,000 | ||||
| Production: |
||||||||
| Crude oil (Bbls) |
8,231,000 | 8,404,000 | ||||||
| Natural gas (Mcf)(4) |
10,600,000 | 10,845,000 | ||||||
| NGLs (Bbls) |
396,000 | 406,000 | ||||||
|
|
|
|
|
|||||
| Total (Boe) (6:1) |
10,393,667 | 10,617,500 | ||||||
|
|
|
|
|
|||||
| Average daily production (Boe/d) (6:1) |
28,476 | 29,089 | ||||||
|
|
|
|
|
|||||
| (1) | Based on an average benchmark commodity price of $71.98/Bbl for crude oil and $3.94/Mcf for natural gas. Recently, in April 2025, oil and natural gas prices dropped significantly, going from $71.20 per barrel and $3.95 per MMBtu as of April 1, 2025 to $58.21 per barrel and $3.33 per MMBtu as of April 30, 2025, respectively. See “Risk Factors—Risks Related to Our Business and Operations—Our business is sensitive to the price of oil and gas and sustained declines in prices may adversely affect our financial position, financial results, cash flows, access to capital, and ability to grow.” |
| (2) | EBITDA is a non-GAAP financial measure. See “—Non-GAAP Financial Measures.” |
| (3) | Assumes repayment of an aggregate of $103.3 million of debt outstanding as of December 31, 2024 and maturing prior to December 31, 2025, without any prepayments of debt not maturing prior to December 31, 2025, and the issuance of between $665.4 million and $915.4 million of new debt during the year ending December 31, 2025. |
| (4) | Revenue from natural gas has not historically represented a significant portion of our total revenues. We anticipate this trend to continue and, as a result, we currently estimate 844 MMcf to 866 MMcf of natural gas volumes (of the production range presented above) will be sold and recognized as revenues for the year ending December 31, 2025. |
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Results of Operations for the Year Ended December 31, 2024 Compared to the Year Ended December 31, 2023
The following table summarizes our consolidated results of operations for the periods indicated:
| Year Ended December 31, | Change | |||||||||||||||
| (in thousands) | 2024 | 2023 (As Restated) |
$ | % | ||||||||||||
| Revenues |
||||||||||||||||
| Mineral and royalty revenues |
$ | 152,999 | $ | 118,088 | $ | 34,911 | 30 | % | ||||||||
| Product sales |
125,649 | — | 125,649 | NM | ||||||||||||
| Water services |
2,478 | — | 2,478 | NM | ||||||||||||
| Other revenues |
101 | 17 | 84 | 494 | % | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total revenues |
$ | 281,227 | $ | 118,105 | $ | 163,122 | 138 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating expenses |
||||||||||||||||
| Cost of sales |
$ | 63,947 | $ | 19,733 | $ | 44,214 | 224 | % | ||||||||
| Depreciation, depletion, amortization, and accretion |
85,977 | 34,228 | 51,749 | 151 | % | |||||||||||
| Advertising and marketing |
679 | 4,136 | (3,457 | ) | (84 | )% | ||||||||||
| Selling, general, and administrative |
29,167 | 14,314 | 14,853 | 104 | % | |||||||||||
| Payroll and payroll-related |
27,934 | 12,733 | 15,201 | 119 | % | |||||||||||
| Loss on sale of assets |
564 | — | 564 | NM | ||||||||||||
| Impairment expense |
564 | 974 | (410 | ) | (42 | )% | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total operating expenses |
$ | 208,832 | $ | 86,118 | $ | 122,714 | 142 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income from operations |
$ | 72,395 | $ | 31,987 | $ | 40,408 | 126 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Other expenses |
||||||||||||||||
| Interest income |
$ | 705 | $ | 66 | $ | 639 | 968 | % | ||||||||
| Interest expense |
(90,210 | ) | (47,882 | ) | (42,328 | ) | (88 | )% | ||||||||
| Loss on derivatives |
(5,986 | ) | (32 | ) | (5,954 | ) | 18606 | % | ||||||||
| Loss on debt extinguishment |
(1,697 | ) | (328 | ) | (1,369 | ) | 417 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total other expenses |
$ | (97,188 | ) | $ | (48,176 | ) | $ | (49,012 | ) | (102 | )% | |||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net loss |
$ | (24,793 | ) | $ | (16,189 | ) | $ | (8,604 | ) | (53 | )% | |||||
|
|
|
|
|
|
|
|
|
|||||||||
NM – not meaningful.
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The following tables summarize our segment operating profit (loss) for the periods indicated:
| Year Ended December 31, 2024 | ||||||||||||||||||||
| (in thousands) | Mineral and Non-operating |
Operating | Securities | Eliminations | Total | |||||||||||||||
| Total revenues |
$ | 153,135 | $ | 128,127 | $ | 102,131 | $ | (102,166 | ) | $ | 281,227 | |||||||||
| Total operating expenses |
(109,636 | ) | (83,982 | ) | (15,350 | ) | 136 | (208,832 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Segment operating profit (loss) |
$ | 43,499 | $ | 44,145 | $ | 86,781 | $ | (102,030 | ) | $ | 72,395 | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Year Ended December 31, 2023 | ||||||||||||||||||||
| (in thousands) | Mineral and Non-operating |
Operating | Securities | Eliminations | Total | |||||||||||||||
| Total revenues |
$ | 116,902 | $ | 1,225 | $ | 40,509 | $ | (40,531 | ) | $ | 118,105 | |||||||||
| Total operating expenses |
(67,884 | ) | (6,725 | ) | (11,548 | ) | 39 | (86,118 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Segment operating profit (loss) |
$ | 49,018 | $ | (5,500 | ) | $ | 28,961 | $ | (40,492 | ) | $ | 31,987 | ||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
The following table summarizes our production data and average realized prices for the periods indicated:
| Year Ended December 31, | Change | |||||||||||||||
| 2024 | 2023 | Amount | % | |||||||||||||
| Production Data: |
||||||||||||||||
| Crude oil (Bbls) |
3,830,461 | 1,446,928 | 2,383,533 | 165 | % | |||||||||||
| Natural gas (Mcf) |
2,979,341 | 2,152,939 | 826,402 | 38 | % | |||||||||||
| NGL (Bbls) |
415,363 | 201,454 | 213,909 | 106 | % | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total (BOE)(6:1) |
4,742,381 | 2,007,205 | 2,735,176 | 136 | % | |||||||||||
| Average daily production (BOE/d) (6:1) |
12,993 | 5,499 | 7,494 | 136 | % | |||||||||||
| Average Realized Prices(a): |
||||||||||||||||
| Crude oil (Bbl) |
$ | 68.49 | $ | 73.10 | $ | (4.61 | ) | (6 | )% | |||||||
| Natural gas (Mcf) |
$ | 1.86 | $ | 3.15 | $ | (1.29 | ) | (41 | )% | |||||||
| NGL (Bbl) |
$ | 25.22 | $ | 27.50 | $ | (2.28 | ) | (8 | )% | |||||||
| (a) | Average realized prices are net of certain post-production costs that are deducted from our royalties. |
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Table of Contents
Revenues
The following table shows the components of our revenue for the periods presented:
| Year Ended December 31, | Change | |||||||||||||||
| (in thousands) | 2024 | 2023 | $ | % | ||||||||||||
| Mineral and royalty revenues |
||||||||||||||||
| Crude oil |
$ | 138,640 | $ | 105,771 | $ | 32,869 | 31 | % | ||||||||
| Natural gas |
5,424 | 6,790 | (1,366 | ) | (20 | )% | ||||||||||
| NGL |
8,935 | 5,527 | 3,408 | 62 | % | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total mineral and royalty revenues |
$ | 152,999 | $ | 118,088 | $ | 34,911 | 30 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Product sales |
||||||||||||||||
| Crude oil |
$ | 123,340 | $ | — | $ | 123,340 | NM | |||||||||
| Natural gas |
315 | — | 315 | NM | ||||||||||||
| NGL |
1,994 | — | 1,994 | NM | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total product sales |
$ | 125,649 | $ | — | $ | 125,649 | NM | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Water services |
$ | 2,478 | $ | — | $ | 2,478 | NM | |||||||||
| Other revenue |
101 | 17 | 84 | 494 | % | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total revenues |
$ | 281,227 | $ | 118,105 | $ | 163,122 | 138 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
NM – not meaningful.
Revenue was $281.2 million for the year ended December 31, 2024, as compared to $118.1 million for the same period in 2023, an increase of $163.1 million, or 138%. The increase was primarily attributable to a $125.6 million increase in product sales generated from our direct drilling, extraction, and related oil and gas operating activities and a $34.9 million increase in mineral and royalty revenues generated from our mineral and non-operating activities.
Mineral and Non-Operating Segment
Mineral and non-operating segment revenue was $153.1 million for the year ended December 31, 2024, as compared to $116.9 million for the same period in 2023, an increase of $36.2 million, or 31%. The increase in segment revenue was primarily driven by an overall increase in our mineral interests and non-operated working interests in oil and gas properties, which have expanded significantly in recent years. Acquisitions of such interests generally generate revenue in subsequent periods (e.g., on a six to eighteen-month lag). As a result, our mineral and non-operating segment revenue has increased over time as our portfolio of mineral interests and non-operated working interests in oil and gas properties has expanded. During the year ended December 31, 2024, we closed 1,802 unique transactions that added 134,809 NMAs of leasehold interests and 52,959 NRAs of mineral interests to our portfolio, as compared to 790 unique transactions, 64,569 NMA of leasehold interests, and 15,086 NRAs of mineral interests for the same period in 2023. The increase in our mineral and non-operating segment revenue was partially offset by lower commodity prices and higher post-production costs passed through to us relative to the increase in production volumes.
Operating Segment
Operating segment revenue was $128.1 million for the year ended December 31, 2024, as compared to $1.2 million for the same period in 2023. The increase in segment revenue was driven by the commencement of drilling activities by PhoenixOp. PhoenixOp began its operations in the third quarter of 2023 with the acquisition of five producing wells from another operator. As a result, segment revenues for the year ended December 31, 2023 were not material. PhoenixOp commenced production on its operated wells in 2024 and placed into service 32 additional wells as of December 31, 2024, resulting in increased segment revenue for the year ended December 31, 2024 as compared to the same period in 2023.
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Table of Contents
Operating Expenses
The following table shows the components of our cost of sales for the periods presented:
Cost of Sales
| Year Ended December 31, | Change | |||||||||||||||
| (in thousands) | 2024 | 2023 | $ | % | ||||||||||||
| Cost of sales |
||||||||||||||||
| Lease operating expenses |
$ | 26,424 | $ | 9,011 | $ | 17,413 | 193 | % | ||||||||
| Production taxes |
25,457 | 10,672 | 14,785 | 139 | % | |||||||||||
| Production costs |
12,066 | 50 | 12,016 | 24,032 | % | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
$ | 63,947 | $ | 19,733 | $ | 44,214 | 224 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
Cost of sales was $63.9 million for the year ended December 31, 2024, as compared to $19.7 million for the same period in 2023, an increase of $44.2 million, or 224%. The increase was primarily driven by the commencement of our direct drilling, extraction, and related oil and gas operating activities in 2024, as well as an increase in our mineral interests and non-operated working interests in oil and gas properties.
Mineral and Non-Operating Segment
Mineral and non-operating segment cost of sales was $30.2 million for the year ended December 31, 2024, as compared to $19.3 million for the same period in 2023, an increase of $10.9 million, or 57%. The increase in segment cost of sales was primarily driven by an overall increase in our mineral interests and non-operated working interests in oil and gas properties and the resulting increase in lease operating expenses and production taxes.
Operating Segment
Operating segment cost of sales was $33.8 million for the year ended December 31, 2024, as compared to $0.5 million for the same period in 2023. The increase in segment cost of sales was driven by the commencement of operated production from newly drilled wells by PhoenixOp in the first quarter of 2024, at which time we began to recognize lease operating expenses, production and ad valorem taxes, and production costs in our operating segment. PhoenixOp began its operations in the third quarter of 2023, when it became the operator of five producing wells acquired from another operator. As a result, there were no material cost of sales incurred for the year ended December 31, 2023.
Depreciation, Depletion, Amortization, and Accretion Expense
The following table shows the components of our depletion, depreciation, amortization, and accretion expense for the period presented:
| Year Ended December 31, | Change | |||||||||||||||
| (in thousands) | 2024 | 2023 | $ | % | ||||||||||||
| Depletion, depreciation, amortization and accretion |
||||||||||||||||
| Depletion |
$ | 85,706 | $ | 34,035 | $ | 51,671 | 152 | % | ||||||||
| Depreciation |
91 | 136 | (45 | ) | (33 | )% | ||||||||||
| Accretion on asset retirement obligations |
180 | 57 | 123 | 216 | % | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
$ | 85,977 | $ | 34,228 | $ | 51,749 | 151 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
Depreciation, depletion, amortization, and accretion expense was $86.0 million for the year ended December 31, 2024, as compared to $34.2 million for the same period in 2023, an increase of $51.7 million, or 151%, primarily due to an increase in our depletable bases within both the mineral and non-operating segment and the operating segment. On a per unit basis, depletion expense was $18.13 per Boe and $17.05 per Boe for the years ended December 31, 2024 and 2023, respectively. The increase in our depletion expense per Boe was predominantly
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Table of Contents
driven by a higher depletion rate for the year ended December 31, 2024 as compared to the year ended December 31, 2023, as a direct result of the incurrence of significant capital expenditures related to developing operated wells under our operating entity, PhoenixOp. The depletion rate for the development capital is depleted at a higher rate as compared to leasehold due to the use of proved developed reserves versus total proved reserves under the successful efforts accounting method.
Mineral and Non-Operating Segment
Depletion for the mineral and non-operating segment was $50.6 million for the year ended December 31, 2024, as compared to $34.2 million for the same period in 2023. The increase in our segment depletion expense was predominantly driven by increased production and increased capital expenditures.
Operating Segment
Depletion for the operating segment was $35.4 million for the year ended December 31, 2024, as compared to less than $0.1 million for the same period in 2023 due to limited operations in the period.
Selling, General, and Administrative Expense
Selling, general, and administrative expense was $29.2 million for the year ended December 31, 2024, as compared to $14.3 million for the same period in 2023, an increase of $14.9 million, or 104%. The increase was primarily due to a $9.8 million increase in corporate overhead costs not directly associated with the segments but which have been allocated to the segments based on headcount and a level-of-effort formula, including a $8.8 million increase in legal, accounting, and consulting professional services fees, a $2.8 million increase in costs associated with our capital raise initiatives in our securities segment, and a $2.8 million increase in fees associated with land acquisition and title work in our mineral and non-operating segment, as further described below.
Mineral and Non-Operating Segment
Selling, general, and administrative expense for the mineral non-operating segment was $14.5 million for the year ended December 31, 2024, as compared to $6.8 million for the same period in 2023, an increase of $7.7 million, or 113%. The increase was primarily due to higher allocated corporate overhead of $4.5 million and increased fees associated with land acquisition and title work of $2.8 million during the year ended December 31, 2024 as compared to the same period in the prior year. This was primarily associated with our increased activity in acquiring leasehold and mineral assets.
Operating Segment
Selling, general, and administrative expense for the operating segment was $6.2 million for the year ended December 31, 2024, as compared to $2.8 million for the same period in 2023, an increase of $3.4 million, or 121%. The increase was due to PhoenixOp’s first full year period of full-time operations. PhoenixOp began its drilling and completion activities in September 2023 and operations continually grew throughout 2024.
Securities Segment
Selling, general, and administrative expense for the securities segment was $8.5 million for the year ended December 31, 2024, as compared to $4.7 million for the same period in 2023, an increase of $3.8 million, or 81%. The increase was primarily due to increased legal costs associated with our securities offerings of $2.0 million, increased securities administration costs of $0.8 million, and increased allocated corporate overhead of $0.9 million.
Payroll and Payroll-Related Expense
Payroll and payroll-related expense was $27.9 million for the year ended December 31, 2024, as compared to $12.7 million for the same period in 2023, an increase of $15.2 million, or 119%, primarily as a result of increased employee headcount, which increased from 118 employees at December 31, 2023 to 135 employees at December 31, 2024.
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Table of Contents
Mineral and Non-Operating Segment
Payroll and payroll-related expense for the mineral and non-operating segment was $13.3 million for the year ended December 31, 2024, as compared to $6.4 million for the same period in 2023, an increase of $6.9 million, or 108%, due to increased activity in acquiring leasehold and mineral assets.
Operating Segment
Payroll and payroll-related expense for the operating segment was $8.6 million for the year ended December 31, 2024, as compared to $3.2 million for the same period in 2023, an increase of $5.4 million, or 171%, due to PhoenixOp’s first full year period of full time operations.
Securities Segment
Payroll and payroll-related expense for the securities segment was $6.1 million for the year ended December 31, 2024, as compared to $3.2 million for the same period in 2023, an increase of $2.9 million, or 91%, primarily due to the increased number of personnel engaged in the administration and management of our securities offerings.
Advertising and Marketing Expense
Advertising and marketing expense was $0.7 million for the year ended December 31, 2024, as compared to $4.1 million for the same period in 2023, a decrease of $3.5 million, or 84%. The decrease was primarily the result of spending $3.6 million on an audio marketing campaign in 2023 attributable to the securities segment that did not recur in 2024.
Loss on Sale of Assets
Loss on sale of assets was $0.6 million for the year ended December 31, 2024 as a result of the disposition of certain mineral interests in the Williston basin within the mineral and non-operating segment, with no comparable activity in the prior-year period.
Impairment Expense
Impairment expense was $0.6 million for the year ended December 31, 2024, as compared to $1.0 million for the same period in 2023. In 2024, impairment expense was a result of write-offs associated with title defects and lease expirations within the mineral and non-operating segment, whereas impairment expense in 2023 was attributable to a decrease in natural gas prices and the resulting impairment of the carrying value of our proved natural gas properties within the mineral and non-operating segment.
Other Expenses
Interest Expense
Interest expense was $90.2 million for the year ended December 31, 2024, as compared to $47.9 million for the same period in 2023, an increase of $42.3 million, or 88%. The increase was primarily due to increased sales of our unregistered debt securities, which increased from $421.8 million outstanding at December 31, 2023 to $737.9 million outstanding at December 31, 2024, with no significant changes in interest rates between the periods, and a $2.9 million increase in amortized debt discount and debt issuance costs for the year ended December 31, 2024 as compared to the prior-year period.
Loss on Derivatives
Loss on derivatives was $6.0 million for the year ended December 31, 2024, as compared to less than $0.1 million for the same period in 2023. The increase was primarily a result of unfavorable changes in the mark-to-market value of commodity derivatives entered into during the second half of 2024, with limited comparable activity for the same period in 2023.
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Loss on Debt Extinguishment
Loss on debt extinguishment was $1.7 million for the year ended December 31, 2024, as compared to $0.3 million for the same period in 2023. The increase was primarily due to increased write-offs of debt issuance costs associated with the early redemptions of bonds issued pursuant to Regulation A and Regulation D, of which $17.7 million of bonds were redeemed during the year ended December 31, 2024, as compared to $4.3 million of bonds redeemed for the same period in 2023.
The following table summarizes the par value of bonds redeemed for the periods indicated:
| Year Ended December 31, | Change | |||||||||||||||
| (in thousands) | 2024 | 2023 | $ | % | ||||||||||||
| August 2023 506(c) Bonds |
$ | 12,426 | $ | 265 | $ | 12,161 | 4589 | % | ||||||||
| Reg A Bonds |
2,306 | 2,122 | 184 | 9 | % | |||||||||||
| December 2022 506(c) Bonds |
1,592 | 1,004 | 588 | 59 | % | |||||||||||
| Adamantium Bonds |
1,319 | — | 1,319 | NM | ||||||||||||
| July 2022 506(c) Bonds |
100 | 915 | (815 | ) | (89 | )% | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
$ | 17,743 | $ | 4,306 | $ | 13,437 | 312 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
NM – not meaningful.
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Results of Operations for the Year Ended December 31, 2023 Compared to the Year Ended December 31, 2022
The following table summarizes our consolidated results of operations for the periods indicated:
| Year Ended December 31, | Change | |||||||||||||||
| (in thousands) | 2023 (As Restated) |
2022 (As Restated) |
$ | % | ||||||||||||
| Revenues |
$ | 118,105 | $ | 54,554 | $ | 63,551 | 116% | |||||||||
| Operating expenses |
||||||||||||||||
| Cost of sales |
$ | 19,733 | $ | 9,573 | $ | 10,160 | 106% | |||||||||
| Depreciation, depletion, amortization, and accretion |
34,228 | 12,144 | 22,084 | 182% | ||||||||||||
| Selling, general, and administrative |
14,314 | 5,563 | 8,751 | 157% | ||||||||||||
| Payroll and payroll-related |
12,733 | 6,023 | 6,710 | 111% | ||||||||||||
| Advertising and marketing |
4,136 | 1,353 | 2,783 | 206% | ||||||||||||
| Impairment expense |
974 | — | 974 | NM | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total operating expenses |
$ | 86,118 | $ | 34,656 | $ | 51,462 | 148% | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income from operations |
$ | 31,987 | $ | 19,898 | $ | 12,089 | 61% | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Other expenses |
||||||||||||||||
| Interest income |
$ | 66 | $ | — | $ | 66 | NM | |||||||||
| Interest expense |
(47,882 | ) | (11,893 | ) | (35,989 | ) | 303% | |||||||||
| Loss on derivatives |
(32 | ) | (2,239 | ) | 2,207 | (99)% | ||||||||||
| Loss on debt extinguishment |
(328 | ) | (92 | ) | (236 | ) | 257% | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total other expenses |
$ | (48,176 | ) | $ | (14,224 | ) | $ | (33,952 | ) | 239% | ||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income (loss) |
$ | (16,189 | ) | $ | 5,674 | $ | (21,863 | ) | (385)% | |||||||
|
|
|
|
|
|
|
|
|
|||||||||
NM – not meaningful.
The following tables summarize our segment operating profit (loss) for the periods indicated:
| Year Ended December 31, 2023 | ||||||||||||||||||||
| (in thousands) | Mineral and Non-operating |
Operating | Securities | Eliminations | Total | |||||||||||||||
| Total revenues |
$ | 116,902 | $ | 1,225 | $ | 40,509 | $ | (40,531 | ) | $ | 118,105 | |||||||||
| Total operating expenses |
(67,884 | ) | (6,725 | ) | (11,548 | ) | 39 | (86,118 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Segment operating profit (loss) |
$ | 49,018 | $ | (5,500 | ) | $ | 28,961 | $ | (40,492 | ) | $ | 31,987 | ||||||||
|
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|
|||||||||||
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| Year Ended December 31, 2022 | ||||||||||||||||||||
| (in thousands) | Mineral and Non-operating |
Operating | Securities | Eliminations | Total | |||||||||||||||
| Total revenues |
$ | 54,554 | $ | — | $ | 4,991 | $ | (4,991 | ) | $ | 54,554 | |||||||||
| Total operating expenses |
(31,306 | ) | — | (3,350 | ) | — | (34,656 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Segment operating profit (loss) |
$ | 23,248 | $ | — | $ | 1,641 | $ | (4,991 | ) | $ | 19,898 | |||||||||
|
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|
|
|
|
|
|
|
|
|
|||||||||||
The following table summarizes our production data and average realized prices for the periods indicated:
| Year Ended December 31, | ||||||||||||||||
| 2023 | 2022 | Change | ||||||||||||||
| Production Data: |
||||||||||||||||
| Crude oil (Bbls) |
1,446,928 | 523,416 | 923,512 | 177% | ||||||||||||
| Natural gas (Mcf) |
2,152,939 | 1,058,506 | 1,094,433 | 103% | ||||||||||||
| NGL (Bbls) |
201,454 | — | 201,454 | NM | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total (BOE)(6:1) |
2,007,205 | 699,834 | 1,307,372 | 187% | ||||||||||||
| Average daily production (BOE/d)(6:1) |
5,499 | 1,917 | 3,582 | 187% | ||||||||||||
| Average Realized Prices(a): |
||||||||||||||||
| Crude oil (Bbl) |
$ | 73.10 | $ | 91.01 | $ | (17.91 | ) | (20)% | ||||||||
| Natural gas (Mcf) |
$ | 3.15 | $ | 6.66 | $ | (3.51 | ) | (53)% | ||||||||
| NGL (Bbl) |
$ | 27.50 | $ | — | $ | 27.50 | NM | |||||||||
NM – not meaningful.
| (a) | Average realized prices are net of certain post-production costs which are deducted from our royalties. |
Revenues
The following table shows the components of our revenue for the periods presented:
| Year Ended December 31, | ||||||||||||||||
| (in thousands) | 2023 | 2022 | Change | |||||||||||||
| Mineral and royalty revenues |
||||||||||||||||
| Crude oil |
$ | 105,771 | $ | 47,493 | $ | 58,278 | 123 | % | ||||||||
| Natural gas |
6,790 | 7,061 | (271 | ) | (4 | )% | ||||||||||
| NGL |
5,527 | — | 5,527 | NM | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total mineral and royalty revenues |
$ | 118,088 | $ | 54,554 | $ | 63,534 | 116 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Other revenue |
$ | 17 | $ | — | $ | 17 | NM | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total revenues |
$ | 118,105 | $ | 54,554 | $ | 63,551 | 116% | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
NM – not meaningful.
Total revenue was $118.1 million for the year ended December 31, 2023, as compared to $54.6 million for the same period in 2022, an increase of $63.6 million, or 116%. The increase was primarily attributable to a $63.5 million increase in mineral and royalty revenues generated from our increased mineral and non-operating activities.
Mineral and Non-Operating Segment
Mineral and non-operating segment revenue was $116.9 million for the year ended December 31, 2023, as compared to $54.6 million for the same period in 2022, an increase of $62.3 million, or 114%. The increase in segment revenue was primarily driven by an overall increase in our mineral interests and non-operated working interests in oil and gas properties, which have expanded significantly in recent years. Acquisitions of such interests generally generate revenue in subsequent periods (e.g., on a six to eighteen month lag). As a result, our mineral and non-operating segment revenue has increased over time as our portfolio of mineral interests and non-operated working interests in oil and gas properties has expanded. We closed 825 unique transactions, which added 71,693
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NMAs of leasehold interests and 12,043 NRAs of mineral interests to our portfolio, in the year ended December 31, 2023, as compared to 259 unique transactions, 19,712 NMAs of leasehold interests, and 10,306 NRAs of mineral interests in the prior year. The increase was partially offset by lower commodity prices, with average NYMEX crude oil and natural gas prices down 18% and 61%, respectively, in 2023 from 2022, and higher post-production costs of $3.0 million, which were passed through to us relative to an increase in production volumes.
Operating Segment
Operating segment revenue was $1.2 million for the year ended December 31, 2023. Prior year operating segment revenues are not included in our financial results because PhoenixOp commenced operations in the third quarter of 2023, when it became the operator of five producing wells acquired from another operator.
Operating Expenses
Cost of Sales
The following table shows the components of our cost of sales for the periods presented:
| Year Ended December 31, |
Change | |||||||||||||||
| (in thousands) | 2023 | 2022 | $ | % | ||||||||||||
| Cost of sales |
||||||||||||||||
| Production taxes |
$ | 10,672 | $ | 4,624 | $ | 6,048 | 131 | % | ||||||||
| Lease operating expenses |
9,011 | 4,949 | 4,062 | 82 | % | |||||||||||
| Production costs |
50 | — | 50 | NM | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
$ | 19,733 | $ | 9,573 | $ | 10,160 | 106 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
NM – not meaningful.
Cost of sales was $19.7 million for the year ended December 31, 2023, as compared to $9.6 million for the same period in 2022, an increase of $10.2 million, or 106%. The increase was primarily due to an increase in our mineral interests and non-operated working interests in oil and gas properties and the resulting increase in lease operating expenses, production taxes, and ad valorem taxes.
Mineral and Non-Operating Segment
Mineral and non-operating segment cost of sales was $19.3 million for the year ended December 31, 2023, as compared to $9.6 million for the same period in 2022, an increase of $9.7 million, or 101%. The increase in segment cost of sales was primarily driven by an overall increase in our mineral interests and non-operated working interests in oil and gas properties and the resulting increase in lease operating expenses and production taxes.
Operating Segment
Operating segment cost of sales was $0.5 million for the year ended December 31, 2023. Prior year operating segment cost of sales is not included in our financial results because PhoenixOp commenced operations in the third quarter of 2023, when it became the operator of five producing wells acquired from another operator.
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Depreciation, Depletion, Amortization, and Accretion Expense
The following table shows the components of our depletion, depreciation, amortization, and accretion expense for the periods presented:
| Year Ended December 31, | Change | |||||||||||||||
| (in thousands) | 2023 | 2022 (As Restated) |
$ | % | ||||||||||||
| Depletion, depreciation, amortization, and accretion |
||||||||||||||||
| Depletion |
$ | 34,035 | $ | 12,042 | $ | 21,993 | 183% | |||||||||
| Depreciation |
136 | 86 | 50 | 58% | ||||||||||||
| Accretion on asset retirement obligation |
57 | 16 | 41 | 256% | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
$ | 34,228 | $ | 12,144 | $ | 22,084 | 182% | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
Depreciation, depletion, amortization, and accretion expense was $34.2 million for the year ended December 31, 2023, as compared to $12.1 million for the same period in 2022, an increase of $22.1 million, or 182%, primarily driven by increased production and an increase in our depletable bases within the mineral and non-operating segment. Depletion expense in the operating segment was not material for the year ended December 31, 2023.
Mineral and Non-Operating Segment
Depletion for the mineral and non-operating segment was $34.2 million for the year ended December 31, 2023, as compared to $12.1 million for the same period in 2022, an increase of $22.1 million, or 182%. The increase in depletion expense was predominantly driven by increased production and an increase in our depletable bases.
Selling, General, and Administrative Expense
Selling, general, and administrative expense was $14.3 million for the year ended December 31, 2023, as compared to $5.6 million for the same period in 2022, an increase of $8.7 million, or 157%. The increase was primarily due to increased costs associated with our capital raise initiatives in our securities segment, increased fees associated with land acquisition and title work in our mineral and non-operating segment, and increased corporate overhead costs not directly associated with the segments but which have been allocated to the segments based on headcount and a level-of-effort formula.
Mineral and Non-Operating Segment
Selling, general, and administrative expense in the mineral and non-operating segment was $6.8 million for the year ended December 31, 2023, as compared to $3.7 million for the same period in 2022, an increase of $3.1 million, or 84%, due to higher legal and land-related professional fees associated with our increased activity in acquiring leasehold and mineral assets.
Operating Segment
Selling, general, and administrative expense in the operating segment was $2.8 million for the year ended December 31, 2023, with no comparable activity in 2022 as PhoenixOp did not commence operations until 2023.
Securities Segment
Selling, general, and administrative expense in the securities segment was $4.7 million for the year ended December 31, 2023, as compared to $1.9 million for the same period in 2022, an increase of $2.8 million, or 155%. The increase was primarily due to increased legal costs and allocated corporate overhead related to our securities offerings.
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Payroll and Payroll-Related Expense
Payroll and payroll-related expense was $12.7 million for the year ended December 31, 2023, as compared to $6.0 million for the same period in 2022, an increase of $6.7 million, or 111%, primarily as a result of increased employee headcount, which increased from 54 employees at December 31, 2022 to 118 employees at December 31, 2023.
Mineral and Non-Operating Segment
Payroll and payroll-related expense for the mineral and non-operating segment was $6.4 million for the year ended December 31, 2023, as compared to $5.3 million for the same period in 2022, an increase of $1.1 million, or 21%, due to increased activity in acquiring leasehold and mineral assets.
Operating Segment
Payroll and payroll-related expense for the operating segment was $3.2 million for the year ended December 31, 2023, with no comparable activity in 2022 as PhoenixOp did not commence operations until 2023.
Securities Segment
Payroll and payroll-related expense for the securities segment was $3.2 million for the year ended December 31, 2023, as compared to $0.7 million for the same period in 2022, an increase of $2.5 million, or 338%, primarily due to the increased number of personnel engaged in the administration and management of our securities offerings.
Advertising and Marketing Expense
Advertising and marketing expense was $4.1 million for the year ended December 31, 2023, as compared to $1.4 million for the same period in 2022, an increase of $2.7 million. The increase was primarily driven by increased spend on an audio marketing campaign within the securities segment to acquire investors.
Impairment Expense
Impairment expense was $1.0 million for the year ended December 31, 2023 and was attributable to a decrease in natural gas prices, which resulted in the impairment of our proved natural gas properties within the mineral and non-operating segment. We did not incur any impairment expense for the year ended December 31, 2022.
Other Expenses
Interest Expense
Interest expense was $47.9 million for the year ended December 31, 2023 as compared to $11.9 million for the same period in 2022, an increase of $36.0 million, or 303%. The increase was primarily driven by an increase in the amount of our debt securities outstanding, which increased from $82.8 million outstanding at December 31, 2022 to $421.8 million at December 31, 2023, with no significant changes in interest rates during 2023 as compared to 2022, and a $10.1 million increase in amortized debt issuance costs for the year ended December 31, 2023 as compared to the prior year.
Loss on Derivatives
Loss on derivatives was less than $0.1 million for the year ended December 31, 2023 as compared to $2.2 million for the same period in 2022. The decrease was primarily due to a loss that was recognized in connection with a derivatives settlement agreement executed in July 2022 that did not recur in 2023.
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Loss on Debt Extinguishment
Loss on debt extinguishment was $0.3 million for the year ended December 31, 2023 as compared to less than $0.1 million for the same period in 2022. The increase was primarily due to increased write-offs of debt issuance costs associated with the early redemptions of bonds issued pursuant to Regulation A and Regulation D, of which $4.3 million of bonds were redeemed during the year ended December 31, 2023, as compared to $1.6 million of bonds redeemed for the same period in 2022.
The following table summarizes the par value of bonds redeemed for the periods indicated:
| Year Ended December 31, | Change | |||||||||||||||
| (in thousands) | 2023 | 2022 | $ | % | ||||||||||||
| Reg A Bonds |
$ | 2,122 | $ | 268 | $ | 1,854 | 692 | % | ||||||||
| December 2022 506(c) Bonds |
1,004 | — | 1,004 | NM | ||||||||||||
| August 2023 506(c) Bonds |
265 | — | 265 | NM | ||||||||||||
| July 2022 506(c) Bonds |
915 | 1,285 | (370 | ) | (29 | )% | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
$ | 4,306 | $ | 1,553 | $ | 2,753 | 177 | % | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
NM – not meaningful.
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Non-GAAP Financial Measures
Our management uses EBITDA to understand and compare our operating results across accounting periods, for internal budgeting and forecasting purposes, and to evaluate financial performance and liquidity, in each case, without regard to financing methods, capital structure, or historical cost basis. EBITDA is presented as supplemental disclosure as we believe it provides useful information to investors and others in understanding and evaluating our results, prospects, and liquidity period over period, including as compared to results of other companies. By providing this non-GAAP financial measure, together with a reconciliation to GAAP results, we believe we are enhancing investors’ understanding of our business and our operating performance, as well as assisting investors in evaluating how well we are executing strategic initiatives.
EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income (loss), the most directly comparable GAAP measure. In particular, EBITDA excludes certain material costs, such as interest expense, and certain non-cash charges, such as depreciation, depletion, amortization, and accretion expense, which have been necessary elements of our expenses. Because EBITDA does not account for these expenses, its utility as a measure of our operating performance has material limitations. Other companies may not publish this or similar metrics, and our computation of EBITDA may differ from computations of similarly titled measures of other companies. Therefore, our EBITDA should be considered in addition to, and not as a substitute for, in isolation from, or superior to, our financial information prepared in accordance with GAAP, and should be read in conjunction with our consolidated financial statements and the related notes included elsewhere in this prospectus.
The following table shows a reconciliation of EBITDA to net income (loss), the most comparable GAAP measure, as presented in the consolidated statements of operations for the periods presented:
| Year Ended December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Net income (loss) |
$ | (24,793 | ) | $ | (16,189 | ) | $ | 5,674 | ||||
| Interest income |
(705 | ) | (66 | ) | — | |||||||
| Interest expense |
90,210 | 47,882 | 11,893 | |||||||||
| Depreciation, depletion, amortization, and accretion expense |
85,977 | 34,228 | 12,144 | |||||||||
|
|
|
|
|
|
|
|||||||
| EBITDA |
$ | 150,689 | $ | 65,855 | $ | 29,711 | ||||||
|
|
|
|
|
|
|
|||||||
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EBITDA was $150.7 million for the year ended December 31, 2024, as compared to $65.9 million for the same period in 2023, an increase of $84.8 million, or 129%. The increase in EBITDA was primarily driven by a $163.1 million increase in consolidated revenues, partially offset by a $71.0 million increase in operating expense (excluding depreciation, depletion, amortization and accretion expense), primarily driven by increased cost of sales and increased legal, accounting and land-related professional service fees and other corporate overhead costs, and a $6.0 million increase in loss on derivatives primarily due to unfavorable changes in the mark-to-market value of commodity derivatives entered into during the second half of 2024.
EBITDA was $65.9 million for the year ended December 31, 2023 as compared to $29.7 million for the year ended December 31, 2022, an increase of $36.1 million, or 122%. The increase in EBITDA was primarily driven by an increase in consolidated revenues, partially offset by increased cost of sales and corporate overhead costs resulting from our growth, and increased advertising costs of $2.8 million primarily due to an audio marketing campaign in 2023 with no comparable activity in the prior year.
We expect our EBITDA to grow substantially in 2025 as the capital raised and deployed by us is expected to produce meaningful revenues. In 2024, the majority of revenues were produced from our properties acquired in 2023. Our management expects that the $864.0 million raised during the year ended December 31, 2024, and the corresponding investments in properties acquired and, in the case of properties and cash contributed to PhoenixOp, developed through the year ended December 31, 2024, will continue producing substantial revenues in 2025.
Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash flows from operations, borrowings under credit agreements, and issuances of debt securities pursuant to Regulation D and Regulation A, including the Adamantium Securities and the Reg D/Reg A Bonds. Future sources of liquidity may also include other credit facilities, additional capital contributions, and continued issuances of debt or equity securities, including the Notes. Our primary uses of cash have been the acquisition of mineral and royalty interests, lease operating expenses, and our proportionate share of production, severance, and ad valorem taxes for mineral and royalty interests, production costs, including gathering, processing, and transportation costs, debt service payments, the reduction of outstanding debt balances, general overhead and other corporate expenses, and distributions to our members. As we continue to engage in increased drilling and direct production activities through PhoenixOp, we expect development and operation of PhoenixOp’s properties to become an increasingly significant use of our cash. As of December 31, 2024, we had cash and cash equivalents of $120.8 million and outstanding indebtedness of $987.9 million.
As of March 31, 2025, we had $132.8 million of debt coming due and $81.4 million of interest payable within the next 12 months. Over the next 12 months, we expect to drill between 75 to 85 gross and 45.0 to 51.0 net wells across our operated leasehold acreage in the Bakken/Willison Basin in North Dakota and Montana, and expect to participate in the drilling of approximately between 115 to 165 gross and 11.3 to 16.1 net wells across our non-operated leasehold. We estimate that these direct drilling operations and non-operated activity will require between $750.0 million and $850.0 million of capital expenditures over the next 12 months.
Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, or to refinance our indebtedness, will depend on our ability to generate cash in the future. Although we expect that our cash flows from operations will be sufficient to meet our fixed obligations, to fully realize our business plan we expect that we will need to raise approximately $400 million in capital in 2025 through the incurrence of additional debt, including the Notes offered hereby. We believe that these sources of liquidity will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, and capital expenditures, for at least the next 12 months, and will allow us to continue to execute on our strategy of expanding our direct drilling operations through PhoenixOp and acquiring attractive mineral and royalty interests in order to position us to grow our cash flows.
We periodically assess changes in current and projected cash flows, acquisition and divestiture activities, and other factors to determine the effects on our liquidity. 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. We are currently monitoring our operations and industry developments, including our drilling operations and production plans, in light of recent changes in the commodity price environment and industry volatility. In April 2025, oil and natural gas prices dropped significantly, going from $71.20 per barrel and $3.95 per MMBtu as of April 1, 2025 to $58.21 per barrel and $3.33 per MMBtu as of April 30, 2025, respectively, which prices are below those assumed for purposes of our business plan. While we believe the company is well-positioned to navigate a lower-price environment, in the event of a prolonged period of commodity prices below those assumed for purposes of our business plan, our cash flows from operations would decrease and we may determine to adjust our business plan by adjusting capital expenditures, decreasing drilling operations, and/or reducing production plans, among other actions. We may also be required to raise additional capital, above our current expectations, in order to fully realize our current or adjusted business plan. See “Risk Factors—Risks Related to Our Business and Operations—Our business is sensitive to the price of oil and gas and sustained declines in prices may adversely affect our financial position, financial results, cash flows, access to capital, and ability to grow.” If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures. If we require additional capital for acquisitions or other reasons, we may raise such capital through additional borrowings, asset sales, offerings of equity and debt securities, or other means. We cannot assure you that necessary capital will be available on acceptable terms or at all. Our ability to raise
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funds through the incurrence of additional indebtedness could be limited by covenants in our debt arrangements. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that are favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves. See “Risk Factors.”
We or our affiliates may from time to time seek to repurchase or retire the Notes or our other indebtedness through cash purchases and/or exchanges for equity or debt securities, in open-market purchases, privately negotiated transactions, tender or exchange offers, or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity, contractual restrictions, and other factors. The amounts involved may be material. For more information regarding the material terms of our outstanding indebtedness, see “—Indebtedness” below.
Cash Flows
The following table summarizes our cash flows for the periods indicated:
| Year Ended December 31, | ||||||||||||
| 2024 | 2023 (As Restated) |
2022 (As Restated) |
||||||||||
| (in thousands) | ||||||||||||
| Net cash provided by (used in) |
||||||||||||
| Operating activities |
$ | 95,239 | $ | (1,826 | ) | $ | 18,642 | |||||
| Investing activities |
(437,703 | ) | (278,661 | ) | (91,888 | ) | ||||||
| Financing activities |
457,850 | 281,308 | 77,493 | |||||||||
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| Net increase in cash and cash equivalents |
$ | 115,386 | $ | 821 | $ | 4,247 | ||||||
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Operating Activities
Net cash provided by operating activities for the year ended December 31, 2024 was $95.2 million, as compared to $1.8 million used in operations for the same period in 2023, an increase of $97.0 million in cash provided by operating activities. The increase was primarily due to a $54.7 million increase in net income, adjusted for non-cash charges of $63.3 million, and net favorable fluctuations of $41.8 million from changes in operating assets and liabilities. The $41.8 million cash inflow from changes in operating assets and liabilities was primarily due to a net increase of $28.6 million in accounts receivable, accounts payable, and accrued and other liabilities, primarily due to the timing of cash receipts and payments, and a $13.8 million increase in accrued interest from the increased amount of debt securities issued during the year ended December 31, 2024 as compared to the same period in 2023.
Net cash used in operating activities was $1.8 million for the year ended December 31, 2023 as compared to net cash provided by operating activities of $18.6 million for the year ended December 31, 2022, an increase of $20.4 million. The increase was driven by a $28.7 million increase in cash paid for our operating costs, a $14.1 million increase in cash paid for interest, net of capitalized interest, and a $23.8 million increase in earnest payments, partially offset by a $37.5 million in proceeds received from revenues earned and a $14.8 million decrease in other working capital balances due to fluctuations in the timing of cash receipts and disbursements.
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Investing Activities
Net cash used in investing activities for the year ended December 31, 2024 was $437.7 million, as compared to $278.7 million for the same period in 2023, an increase of $159.0 million. The increase was primarily driven by a $165.2 million increase in additions to oil and gas properties, primarily due to increased drilling and completion activities in our operating segment during the year ended December 31, 2024, with limited operations for the same period in 2023, and $6.2 million of proceeds received in connection with the disposition of mineral interests during the year ended December 31, 2024 that did not occur in the prior-year period.
Net cash used in investing activities for the year ended December 31, 2023 was $278.7 million as compared to $91.9 million for the year ended December 31, 2022, an increase of $186.8 million. The increase was primarily driven by a $91.8 million increase in cash paid to acquire mineral and leasehold interests, a $30.1 million increase in cash paid to our operators for our portion of drilling and completion costs incurred, cash payments of $63.4 million primarily associated with PhoenixOp’s drilling and completion activities, and $2.1 million of capitalized interest paid in 2023 that did not exist in the prior year.
Financing Activities
Net cash provided by financing activities for the year ended December 31, 2024 was $457.9 million, as compared to $281.3 million for the same period in 2023, an increase of $176.6 million. The increase was primarily driven by increased proceeds from issuances of debt, net of debt discount, of $399.5 million and a $2.7 million decrease in members’ distributions, partially offset by a $188.7 million increase in repayments of debt, a $20.3 million increase in payments of debt issuance costs, a $9.8 million decrease in members’ contributions, and a $6.9 million increase in payments of deferred closings associated with mineral interest acquisitions.
Net cash provided by financing activities for the year ended December 31, 2023 was $281.3 million as compared to $77.5 million for the year ended December 31, 2022, an increase of $203.8 million. The increase was primarily driven by increased proceeds from issuances of debt, net of debt discount, of $379.5 million and a $10.0 million increase in members contributions, which was partially offset by a $38.1 million increase in debt issuance costs, a $137.7 million increase in repayments of debt, a $7.4 million increase in distributions to our members, and a $2.5 million increase in payments of deferred closings associated with mineral interest acquisitions.
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Indebtedness
Set forth below is a chart of our outstanding third-party indebtedness as of December 31, 2024 (dollars in thousands):
| Indebtedness |
Offering Commencement |
Principal Amount Outstanding |
Term | Earliest Maturity |
Latest Maturity |
Interest Rate |
||||||||||||||||||
| Secured |
||||||||||||||||||||||||
| Fortress Credit Agreement(1) |
N/A | $ | 250,000 | 3 years | — | 12/18/2027 | Term SOFR + 7.10% | |||||||||||||||||
| Adamantium Secured Note(2) |
N/A | 7,000 | 7 years | — | 11/1/2031 | 16.5% | ||||||||||||||||||
| Unsecured |
||||||||||||||||||||||||
| Reg A Bonds(3) |
12/23/2021 | 104,884 | 3 years | 1/10/2025 | 8/10/2027 | 9.0% | ||||||||||||||||||
| 2020 506(b) Bonds(4) |
7/20/2020 | 940 | 2 years | — | 3/31/2025 | 5.0% | ||||||||||||||||||
| 2020 506(c) Bonds(4) |
10/22/2020 | 2,098 | 1-4 years | 9/30/2025 | 6/27/2027 | 13.0% - 15.0% | ||||||||||||||||||
| July 2022 506(c) Bonds(4) |
7/20/2022 | 10,457 | 5 years | 7/31/2027 | 12/31/2027 | 11.0% | ||||||||||||||||||
| December 2022 506(c) Bonds(5): |
||||||||||||||||||||||||
| Series B |
12/22/2022 | 17,324 | 3 years | 4/10/2025 | 10/10/2026 | 10.0% | ||||||||||||||||||
| Series C |
12/22/2022 | 9,984 | 5 years | 12/10/2027 | 9/10/2028 | 11.0% | ||||||||||||||||||
| Series D |
12/22/2022 | 41,666 | 7 years | 12/10/2029 | 10/10/2030 | 12.0% | ||||||||||||||||||
| August 2023 506(c) Bonds(5): |
||||||||||||||||||||||||
| Series U, AA, and FF |
8/29/2023 | 74,254 | 1 year | 1/10/2025 | 12/10/2025 | 9.0% - 10.0% | ||||||||||||||||||
| Series V, BB, and GG |
8/29/2023 | 59,383 | 3 years | 8/10/2026 | 12/10/2027 | 10.0% - 11.0% | ||||||||||||||||||
| Series W, CC, and HH |
8/29/2023 | 31,265 | 5 years | 8/10/2028 | 12/10/2029 | 11.0% - 12.0% | ||||||||||||||||||
| Series X, DD, and II |
8/29/2023 | 62,056 | 7 years | 9/10/2030 | 12/10/2031 | 12.0% - 13.0% | ||||||||||||||||||
| Series Y |
8/29/2023 | 4,043 | 9 years | 9/10/2032 | 9/10/2033 | 12.5% | ||||||||||||||||||
| Series Z, EE, and JJ |
8/29/2023 | 184,353 | 11 years | 8/10/2034 | 12/10/2035 | 13.0% - 14.0% | ||||||||||||||||||
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| Total Reg D/Reg A Bonds |
602,707 | |||||||||||||||||||||||
| Adamantium Bonds(6) |
9/29/2023 | 128,180 | 5-11 years | 1/10/2029 | 12/10/2035 | 13.0% - 16.0% | ||||||||||||||||||
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| Total Unsecured Debt |
730,887 | |||||||||||||||||||||||
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| Total Debt |
$ | 987,887 | ||||||||||||||||||||||
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| (1) | The Fortress Credit Agreement provides for a $100.0 million term loan facility, borrowed in full on August 12, 2024, a $35.0 million delayed draw term loan facility, which was fully drawn in October 2024, a $115.0 million term loan facility, borrowed in full on December 18, 2024, and a $25.0 million term loan facility, borrowed in full on April 16, 2025. Amount displayed does not include amounts drawn after December 31, 2024, 2024. The Fortress Credit Agreement also provides for an $8.5 million tranche of loans that represents a contingent principal obligation that is only due and payable (together with accrued interest thereon) upon certain conditions occurring, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing by the obligors thereunder. See “—Fortress Credit Agreement.” |
| (2) | The Adamantium Secured Note is contractually subordinated to amounts under the Fortress Credit Agreement, contractually senior to the Adamantium Bonds, and structurally senior to the Reg D/Reg A Bonds and the Notes offered hereby to the extent of the value of Adamantium’s assets, including the collateral securing the Adamantium Loan Agreement, and will be contractually senior to obligations under the Notes offered hereby. |
| (3) | The Reg A Bonds are pari passu obligations with the Senior Reg D Bonds, are contractually senior to obligations under the Subordinated Reg D Bonds, and will be contractually senior to obligations under the Notes offered hereby. |
| (4) | The Senior Reg D Bonds are pari passu obligations with the Reg A Bonds, are contractually subordinated to amounts under the Fortress Credit Agreement, are contractually senior to obligations under the Subordinated Reg D Bonds, and will be contractually senior to obligations under the Notes offered hereby. |
| (5) | The Subordinated Reg D Bonds are contractually subordinated to obligations under the Fortress Credit Agreement, the Reg A Bonds, and the Senior Reg D Bonds and will be contractually subordinated to obligations under the Notes offered hereby. Between January 1, 2025 and March 31, 2025, we issued an additional $126.7 million of August 2023 506(c) Bonds, with maturities ranging from December 2025 to March 2036 and interest rates between 9.0% and 14.0% per annum. |
| (6) | The Adamantium Bonds are contractually subordinated to amounts under the Fortress Credit Agreement and the Adamantium Secured Note, structurally senior to the Reg D/Reg A Bonds and the Notes offered hereby to the extent of the value of Adamantium’s assets, including the collateral securing the Adamantium Loan Agreement, and will be contractually senior to obligations under the Notes offered hereby. Between January 1, 2025 and March 31, 2025, we issued an additional $41.2 million of Adamantium Bonds (and borrowed a corresponding amount under the Adamantium Loan Agreement), with maturities ranging from December 2029 to March 2036 and interest rates between 13.0% and 16.0% per annum. |
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ANB Credit Agreement
The Issuer and PhoenixOp were borrowers under that certain Commercial Credit Agreement (the “ANB Credit Agreement”), which they entered into with Amarillo National Bank, a national banking association (“ANB”) on July 24, 2023. The ANB Credit Agreement provided for a $30.0 million revolving credit loan by ANB, and, as of June 30, 2024, the outstanding balance was $30.0 million. The proceeds from the borrowing under the ANB Credit Agreement were used in part to repay in full our outstanding facility with Cortland Credit Lending Corporation. ANB’s commitments under the ANB Credit Agreement and the loans thereunder were initially scheduled to terminate and mature, and be due and payable in full, on July 24, 2024. On July 24, 2024, we entered into an agreement that extended ANB’s commitments and the maturity of the loans under the ANB Credit Agreement to September 24, 2024. We fully repaid all amounts owed under the ANB Credit Agreement on August 12, 2024 in connection with entering into the Fortress Credit Agreement.
Fortress Credit Agreement
The Issuer and PhoenixOp, as borrower, entered into the Fortress Credit Agreement with Fortress on August 12, 2024. The Fortress Credit Agreement provides for a $100.0 million term loan facility (the “Fortress Term Loan”), borrowed in full on August 12, 2024, and a $35.0 million delayed draw term loan facility, which was borrowed in full on October 11, 2024 (any loans thereunder, together with the Fortress Term Loan, the “Fortress Tranche A Loans”). On December 18, 2024, the Fortress Credit Agreement was amended to, among other things, provide for a new tranche of term loans (the “Fortress Tranche C Loan”) in an aggregate principal amount of $115.0 million that was borrowed in full on December 18, 2024. On April 16, 2025, the Fortress Credit Agreement was further amended to, among other things, establish a new tranche of term loans (the “Fortress Tranche D Loans”) in an aggregate principal amount of $50.0 million, with $25.0 million aggregate principal amount borrowed on April 16, 2025 and $25.0 million aggregate principal amount to be funded on a delayed draw basis, subject to the sole discretion of the lenders. The Fortress Credit Agreement also includes an $8.5 million tranche of loans (the “Fortress Tranche B Loan” and, together with the Fortress Tranche A Loans, the Fortress Tranche C Loan, and the Fortress Tranche D Loans, the “Fortress Loans”), which represents a contingent principal obligation that is only due and payable (together with accrued interest thereon) if subject to certain exceptions, either (a) the Company has not paid in full all outstanding principal and accrued interest on the Fortress Loans in cash by March 31, 2027 or (b) an Event of Default (as defined in the Fortress Credit Agreement) has occurred resulting from the failure to pay principal or interest when due under the terms and conditions of the Fortress Credit Agreement.
Obligations under the Fortress Credit Agreement are secured by substantially all of the assets of Phoenix Equity and its subsidiaries that have guaranteed the obligations of the obligors under the Fortress Credit Agreement, subject to certain exceptions (the Issuer, PhoenixOp, and such subsidiaries, collectively, the “Credit Parties”). Furthermore, pursuant to that certain Assignment of Loans and Liens, dated as of August 12, 2024, among the Issuer, Phoenix Operating, ANB, Fortress, as administrative agent and as collateral agent, and the new lenders party thereto, ANB assigned, and Fortress assumed, all security interests granted by the Credit Parties in favor of ANB under the ANB Credit Agreement. The lenders under the Fortress Credit Agreement also purchased and assumed from ANB all of the outstanding extensions of credit made by ANB under the ANB Credit Agreement. As a result of the foregoing, the ANB Credit Agreement and all related documentation ceased to be of any force and effect.
The Fortress Term Loan and the Fortress Tranche B Loan were each subject to OID of 10.59907834%, and each of the Fortress Tranche A Loans made under the delayed draw term loan facility, the Fortress Tranche C Loan, and the Fortress Tranche D Loans were subject to 3.00% OID.
Borrowings under the Fortress Credit Agreement bear interest at a rate per annum equal to Term SOFR (as defined in the Fortress Credit Agreement) plus 0.10% plus 7.00%. Interest on the Fortress Tranche A Loans and Fortress Tranche C Loan is payable quarterly in arrears. The outstanding principal amount of the Fortress Loans (including, if applicable, the Fortress Tranche B Loan) must be repaid as follows: (i) on December 31, 2026, $150.0 million of the outstanding principal amount of the Fortress Loans less the aggregate amount of all voluntary prepayments and mandatory prepayments made as of December 31, 2026; and (ii) the remaining aggregate outstanding principal amount on December 18, 2027. In connection with any payment in full of the Fortress Loans (whether by voluntary prepayment, acceleration, or on the maturity date), PhoenixOp will pay a repayment premium in an amount sufficient to achieve a MOIC (as defined in the Fortress Credit Agreement) of 1.18.
The Fortress Credit Agreement contains various customary affirmative and negative covenants, as well as financial covenants. The Fortress Credit Agreement requires the Issuer to maintain (a) a maximum total secured leverage ratio (i) as of the last day of any fiscal quarter ending on or before December 31, 2025 of less than or equal to 2.00 to 1.00 (commencing with the fiscal quarter ending December 31, 2024), and (ii) as of the last day of any fiscal quarter ending on or after March 31, 2026 of less than or equal to 1.50 to 1.00, (b) a minimum current ratio as of the last day of each calendar month of (i) 0.90 to 1.00 from September 30, 2024 through October 31, 2024, (ii) 0.80 to 1.00 from November 30, 2024 through November 30, 2025, (iii) 0.90 to 1.00 from December 31, 2025 through December 31, 2026, and (iv) 1.00 to 1.00 for each calendar month ending thereafter, and (c) a minimum asset coverage ratio
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as of the last day of any fiscal quarter (i) ending during the period from June 30, 2024 through December 31, 2024, of at least 2.00 to 1.00, (ii) ending during the period from March 31, 2025 through September 30, 2025, of at least 1.70 to 1.00, and (iii) ending during the period from December 31, 2025 and thereafter, of at least 2.00 to 1.00. The Fortress Credit Agreement also places certain limits on the Issuer’s ability to incur additional indebtedness, including the issuance of unsecured notes or bonds and accounts receivable factoring arrangements. As of December 31, 2024, we believe we were in compliance with all of the financial covenants contained in the Fortress Credit Agreement.
The Fortress Credit Agreement contains customary events of default, including, but not limited to, nonpayment of the Fortress Tranche A Loans or Fortress Tranche C Loan and any other material indebtedness, material inaccuracies of representations and warranties, violations of covenants, certain bankruptcies and liquidations, certain material judgments, and certain events related to the security documents.
As described above, a portion of the proceeds from the Fortress Term Loan was used to pay all amounts owed under the ANB Credit Agreement. The Issuer and PhoenixOp will use the remaining proceeds of the Fortress Loans to finance the development of oil and gas properties in accordance with the approved plan of development as provided in the Fortress Credit Agreement.
Adamantium Debt
Adamantium was formed on June 21, 2023, as a wholly owned financing subsidiary of the Issuer for the purpose of undertaking financing efforts under Regulation D and subsequently loaning amounts to the Issuer and/or its subsidiaries, as needed. Adamantium offers high net worth individuals Adamantium Bonds pursuant to an offering under Rule 506(c) of Regulation D that commenced in September 2023, and does not expect to undertake financing efforts under Regulation A. Adamantium has in the past, and may in the future, issue debt securities in other offerings exempt from registration under the Securities Act under Section 4(a)(2) thereof or any other available exemption, including, for example, the Adamantium Secured Note.
On September 14, 2023, the Issuer, as borrower, entered into the Adamantium Loan Agreement with Adamantium, as lender. On October 30, 2023, the Issuer, Adamantium, and PhoenixOp entered into an amendment to the Adamantium Loan Agreement to add PhoenixOp as a borrower, and on November 1, 2024 entered into another amendment to increase the loan amount thereunder. The Adamantium Loan Agreement provides for up to $407.0 million in aggregate principal amount of borrowings in one or more advances, comprising $400.0 million from the proceeds of Adamantium Bonds and $7.0 million from the proceeds of the Adamantium Secured Note. Adamantium may, but is not guaranteed to, issue $400 million in aggregate principal amount of Adamantium Bonds to fund advances to the Issuer and PhoenixOp pursuant to the Adamantium Loan Agreement. The timing of any advance under the Adamantium Loan Agreement is contingent upon Adamantium’s receipt of proceeds from the sale of Adamantium Securities. Each advance will have a maturity and interest rate that matches the terms of the respective Adamantium Securities sold prior to such advance and to which such advance relates. We expect to use the proceeds of borrowings under the Adamantium Loan Agreement (i) to purchase mineral rights and non-operated working interests, as well as additional asset acquisitions, (ii) to finance potential drilling and exploration operations of one or more subsidiaries (including PhoenixOp), and (iii) for other working capital needs.
As of December 31, 2024, $128.1 million aggregate principal amount of Adamantium Bonds was outstanding, with maturity dates ranging from five to eleven years from the issue date and interest rates ranging from 13.0% to 16.0% per annum, and $7.0 million aggregate principal amount was outstanding under the Adamantium Secured Note, which initially matures in November 2031, has an interest rate of 16.5% per annum, and is secured by Adamantium’s rights under the Adamantium Loan Agreement, and, in each case, the corollary amount of borrowings was outstanding under the Adamantium Loan Agreement. Between January 1, 2025 and March 31, 2025, we issued an additional $41.2 million of Adamantium Bonds (and borrowed a corresponding amount under the Adamantium Loan Agreement), with maturities ranging from December 2029 to March 2036 and interest rates between 13.0% and 16.0% per annum.
The Adamantium Securities contain customary events of default and may be redeemed at the option of Adamantium at any time without premium or penalty. The holders of Adamantium Bonds also have a right to request redemption of their bonds in certain circumstances at a discount to par, subject to a limit of 10% of the then-outstanding principal amount of Adamantium Bonds in any given calendar year. The holder of the Adamantium Secured Note has the right to request redemption of its note at par, subject to a limit of $5.0 million in aggregate principal amount of the Adamantium Secured Note in any 12-month period.
Amounts loaned under the Adamantium Loan Agreement are secured by mortgages on certain of our properties, which mortgages are junior to the security interest under the Fortress Credit Agreement and other existing and future senior secured indebtedness. The aggregate outstanding amount of all advances under the Adamantium Loan Agreement may not exceed 100% of the aggregate total discounted present value of the junior mortgages serving as collateral thereunder, after deducting any allocable amount securing any of our outstanding senior indebtedness (the “Adamantium Loan-to-Value Ratio”). The value of such collateral will be determined by one or more reserve studies performed by a third party retained by us on an annual basis. In the event the aggregate amount outstanding under the Adamantium Loan Agreement exceeds the Adamantium Loan-to-Value Ratio, we may cure such deficiency by either pledging additional collateral or repaying a portion of the borrowings under the Adamantium Loan Agreement until the Adamantium Loan-to-Value Ratio is achieved.
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At the option of Adamantium, an advance may be made on either (i) a current basis, whereby the Issuer makes interest-only monthly payments in cash to Adamantium on the tenth day of each month or (ii) an accrual basis, whereby interest is compounded monthly and the Issuer will pay all accrued and unpaid interest at maturity of the respective advance. Interest will accrue a full pro rata portion of the annual rate of interest for each calendar month regardless of the number of days an advance is outstanding during such calendar month, on the same terms as the interest payable on the Adamantium Securities sold prior to such advance and to which such advance relates. On each respective maturity date for advances made on both a current and accrual basis, the outstanding principal amount, together with all accrued and unpaid interest thereon, will mature and be due and payable to Adamantium. To the extent the Adamantium Securities are accelerated or prepaid, in whole or in part, the Issuer will be obligated to pay or prepay, in whole or in part, all or any part of any outstanding indebtedness under the Adamantium Loan Agreement so as to satisfy the obligations and terms of the accelerated or prepaid Adamantium Securities. Adamantium will use any amounts repaid under the Adamantium Loan Agreement to repay the corresponding Adamantium Securities. The Adamantium Loan Agreement is not a revolving facility and the Issuer may not reborrow amounts repaid.
The Adamantium Loan Agreement can be amended or waived with the consent of the Issuer and Adamantium, including in order to change the amount, rate, payment terms, collateral package, and borrowers thereunder. The consent of holders of the Adamantium Securities, the Reg D/Reg A Bonds, and/or the Notes is not required for any amendment or waiver of the Adamantium Loan Agreement, and any such amendment or waiver may be adverse to the interests of such holders. Because Adamantium is a wholly owned financing subsidiary of the Issuer with common management, there exists the potential for conflicts of interest with respect to decisions regarding the Adamantium Loan Agreement, including with respect to waivers and amendments thereto. Management is committed to fulfilling its fiduciary duties and operating in good faith. See “Risk Factors—Risks Related to the Notes and this Offering—The Notes are the Issuer’s obligations alone, and will be structurally subordinated to all obligations of the Issuer’s existing and future subsidiaries.”
Reg D/Reg A Bonds
As of December 31, 2024, the Issuer had $602.7 million aggregate principal amount outstanding of unsecured bonds issued pursuant to Regulation D or Regulation A, consisting of:
| (a) | $13.5 million aggregate principal amount outstanding of Senior Reg D Bonds, which rank pari passu with the Reg A Bonds, are contractually subordinated to amounts under the Fortress Credit Agreement, are contractually senior to obligations under the Subordinated Reg D Bonds, and will be contractually senior to obligations under the Notes offered hereby, comprising: |
| (i) | $0.9 million aggregate principal amount outstanding of 2020 506(b) Bonds, which are unsecured bonds offered and sold pursuant to an offering under Rule 506(b) of Regulation D that commenced in July 2020 and terminated in September 2021, with initial maturity dates ranging from one to four years from the issue date and an interest rate of 5.0% per annum; |
| (ii) | $2.1 million aggregate principal amount outstanding of 2020 506(c) Bonds, which are unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in October 2020 and terminated in July 2022, with maturity dates ranging from one to four years from the issue date and interest rates ranging from 13.0% to 15.0% per annum; and |
| (iii) | $10.5 million aggregate principal amount outstanding of July 2022 506(c) Bonds, which are unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in July 2022 and terminated in December 2022, with a maturity date of five years from the issue date and an interest rate of 11.0% per annum; |
| (b) | $484.3 million aggregate principal amount outstanding of Subordinated Reg D Bonds, which are contractually subordinated to obligations under the Fortress Credit Agreement, the Reg A Bonds, and the Senior Reg D Bonds, and will be contractually subordinated to obligations under the Notes offered hereby, comprising: |
| (i) | $69.0 million aggregate principal amount outstanding of Series AAA through Series D-1 December 2022 506(c) Bonds, which are unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in December 2022 and terminated in August 2023, with maturity dates ranging from nine months to seven years from the issue date and interest rates ranging from 8.0% to 12.0% per annum; and |
| (ii) | $415.3 million aggregate principal amount outstanding of Series U through Series JJ-1 August 2023 506(c) Bonds, which are unsecured bonds offered and sold to date pursuant to an offering under Rule 506(c) of Regulation D that commenced in August 2023 with maturity dates ranging from one to eleven years from the issue date and interest rates ranging from 9.0% to 14.0% per annum; and |
| (c) | $104.9 million aggregate principal amount outstanding of Reg A Bonds, which are unsecured bonds offered and sold to date pursuant to an offering under Regulation A, which commenced in December 2021 and are being offered on a continuous basis, which Reg A Bonds rank pari passu with the Senior Reg D Bonds, are contractually senior to obligations under the Subordinated Reg D Bonds, and will be contractually senior to obligations under the Notes offered hereby. |
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The Reg D/Reg A Bonds contain customary events of default. The Reg D/Reg A Bonds may be redeemed at the option of the Issuer at any time without premium or penalty. The Issuer will also be obligated to offer to holders of Reg A Bonds the right to have their Reg A Bonds repurchased upon a change of control (as described in the indenture governing the Reg A Bonds). The holders of Reg D/Reg A Bonds (other than the 2020 506(b) Bonds and 2020 506(c) Bonds) also have a right to request redemption of their bonds in certain circumstances at a discount to par, subject to a limit of 10% of the then-outstanding principal amount of the applicable series in any given calendar year.
Between January 1, 2025 and March 31, 2025, the Issuer issued an additional $126.7 million of August 2023 506(c) Bonds with maturities ranging from December 2025 to March 2036 and interest rates between 9.0% and 14.0% per annum.
Contractual Obligations and Commitments
A summary of our contractual obligations, commitments, and other liabilities as of December 31, 2024 is presented below:
| (in thousands) | 2025 | 2026-2027 | 2028-2029 | Thereafter | Total | |||||||||||||||
| Debt obligations(1) |
$ | 103,319 | $ | 416,255 | $ | 58,424 | $ | 409,889 | $ | 987,887 | ||||||||||
| Interest payable(2) |
80,488 | 135,451 | 87,063 | 667,443 | 970,445 | |||||||||||||||
| Operating lease obligations(3) |
1,293 | 2,657 | 2,480 | 3,047 | 9,477 | |||||||||||||||
| Deferred closing arrangements(4) |
7,189 | 3,324 | — | — | 10,513 | |||||||||||||||
| Drilling rig obligations(5) |
8,442 | — | — | — | 8,442 | |||||||||||||||
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| Total |
$ | 200,731 | $ | 557,687 | $ | 147,967 | $ | 1,080,379 | $ | 1,986,764 | ||||||||||
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| (1) | Debt obligations represent the principal amounts outstanding under our short-term debt and long-term debt (including the current portion) as of December 31, 2024 and are based on the stated maturity dates. The table above assumes no prepayments or early redemptions, and does not reflect additional debt incurred or repaid after December 31, 2024. |
| (2) | Interest payable is estimated based on final maturity dates of debt securities outstanding at December 31, 2024 and does not reflect anticipated future refinancing, early redemptions, or new debt issuances after December 31, 2024. Floating rate interest obligations are estimated based on rates as of December 31, 2024. |
| (3) | We lease office space in California, Colorado, Florida, Texas, and Wyoming, which have non-cancelable lease agreements expiring in various years through April 2034. The amounts in this table represent the minimum lease payments required over the term of the lease. |
| (4) | For certain mineral interest acquisitions, we have agreed to pay the purchase price in installments together with interest, with interest rates ranging from 8.0% to 15.0% per annum. The amounts in this table represent the remaining payments due over bespoke terms ranging from 11 to 48 months. |
| (5) | Drilling rig obligations represent amounts outstanding under the remaining term of drilling rig contracts entered into with third parties during the year ended December 31, 2024. |
Critical Accounting Policies and Use of Estimates
This discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of financial statements in conformity with GAAP requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue, and expenses, and disclosures of contingent assets and liabilities, including with respect to quantities of oil, natural gas, and NGL reserves that are the basis for the calculations of depreciation, depletion, and amortization and determinations of impairment of oil and natural gas properties. Our significant accounting policies are described in Note 2, “Significant Accounting Policies,” of the accompanying consolidated financial statements included elsewhere in this prospectus.
Critical accounting policies are those that we consider to be the most important in portraying our financial condition and results of operations and also require the greatest amount of judgments by management, including requiring an accounting estimate to be made based on assumptions about matters that are highly uncertain at the time the estimate is made, if different estimates reasonably could have been used, or if changes in the estimate that are reasonably possible could materially impact the financial statements. We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the facts and circumstances at the time the estimates are made. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Judgments or uncertainties regarding the application of these policies may result in materially different amounts being reported under different conditions or using different assumptions. There can be no assurance that actual results will not differ from those estimates and assumptions.
Furthermore, reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve
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estimate is a function of the quality of available data and of engineering and geological interpretation and judgment along with estimated selling prices. As a result, reserve estimates may materially differ from the quantities of oil and natural gas that are ultimately recovered. We consider the following policies to be the most critical in understanding the judgments that are involved in preparing our consolidated financial statements.
Oil and Gas Properties
We invest in crude oil and natural gas properties, including mineral interests and working interests as a non-operator and operator. E&P activities are accounted for in accordance with the successful-efforts method of accounting. Under this method, costs of acquiring proved mineral interests in crude oil and natural gas properties, development wells, related plant and equipment, and related asset retirement obligation assets are capitalized. Costs of proved but undeveloped wells are initially capitalized to wells-in-progress until the well becomes productive. Once the well is productive, accumulated capitalized costs are reclassified to proved and producing properties and accounted for following the successful efforts method of accounting. Costs are also capitalized for unevaluated wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the unevaluated well has found a sufficient quality of reserves to justify its completion as an economically and operationally viable producing well. If proved reserves are not found, unevaluated well costs are expensed as dry holes. All other unevaluated wells and costs, and all general and administrative costs unrelated to acquisitions, are expensed as incurred.
Depletion of capitalized costs is recorded using the units-of-production method based on proved reserves. The depletion rate is determined by dividing the cumulative recovered barrels of oil equivalent by the estimated ultimate recovery by well and averaged among all wells within the pooled unit. This rate is multiplied by the original cost basis and reduced by depletion taken in prior periods. The cost basis remaining represents the percentage of the asset remaining to be recovered by the wells within the pooled unit.
Impairment of Long-lived Assets
We follow the provisions of FASB ASC 360, Property, Plant, and Equipment (“ASC 360”). ASC 360 requires that our long-lived assets be assessed for potential impairment of their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Proved oil and natural gas properties are evaluated by geologic basin for potential impairment. In accordance with the successful efforts method of accounting, impairment on proved properties is recognized when the estimated undiscounted projected future net cash flows or evaluation value using expected future prices of a geologic basin are less than its carrying value. If impairment occurs, the carrying value of the impaired geologic basin is reduced to its estimated fair value.
Unproved oil and natural gas properties do not have producing properties and are valued on acquisition by management, with the assistance of an independent expert when necessary. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers (i) estimated potential reserves and future net revenues from an independent expert (ii) our history in exploring the area, (iii) our future drilling plans per our capital drilling program prepared by our reservoir engineers and operations management, and (iv) other factors associated with the area. Impairment is taken on the unproved property value if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions that, with the passage of time, may prove to be materially different from actual results.
Revenue from Contracts with Customers
We recognize our revenues following ASC Topic 606, Revenue from Contracts with Customers. Our revenues are primarily derived from our interests in the sale of oil and natural gas production. Oil, natural gas, and NGL sales revenues are generally recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied, and collectability is reasonably assured. In circumstances where we are the non-operator or mineral right owner, we do not consider ourselves to have control of the product, and revenues are recognized net of production taxes and post-production expenses. The performance obligations for our contracts with customers are satisfied as of a point in time through the delivery of oil and natural gas to our customers. Given the inherent time lag between when oil, natural gas, NGL production, and sales occur and when operators or purchasers often make disbursements to royalty interest owners and due to the large potential fluctuations of both oil production and sale price, a significant portion of our revenue may represent accrued revenue based on estimated net sales volumes and estimated selling prices.
For crude oil and natural gas produced by PhoenixOp, each delivery order is treated as a separate performance obligation. Revenue is recognized when the performance obligation is satisfied, which typically occurs at the point in time control of the product transfers to the customer.
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Revenue is measured as the amount we expect to receive in exchange for transferring commodities to the customer. Our commodity sales are typically based on prevailing market-based prices. When deliveries contain multiple products, an observable standalone selling price is generally used to measure revenue for each product. Revenues from product sales are presented separately from post-production expenses, including transportation costs, as we control the operated production prior to its transfer to customers.
Recent Accounting Pronouncements
In November 2024, the FASB issued Accounting Standards Update (“ASU”) 2024-03, Income Statement—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which requires companies to provide more detailed disclosures about the disaggregation of income statement expenses. The ASU aims to enhance the transparency and usefulness of financial statements by providing better insight into the components of expense line items, and becomes effective for fiscal years beginning after December 15, 2026 and interim periods within fiscal years beginning after December 15, 2027. We are currently evaluating the impact of the standard on our financial statements and disclosures.
Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates or from counterparty or customer credit risk, each as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. These 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. All of our instruments that are sensitive to market risk were entered into for purposes other than speculative trading. Also, gains and losses on these instruments are generally offset by losses and gains on the offsetting expenses.
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to the oil, NGL, and natural gas production of our E&P operators, including PhoenixOp, which affects our revenue from PhoenixOp and the royalty payments we receive from our other E&P operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, NGL, and natural gas has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices that our E&P operators receive for oil, NGL, and natural gas production depend on many factors outside of their and our control, such as the strength of the global economy and global supply and demand for the commodities they produce.
To reduce the impact of fluctuations in oil, NGL, and natural gas prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil, NGL, and natural gas production through various transactions that limit the risks of fluctuations of future prices. Additionally, we are required to hedge a portion of anticipated oil production pursuant to certain covenants under the Fortress Credit Agreement. As a part of our derivative contracts, as of December 31, 2024, over the next three years, we had nearly 5.5 million Bbl hedged at a weighted average floor of $64.24 per Bbl, which would generate revenues of approximately $350 million over the same period, assuming a price of $0 per Bbl. We plan to continue our practice of entering into such transactions to reduce the impact of commodity price volatility on our cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling. These hedging activities are intended to limit our exposure to product price volatility and to maintain stable cash flows.
By using derivative instruments to economically limit exposure to changes in commodity prices, we expose ourselves to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes us, which creates credit risk. See “—Counterparty and Customer Credit Risk” below.
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The fair market value of our commodity derivative contracts was a net liability of $7.3 million as of December 31, 2024. Based upon our open commodity derivative positions at December 31, 2024, a hypothetical 10% increase in the NYMEX WTI price would increase our net derivative liability position by $45.8 million, while a 10% decrease in the NYMEX WTI price would decrease our net liability position by $45.8 million.
A $1.00 per Bbl change in our realized oil price would have resulted in a $4.2 million and a $1.4 million change in our oil revenues for the years ended December 31, 2024 and 2023, respectively. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.1 million change and a $0.2 million change in our natural gas revenues for the years ended December 31, 2024 and 2023, respectively. A $1.00 per Bbl change in NGL prices would have resulted in a less than $0.1 million change and a $0.2 million change in our NGL revenues for the years ended December 31, 2024 and 2023, respectively. Revenues from oil sales contributed 93.2% and 89.5%, revenues from natural gas sales contributed 2.0% and 5.8%, and revenues from NGL sales contributed 3.9% and 4.7% of our consolidated revenues for the years ended December 31, 2024 and 2023, respectively.
Interest Rate Risk
Our primary exposure to interest rate risk results from outstanding borrowings under our credit facilities, which bear interest at a floating rate. The average annual interest rate incurred when such facility was outstanding on our borrowings under the Fortress Credit Agreement during the year ended December 31, 2024 was 11.83%. Assuming no change in the amount of borrowings under the Fortress Credit Agreement outstanding, a hypothetical 100 basis point increase or decrease in the average interest rate under these borrowings would increase or decrease our interest expense on those borrowings on an annual basis by approximately $2.5 million. See “—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement.”
Counterparty and Customer Credit Risk
Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds in major financial institutions. We often have balances in excess of the federally insured limits.
Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. We evaluate the credit standing of such counterparties as we deem appropriate. We have determined that our counterparties have an acceptable credit risk for the size of derivative position placed; therefore, we do not require collateral or other security from our counterparties. Additionally, we use master netting arrangements to minimize credit risk exposure.
Our principal exposures to credit risk are through receivables generated by the production activities of our operators. For the year ended December 31, 2024, one third-party E&P operator made up 21% of our consolidated revenue, as compared to one third-party E&P operator that made up 11% of our consolidated revenue for the year ended December 31, 2023, and four third-party E&P operators that made up 16%, 16%, 15%, and 14% of our consolidated revenue for the year ended December 31, 2022. Similarly, as of December 31, 2024, we had concentrations in accounts receivable of 17%, 15%, and 13% with three third-party E&P operators, as compared to 26% and 14% with two third-party E&P operators as of December 31, 2023, and 34% and 10% with two third-party E&P operators as of December 31, 2022. Although we are exposed to a concentration of credit risk due to our reliance on our operators, we do not believe the loss of any single purchaser would materially impact our operating results as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. If multiple purchasers were to cease making purchases at or around the same time, we believe there would be challenges initially, but there would be ample markets to handle the disruption. Additionally, recent rulings in bankruptcy cases involving our third-party E&P operators have stipulated that royalty owners must still be paid for oil, gas, and NGL extracted from their mineral acreage during the bankruptcy process. In light of this, we do not expect the entry of one of our operators into bankruptcy proceedings would materially affect our operating results.
Furthermore, as PhoenixOp increases the extent of its operations and generates revenue from the sale of crude oil and natural gas delivered to purchasers, we expect that our concentration of revenue and accounts receivable among a limited number of third-party E&P operators will decrease and we will achieve greater control over the terms of the sales agreements entered into among PhoenixOp and the purchasers.
See “Business—Our E&P Operators” for a further discussion of our E&P operator relationships.
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Overview
We operate in the oil and gas industry and execute on a three-pronged strategy involving (i) direct drilling operations of operated working interests, (ii) the acquisition of royalty assets, and (iii) the acquisition of non-operated working interest assets. Our direct drilling operations are currently primarily focused on development efforts in the Williston Basin in North Dakota and Montana and the Powder River and Denver Julesburg Basins in Wyoming. Our royalty and working interest acquisitions center around a variety of assets, including mineral interests, leasehold interests, overriding royalty interests, and perpetual royalty interests. These efforts have historically targeted assets in the Williston, Permian, Powder River, Uintah, and DJ Basins. We are agnostic as to geography and prioritize operational and asset potential when executing on our strategy.
We began operations in 2019 with the development of our specialized software system, which we have designed and improved over time to support our ability to identify, analyze, underwrite, transact, and manage our oil and gas assets. In 2019, we acquired our first mineral interest asset and began to generate revenue. In 2020, we expanded our operations and team to include specialists across a variety of key focus areas. From 2020 to 2024, we experienced significant growth in operations. For example, in 2020, the E&P operators of our properties operated 725 gross and 2.8 net productive development wells on the acreage underlying our mineral and royalty interests, and the total acreage underlying our gross and net royalty interests was 177,824 and 1,506, respectively. In the four years since then, the E&P operators of our properties have operated an additional 6,312 gross and 75.1 net productive development wells on the acreage underlying our mineral and royalty interests, of which approximately 463 gross and 43.2 net productive development wells were drilled in 2024 alone. As of December 31, 2024, we had 3,962,065 and 531,120 acres underlying our gross and net royalty interests, respectively, as compared to 177,824 and 1,506 acres underlying our gross and net royalty interests, respectively, at December 31, 2020. Furthermore, our total production for the year ended December 31, 2020 was under 0.2 million Boe as compared to over 4.7 million Boe for the year ended December 31, 2024. In the same period our number of employees grew from 21 at December 31, 2020 to 135 at December 31, 2024. Additionally, we commenced direct drilling operations and spudded our first wells in the third quarter of 2023 and drilled a total of 42 gross and 38.6 net productive development wells in 2024. We expect these direct drilling operations to be a core component of our business strategy going forward.
Since our initial mineral interest asset acquisition in 2019, we have leveraged our specialized software system and experienced management team to identify asset opportunities that fit our desired criteria and potential for returns. While we evaluate and acquire a wide variety of assets, we have historically prioritized assets with potential for high monthly recurring cashflows and primarily target assets that have a potential payback within the short to medium term and long-term cashflows.
Since 2019, we have completed 3,074 mineral, royalty, and leasehold interest acquisitions from landowners and other mineral interest owners, representing approximately 531,120 NRAs of royalty assets and 476,473 of NMAs of leasehold assets as of December 31, 2024. Over that same period, in addition to completing numerous small transactions, we completed more than 56 transactions larger than 1,000 NMAs that account for approximately 72% of our NMAs. We have acquired mineral, royalty, and leasehold interests from individuals, families, trusts, partnerships, small minerals aggregators, minerals brokers, large private minerals companies, private oil and gas E&P companies, and public minerals companies. We also actively manage our portfolio of assets and, as of December 31, 2024, have sold 3,152 NMAs since 2019.
Following the acquisition of an asset, we typically share in the proceeds of the natural resources extracted and sold by a third-party E&P operator. For certain assets, we operate our own direct drilling operations through PhoenixOp.
For the years ended December 31, 2022, 2023, and 2024, we had revenue of $54.6 million, $118.1 million, and $281.2 million, respectively, net income (loss) of $5.7 million, $(16.2) million, and $(24.8) million, respectively, and EBITDA of $29.7 million, $65.9 million, and $150.7 million, respectively. As of December 31, 2022, 2023, and 2024 we had total assets of $157.0 million, $493.2 million, and $1,029.1 million, respectively, total liabilities of $148.3 million, $498.0 million, and $1,063.1 million, respectively (inclusive of total indebtedness of $117.4 million, $447.9 million, and $987.9 million, respectively), and retained earnings (accumulated deficit) of $6.5 million, $(9.7) million, and $(34.5) million, respectively. In 2023 and 2024, we incurred a significant amount of debt in order to accelerate the growth of our business by acquiring additional assets and establishing our direct drilling operations. As a result, our cash flows from operations alone would not have been sufficient to service the required cash interest and principal payment obligations under our then-existing debt in 2023 and 2024. Furthermore, as of December 31, 2024, we estimate that we will need to make approximately $749.3 million and $3,224.8 million in capital expenditures to develop all our proved and probable undeveloped reserves, respectively, and that we will need to raise approximately $658.9 million in additional capital through the end of 2028 to fund such development. Although we expect our cash flows from operations to be sufficient to service cash interest and principal payment obligations under our debt for the foreseeable future, there can be no assurance as to the sufficiency of our cash flows for that purpose, and we do not expect such cash flows alone to be adequate to fund both our debt service obligations and the development of our reserves. Therefore, we expect to require additional capital to fund our growth and may require additional liquidity to service our debt. As a result, we may use the proceeds of additional debt, including the Notes offered hereby, to make interest and principal payments on our existing debt. See “Risk Factors—Risks Related to Our Business and Operations— The acquisition and development of our properties, directly or through our third-party E&P operators, will require substantial capital, and we and our third-party E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all, including as a result of increases in the cost of capital resulting from Federal Reserve policies in the past few years and otherwise,” “Risk Factors—Risks Related to Our Indebtedness—Despite our current level of indebtedness, we will still be able to incur substantially more debt. This could further exacerbate the risks to our financial condition described above,” “Risk Factors—Risks Related to Our Indebtedness—We may not be able to generate sufficient cash to service all of our existing and future indebtedness, including the Notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful,” “Risk Factors—Risks Related to the Notes and this Offering—We may invest or spend the proceeds of this offering in ways with which you may not agree,” “Use of Proceeds,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
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Market Opportunity
Our royalty and working interest acquisitions generally focus on specific subsets of mineral and leasehold assets in the United States. From a market perspective, we focus on highly attractive and defined basins, currently serviced by top-tier operators, with assets that we believe will generate high near-term cash flow. All the assets we seek to acquire are purchased at what management believes are attractive price points and have a liquidity profile that is desirable in the secondary market. We generally seek to acquire assets that have a near-term payback and long-term residual cash flow upside.
Business Strategy
Our three-pronged strategy centers around (i) direct drilling operations of operated working interests, (ii) the acquisition of royalty assets, and (iii) the acquisition of non-operated working interest assets.
Direct Drilling Operations
We currently run our own direct drilling activities through PhoenixOp. Throughout 2024, we increased the extent to which we run our own direct drilling operations and expect to continue to grow our drilling activities going forward. We intend to actively drill and develop select assets in an effort to maximize value and resource potential, and we will generally seek to increase our production, reserves, and cash flow from operations over time. We have identified a number of potential drilling locations that we believe have the potential for attractive growth and opportunities. In accordance with that business plan, we acquired our second drilling rig in October 2024 and signed an agreement in January 2025 to take possession of our third drilling rig in April 2025.
As we rely more on our own direct drilling operations, our capital expenditures and operating expenses have also increased significantly, and we expect this increase in capital and operating expenses to continue as compared to our previous business model, which relied heavily on royalty and working interest acquisitions. As such, in 2025, we expect to have increased needs for additional capital in excess of cash flows from operating activities in order to fund growth of our business and the development of our reserves. We expect to require additional outside funding, including through sales of the Notes offered hereby, to successfully execute this business strategy. Although we believe that running our own direct drilling operations will require significantly greater funds than partnering with a third-party operator, we believe that this strategy will provide greater control of cashflow, increased revenue, and larger potential for shorter payback periods as compared to returns on royalty assets and working interest assets. We expect that this shift in our business model will allow us to capture more of the upside from the use of our specialized software system. As of March 31, 2025 we estimate that our direct drilling operations will require approximately $423.6 million in additional capital throughout the rest of 2025 in order to achieve our intended business plan. We expect that these capital needs will be met in the near to medium term by capital contributions to PhoenixOp by us, which we expect to fund from time to time in varying amounts through a combination of assets, cash from operations, and the proceeds from loans and offerings of debt securities, including the Notes offered hereby. As of March 31, 2025, we had contributed approximately $192.9 million in cash and $44.8 million in lease assets to PhoenixOp. As of March 31, 2025, we had 202.6 million available for us to borrow under the Adamantium Loan Agreement (assuming Adamantium is able to issue the corresponding amount of Adamantium Securities). We also continue to issue August 2023 506(c) Bonds and have $63.0 million of additional headroom until we reach the announced target offering amount of $750.0 million. In the near term, we intend to raise the target offering amount of the August 2023 506(c) Bonds to $1,500.0 million. Our funding of additional amounts to PhoenixOp will not be subject to specific milestones or triggering events, but instead will be guided by our business judgment in order to execute on our intended business plan. We intend to make such capital contributions to PhoenixOp until such time as PhoenixOp procures its own financing, if any, or has sufficient cash from operations to operate without supplemental financing from us. PhoenixOp is currently a borrower under certain of our loan agreements, including the Fortress Credit Agreement and Adamantium Loan Agreement, and could borrow amounts under such agreements directly. There is currently no committed amount of additional financing under the Fortress Credit Agreement. Although we have issued over $200 million of Adamantium Securities to date, there can be no assurance that we will be successful in issuing additional Adamantium Securities and utilizing then-available commitments under the Adamantium Loan Agreement. See “Risk Factors—Risks Related to Our Business and Operations—The acquisition and development of our properties, directly or through our third-party E&P operators, will require substantial capital, and we and our third-party E&P operators may be unable to obtain needed capital or financing on satisfactory terms or at all, including as a result of increases in the cost of capital resulting from Federal Reserve policies in the past few years and otherwise.”
Leases are contributed to PhoenixOp at a value equal to our cost of acquisition of the contributed asset, and we anticipate contributing additional oil and gas properties to PhoenixOp in the future. Leases are generally contributed in order for PhoenixOp to operate extraction activities on such assets with the requisite title and permissions. We expect to only contribute oil and gas properties to PhoenixOp that are located in an area where we own or lease enough continuous productive acreage to support meaningful mineral extraction activities. Whether and when we have properties we decide to contribute to PhoenixOp will depend on, among other things, our ability to acquire properties from multiple owners, the amount and quality of mineral reserves discovered on such properties, the presence of or proximity to third-party operators with existing extraction activities, and the suitability of the area’s topography for
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drilling and operating producing wells. See “Risk Factors—Risks Related to Our Business and Operations—We, through our investment in PhoenixOp and future assignment of oil and gas properties to PhoenixOp, conduct direct drilling and extraction activities. Such activities pose additional risks to us.”
Royalty and Working Interest Acquisitions
For our royalty and working interest acquisitions, we have developed a process for the identification, acquisition, and monetization of assets. Below is a general illustration of our process:
| • | Our specialized software provides market intelligence to identify and rank potential assets and support our acquisition strategy and functions. |
| • | We make contact with the owner of the asset and begin the conversation on how we can increase the value of the property for the owner. |
| • | We provide the potential seller with a packet detailing our business, industry data, property valuation, and an all-cash offer based on the valuation. |
| • | Our sales team engages the potential seller to discuss the terms of the sale and the value of the property. |
| • | We handle the closing of the property and the property is migrated to our portfolio. |
| • | We utilize our land rights to extract natural resources from the property through third-party operators or determine to proceed with our own direct drilling operations. |
| • | We collect a portion of the revenue generated from the natural resources extracted and sold by a third-party operator. Our share of the revenue depends on the type of asset, either mineral rights or non-operated working interests, and the underlying contract with the third-party operator. |
| • | We continue to operate the property to extract the minerals through third-party operators or PhoenixOp until we decide to sell the property rights. |
Separate from the ordinary royalty income assets, we maintain a structural discipline to participate in non-operated working interests, in part for their tax benefits. Due to favorable IRS treatment, marrying this asset class to our pure royalty income creates an augmented “write off” strategy whereby the balanced portfolio effectively creates little to no annual taxable income. Functionally, the transactions we enter into are similar to traditional real estate transactions with respect to the mechanics. A seller agrees to sell to us, a purchase and sale agreement is executed, earnest money is conveyed, and manual diligence and title review is conducted as an audit function prior to closing. Upon closing, the funds are conveyed to the seller and the title is recorded by us in the applicable jurisdiction. Assets can produce for upwards of 20 years; however, there is a considerable regression/depletion curve over the life of the asset. As such, we tend to focus on wells that have recently begun producing or are likely to have new production in the near term. We focus on a closed-loop process from discovery to acquisition to long-term balance sheet ownership. We believe the recurring nature of these cash flows will allow for considerable scale without material increases in fixed overhead.
Our Specialized Software System
Our software system is designed to be scalable and process inputs from a variety of internal and external sources, and supports our ability to identify, analyze, underwrite, and formally transact in the purchasing of oil and gas assets. Our software system operates across three key facets of our business:
| • | Asset Discovery – The data-driven system has customized inputs that are selected by management to pull in and incorporate data sets from multiple third-party sources through custom application interfaces that automatically retrieve updated information on a regular basis. For example, the system retrieves detailed land and title data and well-level data, including operator, production metrics, well status, dates of activities, well-specific activities, and historical reporting. The software system compiles these inputs and creates dashboards that can be accessed by management to analyze and review granular data on an asset-by-asset level. These dashboards present certain key information, including, among others, the geography of the asset, the estimated probability of future oil wells, the estimated predictability of the timing and value of cashflows, and local and national oil prices. We believe this process provides us with key market intelligence and insights, tailored to prioritize asset traits curated and targeted by management, to identify and rank potential assets. We believe this provides us with a competitive advantage because we are able to identify potentially valuable assets, based on our own hierarchy and prioritization of asset traits and data inputs, that may otherwise be overlooked by other industry participants. |
| • | Asset Grading and Estimates – The outputs from the asset discovery process are then run through a discounted cash flow model, using management inputs for discount rate and the price of oil, to generate asset value and pricing estimates. The software system grades these assets based on management’s desired target criteria for high probability of high near-term |
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| cash flow, and generates a summary version of assets to prospect for acquisition for our sales team. The system also generates an acquisition price for each asset, which informs the sales team as to the maximum price that we may be willing to offer in any prospective transaction. This process is used to further characterize high-priority targets for sales and acquisition efforts. |
| • | Asset Acquisition – Based on management input, the software system then routes the pricing and asset information from the asset grading and estimates process through an automated document generator to create customized, asset-specific document packages for utilization and distribution by our sales team. The workflow for these document packages is then processed and monitored using our internally developed software, which distributes the documents to our operations team for the preparation of an offering and sale package, which is then delivered to the prospective seller. Using relationship management features within our internally developed software, the sales team is able to record notes and each opportunity can be tracked from its original data upload through the lifecycle of the sales process. |
While the data inputs utilized by our software system are largely based on public information, considerable customization and coding has been undertaken to generate a system that we can successfully leverage in our business. This software was designed and built by us to address our specific needs, and we are not aware of a similar competitive product. We rely on trade secret laws to protect our software system and do not own any registered copyright, patent, or other intellectual property rights regarding our software. However, we believe the investment of significant monetary and intellectual resources have created a system that would be difficult to replicate. We currently have no intention of licensing or selling our software. See “Risk Factors—Risks Related to Legal, Regulatory, and Environmental Matters—We do not currently own any registered intellectual property rights relating to our software system and may be subject to competitors developing the same technology.”
Our Oil and Natural Gas Properties
Productive Wells
Productive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells. As of December 31, 2024, we owned mineral, royalty, and working interests in 7,036 productive wells, the majority of which are oil wells that produce natural gas and NGL.
As of December 31, 2024, we had 105 wells that fall under our “wells in progress” (“WIP”) category and we had 35.1 net WIP. We define a WIP as a development well in a stage preliminary to production. We utilize both proprietary and public systems to identify WIPs based on four distinct criteria: (1) a well that is not actively being drilled but is in the process of being developed; (2) a well currently being drilled and awaiting completion; (3) a drilled well in the completion process; and (4) a drilled well that has been completed but is not yet producing. This term serves as a guide in our acquisition strategy, enabling us to pinpoint lower-risk investment opportunities for our stakeholders.
Drilling Results
In the year ended December 31, 2024, the E&P operators of our properties, including PhoenixOp, drilled 463 gross and 43.2 net productive development wells on the acreage underlying our mineral and royalty interests. This compares to 1,965 and 971 gross productive development wells and 19.2 and 8.7 net productive development wells drilled by E&P operators on the acreage underlying our mineral and royalty interests in the years ended December 31, 2023 and 2022, respectively.
Included in our total drilled wells figures, as of December 31, 2024, PhoenixOp had drilled a total of 42 gross and 38.6 net productive development wells, all of which were drilled in the Williston Basin in North Dakota and Montana. PhoenixOp has also drilled a total of six gross and six net saltwater disposal wells, and had 39 gross and 30.1 net development wells in progress as of December 31, 2024.
As a holder of mineral and royalty interests, we generally are not provided information as to whether any wells drilled on the properties underlying our acreage are classified as exploratory. We are not aware of any dry holes drilled on the acreage underlying our mineral and royalty interests during the relevant periods.
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Wells
As of December 31, 2024, we had 7,037 total gross wells and 77.9 total net wells. The following table sets forth information about the productive wells in which we have a mineral or royalty interest as of December 31, 2024:
| Well Count | ||||||||||||||||
| Oil | Gas | |||||||||||||||
| Basin or Producing Region |
Gross | Net | Gross | Net | ||||||||||||
| Bakken/Williston Basin |
3,857 | 56.4 | 3 | 0.0 | ||||||||||||
| DJ Basin/Rockies/Niobrara |
1,160 | 15.6 | 12 | 0.0 | ||||||||||||
| Permian Basin |
682 | 1.3 | 3 | 0.0 | ||||||||||||
| Other |
700 | 2.0 | 620 | 2.5 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
6,399 | 75.3 | 638 | 2.6 | ||||||||||||
|
|
|
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|
|
|
|
|
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Acreage of Mineral and Royalty Interests
The following tables set forth information relating to the acreage underlying our mineral and working interests as of December 31, 2024:
Acreage of Mineral Interest
| Net Royalty Acres | ||||||||||||
| Basin |
Developed Acreage | Undeveloped Acreage | Total Acreage | |||||||||
| Bakken/Williston Basin |
16,187 | 64,402 | 80,589 | |||||||||
| DJ Basin/Rockies/Niobrara/PRB |
4,855 | 9,549 | 14,404 | |||||||||
| Permian Basin |
657 | 356 | 1,013 | |||||||||
| Other |
470 | 434,644 | 435,115 | |||||||||
| Total Net Royalty Acres |
22,170 | 508,950 | 531,120 | |||||||||
| Gross Royalty Acres | ||||||||||||
| Basin |
Developed Acreage | Undeveloped Acreage | Total Acreage | |||||||||
| Bakken/Williston Basin |
497,152 | 785,084 | 1,282,236 | |||||||||
| DJ Basin/Rockies/Niobrara/PRB |
83,031 | 244,236 | 327,267 | |||||||||
| Permian Basin |
94,083 | 24,603 | 118,685 | |||||||||
| Other |
17,579 | 2,216,297 | 2,233,876 | |||||||||
| Total Gross Royalty Acres |
691,844 | 3,270,220 | 3,962,065 | |||||||||
Acreage of Working Interest
| Net Mineral Acres | ||||||||||||
| Basin |
Developed Acreage | Undeveloped Acreage | Total Acreage | |||||||||
| Bakken/Williston Basin |
25,047 | 159,402 | 184,449 | |||||||||
| DJ Basin/Rockies/Niobrara/PRB |
1,630 | 31,873 | 33,503 | |||||||||
| Permian Basin |
28 | 36 | 64 | |||||||||
| Other |
349 | 258,109 | 258,458 | |||||||||
| Total Net Mineral Acres |
27,054 | 449,419 | 476,473 | |||||||||
| Gross Mineral Acres | ||||||||||||
| Basin |
Developed Acreage | Undeveloped Acreage | Total Acreage | |||||||||
| Bakken/Williston Basin |
246,979 | 633,661 | 880,640 | |||||||||
| DJ Basin/Rockies/Niobrara/PRB |
43,179 | 183,381 | 226,560 | |||||||||
| Permian Basin |
7,680 | 1,280 | 8,960 | |||||||||
| Other |
15,872 | 1,309,568 | 1,325,440 | |||||||||
| Total Gross Mineral Acres |
313,710 | 2,127,890 | 2,441,600 | |||||||||
Beginning with the period ended December 31, 2023 and for all subsequent periods, each land holding in which we have a net royalty interest is reviewed and associated with a specific drilling spacing unit. This allows for the estimation of gross royalty acres to be as accurate as possible. For the period ended December 31, 2022 and for all prior periods, the drilling spacing unit was estimated based on average development within a basin and applied to each land holding in which we had a net royalty interest.
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Acreage Expirations
As of December 31, 2024, we have 169,090 gross and 25,916 net working interest acres expiring through the end of 2027, with an additional 234,667 gross and 45,309 net working acres expiring in 2028, and 482,588 gross and 75,603 net working interest acres expiring in 2029. The remaining 243,701 gross and 39,450 net working interest acres expire in years 2030 and beyond.
Evaluation and Review of Estimated Proved and Probable Reserves
We use the term “probable reserves” herein to refer to those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. The probable reserves disclosed herein have been quantified using deterministic methods and, when combined with proved reserves, have at least a 50% probability that actual quantities recovered will equal or exceed the proved plus probable reserves estimates in accordance with Rule 4-10(a)(18) of Regulation S-X. The probable reserves are adjacent to quantifiable proved reserves but where data control is present but is less certain. Our probable reserves are assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Our probable reserves are also assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. The proved plus probable estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects. Where direct observation has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
We use the term “proved reserves” herein to refer to quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data, and reliable technology established a lower contact with reasonable certainty. Where direct observation from well penetrations has defined an HKO elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data, and reliable technology establish the higher contact with reasonable certainty. Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (a) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (b) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
In order to establish the appropriate level of reserve categories and estimates to assign to our properties, we utilize modern geologic and engineering technologies, some of which are proprietary and some of which are publicly available. These technologies include, but are not limited to, drilling and completions data, flowback data, productivity results, pressure performance, mapping of geologic characteristics taken from open hole logs, cased hole logs, gamma ray logs, measurement while drilling logs, electric logs, and seismic surveys.
The proved and probable reserves estimates reported herein are as of December 31, 2024, December 31, 2023, and December 31, 2022. The technical persons primarily responsible for preparing the estimates disclosed herein each have over 15 years of industry experience. Each meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations, as well as applying SEC and other industry reserves definitions and guidelines. Mr. Brandon Allen, who is our Chief Operating Officer and who, prior to that role, served as the President of PhoenixOp from February 2024 until December 2024 and its Vice President of Reservoir Engineering from March 2023 to February 2024, is primarily responsible for overseeing the preparation of the reserves estimation. He has approximately 19 years of oil and gas operations and reserves estimation and reporting experience. He has earned Bachelor of Science degrees in Biochemistry and Chemical Engineering from the University of Colorado, Boulder, and is an active member of the Society of Petroleum Engineers.
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Proved and probable reserve estimates are based on the unweighted arithmetic average prices on the first day of each month for the 12-month period ended December 31, 2024, December 31, 2023, or December 31, 2022, as applicable. Average prices for the 12-month periods were as follows: WTI crude oil spot price of $76.32 per Bbl as of December 31, 2024, adjusted by lease or field for quality, transportation fees, and market differentials, and a Henry Hub natural gas spot price of $2.130 per MMBtu as of December 31, 2024, adjusted by lease or field for energy content, transportation fees, and market differentials. All prices and costs associated with operating wells were held constant in accordance with SEC guidelines.
We estimate the quantity or perceived cashflow of proved and probable undeveloped reserves for financial reporting purposes in accordance with the five-year rule as set forth by the SEC. Most proved undeveloped properties are operated by our subsidiary, PhoenixOp, whereby we and PhoenixOp have the property on the most current drill schedule. Non-operated proved and probable undeveloped properties represent properties that we have high confidence will be converted to producing properties within five years based on our diligence and review of public and non-public data sources. As it relates to a majority of our mineral and non-operated interest holdings, we do not always have the ability to accurately estimate when undeveloped reserves may be extracted and instead take a conservative approach whereby we only classify such reserves as proved when such reserves are either currently producing or where we have knowledge of a close date of extraction, such as upon our receipt of a notice from the operators of such reserves providing a specific timeframe for near-term production. We classify the remaining reserves as probable reserves. For example, for probable undeveloped reserves, we have a high confidence that the properties are on a development plan and/or will be converted to producing properties within the next five years based on, among other factors, our discussions with service providers, the location of nearby drilling rigs, permits obtained by the operators that are generally valid for one to two years, and the terms of the respective leases, which typically expire within five years.
Estimates of probable reserves, and the future cash flows related to such estimates, are inherently imprecise and are more uncertain than estimates of proved reserves, and the future cash flows related to such estimates, but have not been adjusted for risk due to that uncertainty. Because of such uncertainty, estimates of probable reserves, and the future cash flows related to such estimates, may not be comparable to estimates of proved reserves, and the future cash flows related to such estimates, and should not be summed arithmetically with estimates of proved reserves, and the future cash flows related to such estimates. When producing an estimate of the amount of natural gas and oil that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes, and other factors. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
The reserves information in this disclosure represents only estimates. Reserve evaluation is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. In addition, results of drilling, testing, and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.
In addition, we anticipate that the preparation of our proved and probable reserve estimates is completed in accordance with internal control procedures, including the following:
| • | review and verification of historical production data, which data is based on actual production as reported by the operators of our properties; |
| • | preparation of reserves estimates by Mr. Brandon Allen or under his direct supervision; |
| • | review by Mr. Brandon Allen and Mr. Curtis Allen, our Chief Financial Officer, of all of our reported proved and probable reserves at the close of the calendar year, including the review of all significant reserve changes and all new proved and probable undeveloped reserves additions; |
| • | verification of property ownership by our land department; and |
| • | no employee’s compensation being tied to the amount of reserves booked. |
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Oil, Natural Gas, and NGL Reserves
The following table presents our estimated proved and probable oil, natural gas, and NGL reserves as of each of the dates indicated:
| As of December 31, | ||||||||||||
| 2024(1)(2) | 2023(2)(3) | 2022(4) | ||||||||||
| Estimated proved developed reserves |
||||||||||||
| Oil (Bbl) |
18,624,758 | 7,124,194 | 3,691,722 | |||||||||
| Natural gas (Mcf) |
20,819,874 | 12,250,285 | 7,624,212 | |||||||||
| Natural gas liquids (Bbl) |
2,848,355 | 1,514,761 | — | |||||||||
| Total (Boe)(6:1)(5) |
24,943,093 | 10,680,669 | 4,962,424 | |||||||||
| Estimated proved undeveloped reserves |
||||||||||||
| Oil (Bbl) |
31,197,795 | 24,925,841 | — | |||||||||
| Natural gas (Mcf) |
17,491,089 | 19,565,808 | — | |||||||||
| Natural gas liquids (Bbl) |
4,753,257 | 6,648,747 | — | |||||||||
| Total (Boe)(6:1)(5) |
38,866,233 | 34,835,556 | — | |||||||||
| Estimated proved reserves |
||||||||||||
| Oil (Bbl) |
49,822,554 | 32,050,035 | 3,691,722 | |||||||||
| Natural gas (Mcf) |
38,310,963 | 31,816,093 | 7,624,212 | |||||||||
| Natural gas liquids (Bbl) |
7,601,611 | 8,163,508 | — | |||||||||
| Total (Boe)(6:1)(5) |
63,809,326 | 45,516,225 | 4,962,424 | |||||||||
| Percent proved developed |
39 | % | 23 | % | 100 | % | ||||||
| Estimated probable undeveloped reserves |
||||||||||||
| Oil (Bbl) |
107,769,309 | 74,877,268 | — | |||||||||
| Natural gas (Mcf) |
134,083,603 | 88,184,111 | — | |||||||||
| Natural gas liquids (Bbl) |
— | — | — | |||||||||
| Total (Boe)(6:1)(5) |
130,116,577 | 89,574,620 | — | |||||||||
| (1) | Estimates of reserves of oil and natural gas as of December 31, 2024 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the last 12 months ended December 31, 2024, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $76.32 per Bbl for oil and $2.130 per MMBtu for natural gas at December 31, 2024. Estimates of reserves of NGL as of December 31, 2024 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2024 was $25.22 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. |
| (2) | In early 2023, PhoenixOp was established with the intention that certain leaseholds held by us would be developed by PhoenixOp. PhoenixOp executed a contract for a drilling rig with Patterson-UTI Drilling Company on June 20, 2023. This allowed for previously unbooked reserves as of December 31, 2022 to be estimated and booked as of December 31, 2023 as proved undeveloped in accordance with SEC guidelines for reserves categorization and estimation and in adherence to the five-year rule as set forth in Rule 4-10(a)(31) of Regulation S-X. |
| (3) | Estimates of reserves of oil and natural gas as of December 31, 2023 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the last 12 months ended December 31, 2023, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $78.21 per Bbl for oil and $2.637 per MMBtu for natural gas at December 31, 2023. Estimates of reserves of NGL as of December 31, 2023 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2023 was $19.21 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. |
| (4) | Estimates of reserves of oil and natural gas as of December 31, 2022 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the last 12 months ended December 31, 2022, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $94.14 per Bbl for oil and $6.357 per MMBtu for natural gas at December 31, 2022. We had no NGL reserves as December 31, 2022 and, as such, no NGL price was calculated as of December 31, 2022. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. |
| (5) | Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of “oil equivalent.” This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the 12-month average prices for the period ended December 31, 2024 was used, the conversion factor would be approximately 35.8 Mcf per Bbl of oil. |
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At December 31, 2024, total estimated proved reserves were approximately 63,809,326 Boe, a 18,293,101 Boe net increase from the previous year end’s estimate of 45,516,225 Boe. Proved developed reserves of 24,943,092 Boe increased approximately 14,262,423 Boe from December 31, 2023 as a result of proved developed reserves acquisitions of 1,047,809 Boe, extensions of 3,268,997 Boe, and total positive revisions of previous estimates of 14,759,886 Boe, offset by divestitures of 71,887 Boe and production from proved developed reserves of 4,742,381 Boe. The total positive revisions of previous estimates comprised: (i) positive price revisions of 1,263 Boe; (ii) positive transfer of 14,871,911 Boe from proved undeveloped to proved developed reserves; (iii) negative well performance revisions of (481,161) Boe; (iv) positive revisions of 715,795 Boe due to interest changes; and (v) negative revisions of (347,922) Boe due to changes in lifting cost. Proved undeveloped reserves of 38,866,233 Boe increased approximately 4,030,677 Boe from December 31, 2023 as a result of proved undeveloped reserves extensions of 21,207,289 and total negative revisions of previous estimates of 17,176,612 Boe. The total negative revisions of previous estimates comprised: (i) positive price revisions of 48,935 Boe; (ii) negative transfer of (14,871,911) Boe from proved undeveloped to proved developed reserves; and (iii) negative well performance revisions of (2,353,636) Boe due to asset development reconfiguration and type curve adjustments. During the year ended December 31, 2024, approximately $87.4 million in capital expenditures were related to the conversion of proved undeveloped reserves to proved developed reserves. During the year ended December 31, 2024, approximately $450.0 million in capital expenditures went toward the acquisition and development of proved developed reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. All proved undeveloped reserves disclosed as of December 31, 2024 are scheduled to be converted to proved developed status within five years of initial disclosure.
At December 31, 2023, total estimated proved reserves were approximately 45,516,225 Boe, a 40,553,802 Boe net increase from the previous year end’s estimate of 4,962,424 Boe. Proved developed reserves of 10,680,669 Boe increased approximately 5,718,245 Boe from December 31, 2022 as a result of proved developed reserves acquisitions of 1,426,545 Boe, extensions of 5,682,894 Boe, and total positive revisions of previous estimates of 616,010 Boe, offset by production from proved developed reserves of 2,007,205 Boe. The total positive revisions of previous estimates comprised: (i) negative price revisions of (13,622) Boe; (ii) transfer of (89,378) Boe from proved developed to proved undeveloped due to previous misclassifications of reserve; (iii) positive well performance revisions of 515,938 Boe; and (iv) positive revisions of 203,072 Boe due to changes in lifting cost. Proved undeveloped reserves of 34,835,556 Boe increased approximately 34,835,556 Boe from December 31, 2022 as a result of revisions due to previous misclassification of 89,378 Boe of reserves as proved developed reserves and due to the addition of 34,746,179 Boe of operated proved undeveloped reserves stemming from the signing of a drilling rig contract in June 2023. During the year ended December 31, 2023, approximately $171.2 million in capital expenditures went toward the acquisition and development of proved developed reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. At December 31, 2022, there were no proved undeveloped reserves, Therefore, no capital expenditures for the year ended December 31, 2023 were related to the conversion of proved undeveloped reserves to proved developed reserves. All proved undeveloped reserves disclosed as of December 31, 2023 are scheduled to be converted to proved developed status within five years of initial disclosure.
At December 31, 2022, total estimated proved reserves were approximately 4,962,424 Boe, a 2,195,112 Boe net increase from the previous year end’s estimate of 2,767,312 Boe. Proved developed reserves of 4,962,424 Boe increased approximately 2,195,112 Boe from December 31, 2021 as a result of proved developed reserves acquisitions of 1,554,122 Boe, extensions of 75,272 Boe, and total positive revisions of previous estimates of 1,265,552 Boe, offset by production from proved developed reserves of 699,834 Boe. The total positive revisions of previous estimates comprised (i) positive price revisions of 524,667 Boe and (ii) positive well performance revisions of 740,885 Boe. During the year ended December 31, 2022, approximately $117.1 million in capital expenditures went toward the acquisition and development of proved reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. At December 31, 2021, there were no proved undeveloped reserves. Therefore, no capital expenditures for the year ended December 31, 2022 were related to the conversion of proved undeveloped reserves to proved developed reserves.
Delivery Commitments
As of March 31, 2025, PhoenixOp is subject to arrangements pursuant to which it has committed to provide a total of 2.2 million barrels of crude oil, with the highest yearly minimum of 958,000 barrels of crude oil, from June 1, 2025 to December 31, 2030. PhoenixOp will be subject to a shortfall fee for failure to meet this commitment. As a part of these arrangements, PhoenixOp has dedicated to the counterparties certain rights to all oil extracted from our wells in certain properties in Dunn County, Williams County, and Divide County, North Dakota. PhoenixOp has assessed the productivity potential of its leasehold in the area, as well as the feasibility of executing an operational plan to extract oil on its leasehold within the commitment period and dedication area, and deemed it to be reasonable to enter into such an agreement.
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Select Production and Operating Statistics
The following table presents information regarding our production of oil, natural gas, and NGL and certain price and cost information for each of the periods indicated:
| For the Years Ended December 31, | ||||||||||||
| 2024 | 2023 | 2022 | ||||||||||
| Production Data: |
||||||||||||
| Bakken |
||||||||||||
| Oil (Bbl) |
3,022,810 | 943,930 | 360,604 | |||||||||
| Natural gas (Mcf) |
1,301,782 | 1,123,859 | 522,523 | |||||||||
| Natural gas liquids (Bbl) |
270,219 | 88,762 | — | |||||||||
| Total (Boe)(6:1)(1) |
3,509,992 | 1,220,003 | 447,691 | |||||||||
| Average daily production (Boe/d)(6:1) |
9,590 | 3,342 | 1,227 | |||||||||
| All Properties |
||||||||||||
| Oil (Bbl) |
3,830,461 | 1,446,928 | 523,416 | |||||||||
| Natural gas (Mcf) |
2,979,341 | 2,152,939 | 1,058,506 | |||||||||
| Natural gas liquids (Bbl) |
415,363 | 201,454 | — | |||||||||
| Total (Boe)(6:1)(1) |
4,742,381 | 2,007,205 | 699,834 | |||||||||
| Average daily production (Boe/d)(6:1) |
12,993 | 5,499 | 1,917 | |||||||||
| Average Realized Prices: |
||||||||||||
| Bakken |
||||||||||||
| Oil (Bbl) |
$ | 71.77 | $ | 71.43 | $ | 80.67 | ||||||
| Natural gas (Mcf) |
$ | 2.12 | $ | 3.47 | $ | 3.77 | ||||||
| Natural gas liquids (Bbl) |
$ | 23.53 | $ | 26.70 | $ | — | ||||||
| All Properties |
||||||||||||
| Oil (Bbl) |
$ | 68.49 | $ | 73.10 | $ | 91.01 | ||||||
| Natural gas (Mcf) |
$ | 1.86 | $ | 3.15 | $ | 6.66 | ||||||
| Natural gas liquids (Bbl) |
$ | 25.22 | $ | 27.50 | $ | — | ||||||
| Average Unit Cost per Boe (6:1): |
||||||||||||
| All Properties |
||||||||||||
| Operating costs, production and ad valorem taxes |
$ | 16.11 | $ | 16.18 | $ | 19.89 | ||||||
| Operating costs excluding taxes |
$ | 10.75 | $ | 10.86 | $ | 12.58 | ||||||
| Percentage of revenue |
26.4 | % | 16.7 | % | 21.9 | % | ||||||
| (1) | “Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. |
Depletion of Oil and Natural Gas Properties
We account for our oil and gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities, are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves. The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs, as well as the anticipated proceeds from salvaging equipment.
Depletion expense was $86.0 million, $34.2 million, and $12.1 million for the years ended December 31, 2024, 2023, and 2022, respectively. On a per unit basis, depletion expense was $18.13 per Boe, $17.06 per Boe, and $17.34 per Boe for the years ended December 31, 2024, 2023, and 2022, respectively. The decrease in our depletion rate for the year ended December 31, 2023 compared to 2022 was primarily due to increased proved reserves relative to the change in aggregated proved leasehold and development costs associated with those proved reserves, whereas the increase in our depletion rate for the year ended December 31, 2024 compared to 2023 was primarily due to the incurrence of significant capital expenditures related to developing operated wells under our operating entity, PhoenixOp. The depletion rate for the development capital is depleted at a higher rate as compared to leasehold due to the use of proved developed reserves versus total proved reserves under the successful efforts accounting method. We expect depletion to continue to increase in subsequent periods as our gross production of oil, gas, and other products increase.
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Our E&P Operators
Our management team strives to acquire mineral and royalty interests in properties with top-tier third-party E&P operators. We seek third-party E&P operators that are well-capitalized, have a strong operational track record, and we believe will continue to produce through the application of the latest drilling and completion techniques across our mineral and royalty interests. Over 100 third-party E&P operators are currently producing oil and gas at our assets. As of December 31, 2024, our top ten third-party E&P operators operate on 7.1% of our NRAs.
Industry Operating Environment
The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of taxation, energy, climate change, and the environment, political and social developments in the Middle East and Russia, demand in Asian and European markets, and the extent to which members of OPEC and other oil exporting nations manage oil supply through export quotas. Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas because it is a primary heating source.
Oil and natural gas prices have been, and we expect may continue to be, volatile. Lower oil and gas prices not only decrease our revenues, but an extended decline in oil or gas prices may affect planned capital expenditures and the oil and natural gas reserves that our assets can economically produce. Among other things, drilling operations and related activities can be significantly impacted by the accuracy of the estimation of reserves and the effect on those reserves of fluctuating market prices. If commodity prices decline, the cost of developing, completing, and operating a well may not decline in proportion to the prices that are received for the production, resulting in higher operating and capital costs as a percentage of revenues. While lower commodity prices may reduce the future net cash flow from operations of the assets in which we invest, we expect to have sufficient liquidity to continue participation in development of our oil and gas properties.
Competition
The oil and gas industry is intensely competitive, and we compete with other oil and natural gas E&P companies, some of which have substantially greater resources than we have and may be able to pay more for exploratory prospects and productive oil and natural gas properties, and competition for our target asset classes is subject to increase in the future. Our larger or more integrated competitors may be better able to absorb the burden of existing, as well as any changes to, federal, state, and local laws and regulations than we can, which would adversely affect our competitive position. Our ability to acquire additional assets in the future is dependent on the success of our software platform, our ability and resources to evaluate and select suitable properties, and our ability to consummate transactions in this highly competitive environment.
Marketing and Customers
The market for oil and natural gas that will be produced from our assets depends on many factors, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of pipelines and other transportation and storage facilities, demand for oil and natural gas, the marketing of competitive fuels, and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial, and individual consumers.
Our oil and natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We rely on our third-party operating and service partners to market and sell our production. Our operating partners include a variety of E&P companies, from large, publicly traded companies to small, privately owned companies. Our service partners include a variety of oil and natural gas gathering, transportation, processing, and marketing companies. We do not believe the loss of any single operator or service partner would have a material adverse effect on our company as a whole.
Seasonality
Winter weather events and conditions, such as ice storms, freezing conditions, droughts, floods, and tornados, breeding and nesting seasons, and lease stipulations can limit or temporarily halt our and our operating partners’ drilling and producing activities and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our and our operating partners’ operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting well drilling objectives and may increase competition for equipment, supplies, and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our and our operating partners’ operations.
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Title to Properties
Prior to completing an acquisition of mineral and royalty interests, we perform due diligence title reviews on a majority of tracts to be acquired. Our title review is meant to confirm the quantum of mineral and royalty interest owned by a prospective seller, the property’s lease status and royalty amount, and encumbrances or other related burdens. Said title review consists of a patent to present title search on the prospective tract and a “grantor/grantee” search of the prospective seller in county records, in addition to a lien/judgement search related to the seller’s ownership.
In addition to our initial title work and due diligence title review, E&P operators will conduct a thorough title examination prior to leasing and/or drilling a well and paying out the royalty owner. Should an E&P operator’s title work uncover any further title defects, either we or the E&P operator will perform curative work with respect to such defects. An E&P operator generally will not pay out royalty payments on the property until any material title defects on such property have been cured.
We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is in some cases subject to encumbrances, such as customary interests generally retained in connection with the acquisition of crude oil and gas interests, non-participating royalty interests, and other burdens, easements, restrictions, or minor encumbrances customary in the crude oil and natural gas industry, we believe that none of these encumbrances will materially detract from the value of these properties or from our interest in these properties.
Governmental Regulation and Environmental Matters
Our operations are subject to various rules, regulations, and limitations impacting the oil and natural gas E&P industry as a whole, including those associated with E&P operators and other owners of working interests in crude oil and natural gas properties. The legislation and regulation affecting the crude oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the crude oil and natural gas industry increases the cost of doing business.
Environmental Matters
Crude oil and natural gas exploration, development, and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on the properties in which we own mineral interests, which could materially adversely affect our business and prospects. Numerous federal, state, and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil, and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities, and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses, and authorizations, require that additional pollution controls be installed, and impose substantial liabilities for pollution resulting from operations. The strict, joint, and several liability nature of such laws and regulations could impose liability upon the E&P operators of our properties, including PhoenixOp regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, or other waste products into the environment. In the opinion of our management, we are in substantial compliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. However, changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our business and prospects.
Non-Hazardous and Hazardous Waste
The RCRA and comparable state statutes and regulations promulgated thereunder affect crude oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of the RCRA, sometimes in conjunction with their own, more stringent requirements. Administrative, civil, and criminal penalties can be imposed for failure to comply with waste handling requirements. Although most wastes associated with the
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exploration, development, and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject to less stringent requirements. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated in connection with E&P of oil and gas that are currently classified as nonhazardous may, in the future, be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements. Any changes in the laws and regulations could have a material adverse effect on the E&P operators of our properties’ capital expenditures and operating expenses, including those of PhoenixOp, which in turn could affect production from the acreage underlying our mineral and royalty interests and adversely affect our business and prospects.
Remediation
CERCLA and analogous state laws generally impose strict, joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict, joint, and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources, and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, the risk of accidental spills or releases could expose the operators of the acreage underlying our mineral interests to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition, and results of operations. Liability for any contamination under these laws could require the operators of the acreage underlying our mineral interests to make significant expenditures to investigate and remediate such contamination or attain and maintain compliance with such laws and may otherwise have a material adverse effect on their results of operations, competitive position, or financial condition.
Water Discharges
The CWA, SDWA, the Oil Pollution Act of 1990 (the “OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other crude oil and natural gas wastes, into regulated waters. The definition of regulated waters has been the subject of significant controversy in recent years, with different definitions proposed under the Obama and Trump Administrations. Both of these definitions have been subject to litigation. In January 2023, the EPA and the U.S. Army Corps of Engineers (the “Corps”) released a final revised definition of “waters of the United States” founded upon a pre-2015 definition and included updates to incorporate existing Supreme Court decisions and regulatory guidance. However, the January 2023 rule was challenged and is currently enjoined in 27 states. In May 2023, the U.S. Supreme Court released its opinion in Sackett v. EPA, which involved issues relating to the legal tests used to determine whether wetlands qualify as waters of the United States. The Sackett decision invalidated certain parts of the January 2023 rule and significantly narrowed its scope, resulting in a revised rule being issued in September 2023. However, due to the injunction of the January 2023 rule, the implementation of the September 2023 rule currently varies by state. In March 2025, the EPA announced that it will work with the U.S. Army Corps of Engineers to deliver on President’s Trump’s promise to review and revise the definition of “waters of the United States,” guided by the Sackett decision. To the extent the implementation of the final rule, results of the litigation, or any further action expands the scope of jurisdiction, it may impose greater compliance costs or operational requirements on our operators, including PhoenixOp. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In addition, spill prevention, control, and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. The EPA has also adopted regulations requiring certain crude oil and natural gas E&P facilities to obtain individual permits or coverage under general permits for storm water discharges, and, in June 2016, the EPA finalized effluent limitation guidelines for the discharge of wastewater from hydraulic fracturing.
The OPA is the primary federal law for crude oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of crude oil into surface waters.
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Noncompliance with the CWA, the SDWA, or the OPA may result in substantial administrative, civil, and criminal penalties, as well as injunctive obligations, for the E&P operators of the acreage underlying our mineral interests, including PhoenixOp.
Air Emissions
The CAA and comparable state laws and regulations regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in June 2016, the EPA established criteria for aggregating multiple small surface sites into a single source for air quality permitting purposes, which could cause small facilities, on an aggregate basis, to be deemed a major source subject to more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for crude oil and natural gas producers and impact production of the acreage underlying our mineral and royalty interests. In addition, federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of crude oil and natural gas projects.
Climate Change
Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of carbon dioxide, methane, and other GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.
In the United States, besides the IRA 2022, no comprehensive climate change legislation has been implemented at the federal level. Although former President Biden’s administration highlighted addressing climate change as a priority and issued several executive orders to that effect, President Trump’s administration has taken a different stance, and has revoked many of President Biden’s executive orders and imposed a regulatory freeze. Additionally, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under 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 U.S. Department of Transportation, 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. However, in response to former President Biden’s executive order calling on the EPA to revisit federal regulations regarding methane, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources, known as OOOOc, in December 2023. Under those rules, states would have two years to prepare and submit their plans to impose methane emissions controls on existing sources. On November 12, 2024, the EPA finalized the methane emissions charge rule, implementing the IRA 2022. The Trump Administration may challenge, repeal, or revise the EPA rule. Additionally, the U.S. Congress may take action to repeal or revise the IRA 2022, including with respect to the methane charge rule, which timing or outcome similarly cannot be predicted. The final methane charge rule is currently being challenged by 23 U.S. states and a coalition of industry groups in the U.S. Circuit Court of Appeals for the D.C. Circuit.
As of March 2025, President Trump has not rolled back any methane regulations, but the future of such regulations and any enforcement of those regulations at the federal level is murky given the Trump Administration’s skeptical approach to climate change-related regulations. The presumptive standards established under the final rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of a “super emitter” response program that would allow third parties to make reports to the EPA of large methane emissions events, triggering certain investigation and repair requirements. It is likely, however, that the final rule and its requirements will be subject to legal challenges, if ever implemented. Moreover, compliance with these rules may affect the amount oil and gas companies owe under the IRA 2022, which amended the CAA to impose a first-time fee on the emission of methane from sources required to report their GHG emissions to the EPA. The methane emissions fee applies to excess methane emissions from certain facilities and starts at $900 per metric ton of leaked methane in 2024 and increases to $1,200 in 2025 and $1,500 in 2026 and thereafter. Compliance with the EPA’s new final rules would exempt an otherwise covered facility from the requirement to pay the methane fee. Failure to comply with the requirements of the EPA’s new rules and the methane fee could adversely affect costs of compliance and operations and result in the imposition of substantial fines and penalties, as well as costly injunctive relief.
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Separately, various states and groups of states have adopted or are considering adopting legislation, regulation, or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, New Mexico has adopted regulations to restrict the venting or flaring of methane from both upstream and midstream operations. At the international level, the Paris Agreement requires member states to submit non-binding, individually determined reduction goals known as Nationally Determined Contributions every five years after 2020. Although former President Biden recommitted the United States to the Paris Agreement during his presidency and, in April 2021, announced a goal of reducing the United States’ emissions by 50 to 52% below 2005 levels by 2030, President Trump has signed an executive order directing the United States’ withdrawal from the Paris Agreement. The Trump Administration’s stance makes it unclear whether the Global Methane Pledge announced by the United States and the European Union at the 26th Conference of the Parties to the United Nations Framework Convention on Climate Change in Glasgow in November 2021—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—will move forward. In December 2023, the United Arab Emirates hosted the 28th Conference of the Parties where parties signed onto an agreement to transition “away from fossil fuels in energy systems in a just, orderly, and equitable manner” and increase renewable energy capacity so as to achieve net zero by 2050, although no timeline for doing so was set. In November 2024, Azerbaijan hosted the 29th Conference of the Parties, which concluded with an agreement calling on developed countries to deliver at least $300 billion per year to developing countries by 2035 to drastically reduce greenhouse gas emissions and protect lives and livelihoods from the impacts of climate change. The full impact of these various orders, pledges, agreements, and actions cannot be predicted at this time.
Whereas on January 27, 2021, former President Biden’s administration had called for restrictions on leasing on federal land, and had issued an executive order that called 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 new Trump administration has revoked many such related rules and executive orders focusing on greenhouse emissions and fossil fuel energy regulations. For example, on January 21, 2025, the Trump Administration lifted the former administration’s pause on liquefied natural gas exports. However, we cannot predict whether and to what extent the Trump Administration will continue to act favorably to the energy sector.
Litigation risks are also increasing as a number of entities 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 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.
Historically there have also been increasing financial risks for fossil fuel producers as shareholders 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. 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. For example, in October 2023, the Federal Reserve, Office of the Comptroller of the Currency, and the Federal Deposit Insurance Corp. released a finalized set of principles guiding financial institutions with $100 billion or more in assets on the management of physical and transition risks associated with climate change. The 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 6, 2024, the SEC adopted rules to enhance and standardize climate-related disclosures by public companies and in public offerings. However, on April 4, 2024, the SEC voluntarily stayed implementation of these rules pending completion of judicial review of consolidated challenges to the rules by the U.S. Court of Appeals for the Eighth Circuit and is expected to withdraw these rules in the near future. Although the application and viability of the proposed rules are not yet known, any adoption of such rules either by the Trump Administration or a future administration may result in additional costs to comply with any such disclosure requirements, alongside increased costs of and restrictions on access to capital.
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 canceling 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. One or more of these developments could have a material adverse effect on our business, financial condition, and results of operation.
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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, including PhoenixOp, 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. Extreme weather conditions can interfere with production and increase costs, and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our business.
Regulation of Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their crude oil and natural gas regulatory programs. However, several agencies have asserted regulatory authority over certain aspects of the process. For example, in August 2012, the EPA finalized regulations under the federal CAA that establish new air emission controls for crude oil and natural gas production and natural gas processing operations. Federal regulation of methane emissions from the oil and gas sector has been subject to substantial controversy in recent years.
In addition, governments have studied the environmental aspects of hydraulic fracturing practices. These studies, depending on their degree of pursuit and whether any meaningful results are obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water under certain limited circumstances.
Several states where we operate, including North Dakota, Montana, Utah, Texas, Colorado, and Wyoming, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, the Texas RRC has previously issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place, and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular.
In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. For example, in November 2020, the Colorado Oil and Gas Conservation Committee (the “COGCC”), as part of Senate Bill 181’s mandate for the COGCC to prioritize public health and environmental concerns in its decisions, adopted revisions to several regulations to increase protections for public health, safety, welfare, wildlife, and environmental resources. Most significantly, these revisions establish more stringent setbacks (2,000 feet, instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. Some local communities have adopted, or are considering adopting, further restrictions for oil and gas activities, such as requiring greater setbacks. The Colorado Department of Public Health and the Environment also finalized rules related to the control of emissions from certain pre-production activities; namely, curbing methane emissions by setting limits of per 1,000 barrels of oil equivalent produced, more frequent inspections, and limits on emissions during maintenance. These and other developments related to the implementation of Senate Bill 181 could adversely impact our revenues and future production from our properties.
State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing-related activities, particularly the disposal of produced water in underground injection wells, and the increased occurrence of seismic activity. When caused by human activity, such events are called “induced seismicity.” In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado and Texas, have modified their regulations to account for induced seismicity. For example, in October 2014, the Texas RRC published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections, and structure maps relating to the disposal area in question. The Texas RRC has used this authority to deny permits for waste disposal wells. In some instances, regulators may also order that disposal wells be shut in. In late 2021, the Texas RRC issued a notice to operators of disposal wells in the Midland area to reduce saltwater disposal well actions and provide certain data to the Texas RRC. In December 2021, the Texas RRC suspended all disposal well permits to inject oil and gas waste within the boundaries of the Gardendale Seismic Response Area. Relatedly, in March 2022, the Texas RRC began implementation of
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its Northern Culberson-Reeves Seismic Response Area Plan to address injection-induced seismicity with the goal to eliminate 3.5 magnitude or greater earthquakes no later than December 31, 2023. From November 8 through December 17, 2023, the TexNet Seismic Monitoring Program reported seven earthquakes with magnitudes greater than 3.5 and, in April 2024, a 4.4 magnitude earthquake was recorded in the Stanton Seismic Response Area, an area where the Texas RRC is also monitoring seismic activity linked to disposal of saltwater. In January 2024, the RRC banned saltwater disposal injection in the Northern Culberson-Reeves Seismic Area, which applied to 23 disposal wells in the area. As a result of these developments, our operators may be required to curtail operations or adjust development plans, which may adversely impact our business. In May 2024, the EPA announced it would review the Texas RRC’s oversight of disposal wells used for injecting oil drilling wastewater and carbon dioxide into the ground.
The USGS has identified six states with the most significant hazards from induced seismicity, including Texas and Colorado. 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. These developments could result in additional regulation and restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on the E&P operators of our properties, including PhoenixOp, and on their waste disposal activities.
If new laws or regulations that significantly restrict hydraulic fracturing and related activities are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting, and recordkeeping obligations, plugging and abandonment requirements, and to attendant permitting delays and potential increases in costs. Such legislative changes could cause E&P operators to incur substantial compliance costs, and compliance or the consequences of any failure to comply by E&P operators could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.
Endangered Species Act
The Endangered Species Act (the “ESA”) restricts activities that may affect endangered and threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause E&P operators to incur additional costs or become subject to operating delays, restrictions, or bans in the affected areas. As part of a stipulated settlement agreement in a case challenging its failure to timely make a 12-month finding on a petition to list the dunes sagebrush lizard, whose habitat includes parts of the Permian Basin, the United States Fish and Wildlife Service (the “FWS”). In June 2024, the FWS issued a final rule listing the dunes sagebrush lizard as endangered under the ESA. Additionally, in June 2021, the FWS proposed to list two distinct population sections of the Lesser Prairie Chicken, including one in portions of the Permian Basin, under the ESA. In November 2022, following an extensive review, the FWS listed the northern distinct population segment of the Lesser Prairie Chicken, encompassing southeastern Colorado, southcentral to western Kansas, western Oklahoma, and the northeast Texas Panhandle, as threatened, and the southern district population segment, covering eastern New Mexico and the southwest Texas Panhandle, as endangered. The FWS listing decisions for both the lesser prairie chicken and the dunes sagebrush lizard are subject to ongoing litigation in the U.S. District Court for the Western District of Texas. To the extent species are listed under the ESA or similar state laws, or previously unprotected species are designated as threatened or endangered in areas where our properties are located, operations on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to production activities thereon.
Employee Health and Safety
Operations on our properties are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (the “OSHA”) and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and citizens.
Other Regulation of the Crude Oil and Natural Gas Industry
The crude oil and natural gas industry is extensively regulated by numerous federal, state, and local authorities. Legislation affecting the crude oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the crude oil and natural gas industry and its individual members, some of which carry substantial
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penalties for failure to comply. Although the regulatory burden on the crude oil and natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities, and locations of production.
The availability, terms and conditions, and cost of transportation significantly affect sales of crude oil and natural gas. The interstate transportation of crude oil and natural gas and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions, and rates for interstate transportation, storage, and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to crude oil and natural gas pipeline transportation. FERC’s regulations for interstate crude oil and natural gas transmission in some circumstances may also affect the intrastate transportation of crude oil and natural gas.
We cannot predict whether new legislation to regulate crude oil and natural gas might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of crude oil, condensate, and NGL are not currently regulated and are made at market prices.
Drilling and Production
The operations of the E&P operators of our properties, including PhoenixOp, are subject to various types of regulation at the federal, state, and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds, and reports concerning operations. The states and some counties and municipalities in which we operate also regulate one or more of the following:
| • | the location of wells; |
| • | the method of drilling and casing wells; |
| • | the timing of construction or drilling activities, including seasonal wildlife closures; |
| • | the rates of production or “allowables”; |
| • | the surface use and restoration of properties upon which wells are drilled; |
| • | the plugging and abandoning of wells; and |
| • | notice to, and consultation with, surface owners and other third parties. |
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of crude oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of crude oil and natural gas that the E&P operators of our properties can produce from our wells or limit the number of wells or the locations at which E&P operators can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of crude oil, natural gas, and NGL within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of crude oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells, or limit the number of locations E&P operators can drill.
Federal, state, and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines, and site restoration in areas where the E&P operators of our properties operate. The Corps and many other state and local authorities also have regulations for plugging and abandonment, decommissioning, and site restoration. Although the Corps does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.
Natural Gas Sales and Transportation
FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (the “NGA”) and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.”
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Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which the E&P operators of our properties may use interstate natural gas pipeline capacity, as well as the revenues such E&P operators receive for release of natural gas pipeline capacity. Interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers, and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open-access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines.
Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase the E&P operators’ costs of transporting gas to point-of-sale locations. This may, in turn, affect the costs of marketing natural gas that the E&P operators of our properties produce.
Historically, the natural gas industry was more heavily regulated; therefore, we cannot guarantee that the regulatory approach currently pursued by FERC and the U.S. Congress will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
Crude Oil Sales and Transportation
Crude oil sales are affected by the availability, terms, and cost of transportation. The transportation of crude oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act, and intrastate crude oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate crude oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of crude oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.
Further, interstate and intrastate common carrier crude oil pipelines must provide service on a non-discriminatory basis. Under this open-access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When crude oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to crude oil pipeline transportation services by E&P operators of our properties will not materially differ from our competitors’ access to crude oil pipeline transportation services.
Certain State Regulations and Developments
North Dakota
On July 6, 2020, the U.S. District Court for the District of Columbia ordered vacatur of Dakota Access Pipeline’s (“DAPL”) easement from the Corps and further ordered the shutdown of the pipeline by August 5, 2020 while the Corps completes a full environmental impact statement for the project. On January 26, 2021, the Court of Appeals for the District of Columbia affirmed the vacatur of the easement, but declined to require the pipeline to shut down while an Environmental Impact Statement is prepared. On May 21, 2021, the District Court denied the Plaintiff’s request for an injunction and, on June 22, 2021, terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. Following the denial of a rehearing en banc by the Court of Appeals for the District of Columbia, on September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General and Plaintiffs and Dakota Access filed its reply, although in February 2022, the U.S. Supreme Court denied certiorari, declining to hear the appeal. The pipeline continues to operate pending completion of the Environmental Impact Statement, which the Corps released in September 2023. The Draft Environmental Impact Statement was subject to public comment until December 2023, and the final Environmental Impact Statement is expected to be released in 2025. Additional lawsuits challenging the legality of the DAPL have been filed by various stakeholders. We cannot determine when or how these or future lawsuits will be resolved or the impact they may have on the DAPL. If future legal challenges to DAPL are successful, we may be adversely affected by increased transportation costs, well shut ins, and future productive, negatively impacting our revenue costs.
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Montana
In April 2020, a Montana federal judge vacated the Corps’ Nationwide Permit (“NWP”) 12 and enjoined the Corps from authorizing any dredge or fill activities under NWP 12 until the agency completed formal consultation with the FWS under the ESA regarding NWP 12 generally. The court later revised its order to vacate NWP 12 only as it relates to the construction of new oil and natural gas pipelines, and that order went on appeal in the Ninth Circuit Court of Appeals. The United States Supreme Court narrowed the applicability of the order to the Keystone XL pipeline pending the outcome of the Ninth Circuit’s decision, and in May 2021, the Biden Administration argued that the suit was moot given the discontinuation of the Keystone XL pipeline. In March 2022, the Corps announced its formal review of NWP 12. The Corps’ review of NWP 12 may adversely affect our business, preventing the advancement of our oil and gas infrastructure projects due to public interest review and studies of the impacts of our projects on the climate. There have been no recent updates of the Corps’ review.
In December 2024, the Montana Supreme Court affirmed a lower court decision in Held v. State of Montana, holding that the right to a clean and healthful environment under the Montana Constitution includes a stable climate system, and that the law at question banning state agencies from weighing the impact of climate change and GHG emissions in environmental reviews was unconstitutional under state law. The policy impacts of the ruling remain unclear; however, it may lead to adverse changes in the permitting process for oil and gas development in Montana, and may lead to further lawsuits, which may negatively impact our operations in the state.
Utah
In recent years, Utah has experienced persistent and severe drought conditions. Various local governments in Utah have implemented water restrictions. Water management and our access to water, in each case at a reasonable cost, in a timely manner and in compliance with applicable laws, regulations and permits, is an essential component of our operations due to water’s significance in shale oil and natural gas development. As such, any limitations or restrictions on wastewater disposal or water availability could have an adverse impact on our operations. Our third party E&P operators may use water supplied from various local and regional sources to support operations like steam injection in certain fields. While our third party E&P operators’ production to date has not been materially impacted by restrictions on wastewater disposals or access to third-party water sources, we cannot guarantee that there may not be restrictions in the future.
Texas
Texas regulates the drilling for, and the production, gathering, and sale of, crude oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on the market value of crude oil production and a 7.5% severance tax on the market value of natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells, and the prevention of waste of crude oil and natural gas resources.
States may regulate rates of production and may establish maximum daily production allowables from crude oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. Should direct economic regulation or regulation of wellhead prices by the states increase, this could limit the amount of crude oil and natural gas that may be produced from wells on our properties and the number of wells or locations the E&P operators of our properties can drill.
The petroleum industry is also subject to compliance with various other federal, state, and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not currently believe that compliance with these laws will have a material adverse effect on our business.
Colorado
A number of municipalities in other states, including Colorado and Texas, have enacted bans on hydraulic fracturing. In Colorado, the Colorado Supreme Court has ruled the municipal bans were preempted by state law. However, in April 2019 the Colorado legislature subsequently enacted “SB 181” that gave significant local control over oil and gas well head operations. Municipalities in Colorado have enacted local rules restricting oil and gas operations based on SB 181; nevertheless, in November 2020, a Colorado district court upheld the prior Colorado Supreme Court ruling in finding that a hydraulic fracking ban in the City of Longmont was preempted by state law. Additionally, in May 2024, the Colorado legislature enacted a bill that mandates a 50%
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reduction in nitrogen oxide emissions from upstream oil and gas operations by 2030, relative to 2017 levels. Oil and gas operators are required to obtain and maintain a license to conduct operations, in addition to necessary permits. The Colorado Energy and Carbon Management Commission (the “ECMC”) will enforce these requirements. The bill authorizes the ECMC to adopt rules requiring enhanced systems and practices to minimize emissions of ozone precursors at new oil and gas locations, particularly in areas designated as ozone nonattainment zones. The bill increases civil penalties for violations. It also allows for more stringent enforcement actions, including license suspension or revocation for severe violations. The bill also expands efforts to plug, reclaim, and remediate orphaned and marginal wells, with a focus on those at high risk of becoming orphaned, to mitigate environmental and public health risks. During the same legislative session, Colorado enacted a bill that imposes a “Production Fee for Clean Transit” and a “Production Fee for Wildlife and Land Remediation” on oil and gas produced in the state. Oil and gas producers are required to register and file returns detailing their production volumes and corresponding fees. Failure to comply with these requirements can result in penalties. In October 2024, the ECMC introduced rules to scrutinize the cumulative impacts of GHG emissions and set emissions intensity targets for operators. Local communities are considering additional restrictions, such as greater setbacks. The Colorado Department of Public Health and the Environment also set rules to curb methane emissions from pre-production activities. We cannot predict whether other similar legislation in other states will ever be enacted and if so, what the provisions of such legislation would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, it could lead to delays, increased operating costs and process prohibitions that would materially adversely affect our operating partners and our revenue and results of operations.
Wyoming
On May 7, 2024, the Wyoming Department of Environmental Quality (“DEQ”) – Air Quality Division issued an emergency rule in response to EPA new air regulation 40 CFR Part 60 subpart OOOOb – “Standards of Performance for Crude Oil and Natural Gas Facilities for Which Construction, Modification, or Reconstruction Commenced After December 6, 2022” (the “Methane Rule”). The Methane Rule establishes emission standards and compliance schedules for the control of GHGs. Subpart OOOOb requirements became federally effective on May 7, 2024, and as a result, oil and gas operators across the nation, including in Wyoming, must implement them. To assist Wyoming’s regulated community with implementing EPA’s new requirements, DEQ issued an Oil and Gas Emergency Rulemaking. Given EPA’s shortened timeframes and deadlines, the division initiated the emergency rulemaking process before initiating the regular rulemaking process. The regular rulemaking process will provide the public and stakeholders the opportunity to comment and participate in the rulemaking process.
Human Capital Resources
As of December 31, 2024, we had 135 total employees, all of whom were full-time employees and all of whom were located in the United States. From time to time, we utilize the services of independent contractors to perform various field and other services. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. In general, we believe that employee relations are satisfactory.
We are focused on attracting, engaging, developing, retaining, and rewarding top talent. We strive to enhance the economic and social well-being of our employees and the communities in which we operate. We are committed to providing a welcoming, inclusive environment for our workforce, with training and career development opportunities to enable employees to thrive and achieve their career goals. The health, safety, and well-being of our employees is of the utmost importance.
As part of our efforts to hire and retain highly qualified employees, we have structured compensation and benefits programs that, we believe, are extremely competitive and reward outstanding performance. In addition to the incentive programs in place for our named executive officers, which are described in detail under “Compensation Discussion and Analysis—Details of Our Compensation Program,” we have structured an incentive bonus program for non-officer employees that is dependent on an employee’s individual performance and our performance as a company. We also provide a robust suite of benefits to our employees covering all aspects of life, including 401(k) contributions, medical-insurance options, and programs to encourage and support the employees’ development.
Our Offices
Our principal executive office is located in Irvine, California, and we have additional offices located in Denver, Colorado, Dallas, Texas, Fort Lauderdale, Florida, and Casper, Wyoming. We currently lease this office space and believe that the condition and size of our offices are adequate for our current needs, and that additional or alternative space will be available on commercially reasonable terms for future use and expansion.
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Legal Proceedings
On June 15, 2022, we filed a civil lawsuit against William Francis and Incline Energy Partners, L.P. (“Incline Energy”) in the 116th District Court of Dallas County, Texas, asserting claims of (i) defamation, (ii) business disparagement, (iii) tortious interference with contract, (iv) tortious interference with prospective contract/relations, (v) unfair competition, and (vi) civil conspiracy, and seeking damages of $50 million. Francis and Incline Energy moved to dismiss all claims under the Texas Citizen Participation Act. On October 9, 2022, the District Court dismissed the tortious interference with contract claim, and the defamation and business disparagement claims to the extent they were based on a specific document. Francis and Incline Energy appealed the portions of the Court’s decision that denied their motion to dismiss. On August 30, 2023, the Court of Appeals for the Fifth District of Texas reversed the District Court’s decision in part, dismissing all claims other than defamation per se. On December 28, 2023, we filed a petition for review by the Texas Supreme Court. On June 21, 2024, the Supreme Court of Texas denied the petition for review. On remand, the trial court dismissed our remaining claims with prejudice. We are evaluating an appeal of this ruling.
On October 20, 2023, we filed a civil lawsuit against Incline Energy in the United States District Court for the District of North Dakota, asserting (i) tortious interference with contract, (ii) tortious interference with business expectancy, (iii) unfair competition, and (iv) unjust enrichment, and seeking damages in excess of $10 million. On November 28, 2023, Incline Energy filed a motion to dismiss these claims. We opposed Incline Energy’s motion. The court has permitted additional filings, including a motion for leave to amend the complaint that would add antitrust claims against Incline Energy. The court has not yet ruled on the parties’ pleading-stage motions.
From time to time, we may be involved in various legal proceedings, lawsuits, regulatory investigations, and other claims in the ordinary course of business. In particular, due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. Such matters are subject to many uncertainties, and outcomes are not predictable with certainty. In the opinion of our management, none of the other pending litigation matters, disputes, or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows, or results of operations.
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We are a member-managed limited liability company organized under the laws of the State of Delaware, and do not have a board of directors, board of managers, or similar construct (or any committees thereof). We are wholly owned and controlled by Phoenix Equity. LJC has the power to select or remove Phoenix Equity’s managers in its sole discretion pursuant to its limited liability company agreement. No other unitholders of Phoenix Equity are entitled to appoint managers or otherwise directly participate in Phoenix Equity’s management or operations. Pursuant to our organizational documents, any manager of Phoenix Equity will be deemed to be the manager of the Issuer for all purposes of the Delaware Limited Liability Company Act (the “DLLCA”). As of the date of this prospectus, Adam Ferrari, our Chief Executive Officer, is the sole manager of Phoenix Equity. Therefore, none of Phoenix Equity’s managers would be considered “independent” under the rules of any national securities exchange or inter-dealer quotation system. As used in this section “we,” “our,” and “us” refer to Phoenix Equity and its subsidiaries.
The following table sets forth certain information about our manager, executive officers, and significant employees as of the date of this prospectus:
| Name |
Age |
Position |
Since | |||
| Executive Officers | ||||||
| Adam Ferrari | 42 | Manager and Chief Executive Officer | November 2023 | |||
| Curtis Allen | 39 | Chief Financial Officer | February 2020 | |||
| Brandon Allen | 44 | Chief Operating Officer | December 2024 | |||
| Lindsey Wilson | 40 | Chief Business Officer | December 2024 | |||
| Sean Goodnight | 50 | Chief Acquisition Officer | June 2020 | |||
| Justin Arn | 45 | Chief Land and Title Officer | April 2020 | |||
| David Wheeler | 50 | Chief Legal Officer | October 2024 | |||
| Significant Employees | ||||||
| Matthew Willer | 48 | Managing Director, Capital Markets | March 2021 | |||
Set forth below is a brief description of the business experience of our manager and each of our executive officers and significant employees. All of our officers serve at the discretion of LJC.
Adam Ferrari, Manager and Chief Executive Officer. Adam has been Manager and Chief Executive Officer since November 2023. Adam served as our Vice President of Engineering from April 2023 until November 2023, during which time he was responsible for conducting engineering evaluations across all areas of interest and making purchase recommendations to our executive team. Prior to April 2023, Adam provided us with advisory services since our founding in 2019. Adam began his career with BP America as a completions engineer in 2005. During his tenure with BP America, Adam served in various drilling, completions, and production roles, both in the Gulf of Mexico and in the onshore U.S. business units. Following his experience at BP America, Adam transitioned to an equity analyst role within the Oil and Gas division at Macquarie Capital. After gaining experience on the financial services side of the oil and gas industry, Adam transitioned back to the operating side in a lead Petroleum Engineering role with then-start-up Halcón Resources Corporation (now Battalion Oil Corporation (NYSE: BATL) (“Halcón”)). While at Halcón, Adam supported various exploration and development programs in the broader Gulf Coast region and the Bakken shale asset in North Dakota. Following his tenure at Halcón, Adam pursued entrepreneurial opportunities on the mineral acquisitions side of the oil and gas industry that ultimately led him to us. Immediately prior to providing us advisory services, Adam was the Chief Executive Officer of The Petram Group, LLC (f/k/a Wolfhawk Energy Holdings, LLC d/b/a “Ferrari Energy”) (“The Petram Group”) from December 2016 until March 2019. Prior to his employment at The Petram Group, Mr. Ferrari founded and operated Ferrari Energy, LLC, which was active in acquiring and disposing of mineral interests from 2014 to 2017. In early 2016, Wolfhawk Energy Holdings, LLC (later to be renamed The Petram Group, LLC) began operating under the brand name “Ferrari Energy,” even though there was no formal connection between Ferrari Energy, LLC and Wolfhawk Energy Holdings, LLC. Currently, Ferrari Energy, LLC has no employees, holds only one remaining mineral property, and is otherwise inactive. Adam graduated magna cum laude from the University of Illinois at Urbana-Champagne with a Bachelor of Science Degree in Chemical Engineering. Adam Ferrari is the spouse of Brynn Ferrari, our Chief Marketing Officer, and the son of Charlene and Daniel Ferrari, who control LJC.
Curtis Allen, Chief Financial Officer. Curtis has been our Chief Financial Officer since February 2020. Curtis is responsible for all accounting and finance functions and mineral underwriting, along with a multitude of day-to-day operational tasks. Curtis has over 15 years’ experience in financial services with an emphasis on investment analysis. Curtis has a range of accounting and financial experience, from a private tax practice to auditing billion-dollar defense contractors with the Department of Defense. Most recently prior to joining our company, Curtis spent over seven years managing investments for personal and corporate clients at LPL Financial. Curtis is a Certified Public Accountant, has held FINRA Series 7 and Series 66 licenses, and has passed the Chartered Financial Analyst Level I exam. Curtis graduated magna cum laude from the State University of New York at Oswego with both his Bachelor of Science and Master of Business Administration concentrated in Accounting.
Brandon Allen, Chief Operating Officer. Brandon has been our Chief Operating Officer since December 2024. Brandon previously served as PhoenixOp’s President from February 2024 and as its Vice President of Reservoir Engineering from March 2023 to February 2024. Brandon is responsible for overseeing all of the operations of the business, including maintaining the reserves for all Phoenix Energy ownership. Brandon has over 19 years of experience in the oil and gas business, spanning multiple basins throughout the United States. He has a range of oil and gas experience, offering expertise in reservoir engineering, SEC reserves estimation and reporting, financial reporting, operations planning, asset development and planning, and acquisition evaluation. Immediately prior to joining PhoenixOp, Brandon founded and served as the Senior Vice President of CarbonPath, Inc., a startup carbon credit business. Brandon received a Bachelor of Science degree in Chemical Engineering and a Bachelor of the Arts degree in Biochemistry from the University of Colorado at Boulder.
Lindsey Wilson, Chief Business Officer. Lindsey has been our Chief Business Officer since December 2024. Prior to that time, Lindsey served as our Chief Operating Officer since she helped to found our company in 2019. Lindsey is responsible for overseeing a wide range of business matters related to our operations and takes great pride in working with all of our departments on setting and achieving aggressive business goals. Lindsey brings to our company years of extensive practical experience leading diverse, multidisciplinary teams in the energy sector. Lindsey entered the oil and gas industry in 2011 working leasing projects in Texas, and this foundational experience was the springboard that ultimately allowed her to transition into more advanced management roles within the mineral and leasehold acquisition space. From 2017 until immediately prior to helping found our company, Lindsey was employed as the Operations Manager of The Petram Group. Lindsey graduated from the University of Texas at Arlington and holds a Bachelor of Business Administration with a concentration in Marketing.
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Sean Goodnight, Chief Acquisitions Officer. Sean has been our Chief Acquisitions Officer since June 2020. Sean brings over 25 years of consultative sales experience to our company. Sean leads our acquisitions, securities, and sales efforts and has implemented processes, developed tools, and introduced materials that have contributed to the continued success of our company. He has built a team of talented, sophisticated professionals who possess the expertise and skillset to maintain the high standards that have become the foundation of his department. Sean spent the early part of his career in the health care and insurance industries, and was introduced into the oil and gas industry in 2016 working with mineral acquisitions, where he quickly transitioned into management. Prior to joining our company, Mr. Goodnight was employed by The Petram Group as an acquisitions landman from 2016 to 2018.
Justin Arn, Chief Land and Title Officer. Justin has been our Chief Land and Title Officer since April 2020. Justin began his Land career researching mineral and royalty rights for multiple mineral acquisition companies focusing on the DJ Basin in Weld County, Colorado, and Laramie County, Wyoming. He has coordinated and managed title projects, large and small, in Wyoming, Colorado, North Dakota, Montana, and Texas, and performed and managed opportunity and due diligence title work for the purchase of thousands of royalty acres throughout the DJ, Bakken, and Permian basins. Immediately prior to joining our company, Justin was employed as a landman for The Petram Group from 2017 to 2020. Justin is an active member of the American Association of Professional Landmen and the Wyoming Association of Professional Landmen.
David Wheeler, Chief Legal Officer. David has been our Chief Legal Officer since October 2024 and is based out of our Irvine, California office. David is responsible for overseeing our day-to-day legal needs and providing advice and guidance to the management team on legal matters, including with respect to capital markets and securities laws and compliance, corporate structuring and governance, litigation management, and contract negotiation and drafting. David comes to us with over 20 years of legal experience as a corporate lawyer, serving most recently for over four years as the Chief Legal Officer of a private equity sponsored company with global operations operating in a regulated industry. Prior to that, David spent almost 13 years at Latham & Watkins LLP in their corporate department, advising both public and private clients on a wide variety of corporate law matters, including mergers and acquisitions, corporate governance, capital markets transactions, public company representation, and other general corporate and transactional matters. David graduated from The University of Southern California Gould School of Law with a Juris Doctorate and from Brigham Young University with a Bachelor of Science Degree in Business Management. David is actively licensed to practice law in the State of California.
Matthew Willer, Managing Director, Capital Markets. Matthew has been serving as our Managing Director, Capital Markets, since March 2021. Matthew is responsible for investor relations and outreach and coordinating our investor presentations across our multiple debt offerings. Matthew is also the President and Director of M.D. Willer & Co., a boutique capital markets firm specializing in the needs of small-cap issuers, a position he has held since January 2002. Previously, Matthew co-founded Assure Holdings Corp., where he served as its President and Director from March 2016 to March 2018. Matthew received his Bachelor of Science in Finance and Management from the University of Southern California’s Marshall School of Business, with an emphasis on Finance and Management.
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COMPENSATION DISCUSSION AND ANALYSIS
This compensation discussion and analysis discusses the material components and principles underlying the executive compensation program for our executive officers who are named in the Summary Compensation Table (as defined below). In 2024, our “named executive officers” and their positions were as follows:
| • | Adam Ferrari, Chief Executive Officer; |
| • | Curtis Allen, Chief Financial Officer; |
| • | Sean Goodnight, Chief Acquisitions Officer; |
| • | Brandon Allen, Chief Operating Officer; and |
| • | Lindsey Wilson, Chief Business Officer. |
Where relevant, the discussion below also reflects certain contemplated changes to our compensation structure that occurred after our 2024 fiscal year. Actual compensation programs that we adopt following the completion of this offering may differ materially from the currently planned programs summarized in this discussion but, absent a requirement to update our offering materials, we will not update this discussion to reflect any changes to the currently planned programs.
Details of Our Compensation Program
Executive Compensation Philosophy and Objectives
Our compensation programs are designed to help achieve the goals of attracting, incentivizing, and retaining highly talented individuals who are committed to our company, while balancing the long-term interests of our members, investors, and customers. The principles and objectives of our compensation and benefits program for our named executive officers are to:
| • | attract, retain, and motivate individuals who are capable of advancing our financial goals and, ultimately, creating and maintaining our long-term equity value; |
| • | reward executives in a manner aligned with our financial performance to drive pay for performance; and |
| • | provide a total compensation opportunity that is competitive with our market and the industry within which we seek executive talent. |
Other than Mr. Ferrari, each of our named executive officers is a member in Phoenix Equity and may become entitled to future distributions with respect to their membership interests under the Second Amended and Restated Limited Liability Company Agreement of Phoenix Equity, dated December 4, 2024 (as the same may be amended or supplemented from time to time, the “Phoenix Equity Operating Agreement”). Under the terms of the Phoenix Equity Operating Agreement, any payments of wages, consulting fees, commissions, or other cash compensation for services rendered and the out-of-pocket costs incurred by us for any health, welfare, retirement, fringe, or other similar benefits provided to our members, including our executive officers, are deemed to be a draw against and will reduce future distributions to the member with respect to such member’s membership interest in Phoenix Equity. Although Mr. Ferrari is not a member in Phoenix Equity, he holds 100% of the economic interests in LJC, and LJC is a member in Phoenix Equity. On April 25, 2025, the Phoenix Equity Operating Agreement was amended to clarify that any payments of wages, consulting fees, commissions, or other cash compensation for services rendered, and the out-of-pocket costs incurred, by us for any health, welfare, retirement, fringe, or other similar benefits provided to Mr. Ferrari, whether such amounts are paid on, prior to, or following April 25, 2025, will reduce future distributions to LJC with respect to LJC’s membership interests in Phoenix Equity.
Accordingly, base salary, variable revenue-based compensation, bonuses, and commission payment amounts are agreed upon from time to time by our named executive officers and our company and are subject to change, in each case, as determined by our chief executive officer in consultation with or, with respect to Mr. Ferrari, the approval of, LJC.
Compensation Governance and Best Practices
We are committed to having strong governance standards with respect to our compensation programs, procedures, and practices. Our key compensation practices include the following:
| • | Pay for performance. Any compensation paid to our named executive officers, either in terms of base salary, variable revenue-based compensation, bonuses, or commission payments, will ultimately reduce the future distributions payable to such named executive officer with respect to his or her membership interest in Phoenix Equity (or, for Mr. Ferrari, payable to LJC). This is intended to align their interests with investors. Mr. Ferrari’s variable revenue-based compensation is determined by LJC and directly tied to the performance of our company and its annual revenues in order to align Mr. Ferrari’s interests with our members and investors. |
| • | No guaranteed annual salary increases. Other than with respect to Mr. Ferrari, our named executive officers’ salaries are based on individual evaluations and agreed to from time to time by our named executive officers and our chief executive officer with the input of certain other named executive officers and LJC. Mr. Ferrari’s compensation is determined by LJC and Mr. Ferrari as agreed upon from time to time based on the performance of our company. |
| • | No pledging. We prohibit our members, including our named executive officers, from pledging any membership interests in Phoenix Equity, except with the prior consent of LJC or as otherwise permitted by the Phoenix Equity Operating Agreement. |
Determination of Compensation and Role of Executive Officers in Determining Executive Compensation
Our chief executive officer consults with LJC and certain of our named executive officers to make compensation decisions with respect to our
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named executive officers. Ultimately, our chief executive officer, together with LJC, made 2024 compensation decisions for each of our named executive officers (other than Mr. Ferrari) based on their collective experience and knowledge of the compensation practices in our industry and that of similar companies within our industry. As described above, because any compensation payable to our named executive officers ultimately reduces each named executive officer’s future distributions payable with respect to his or her membership interest in Phoenix Equity (or, for Mr. Ferrari, payable to LJC), our named executive officers agree to their annual compensation packages. Mr. Ferrari’s 2024 compensation was determined by LJC with input from certain of the named executive officers based on our company’s projected performance and an analysis of compensation practices within our industry.
We expect that going forward our chief executive officer, in consultation with LJC, will continue to make future compensation decisions with respect to our named executive officers other than himself. We expect that LJC will continue to make future compensation decisions with respect to Mr. Ferrari, as the chief executive officer. We do not currently have any plans to form a compensation committee or otherwise obtain third-party guidance regarding our compensation program.
Elements of Our Executive Compensation Program
We design the principal components of our executive compensation program to fulfill one or more of the principles and objectives described above. Compensation of any named executive officers consist of the following elements:
| • | base compensation, either in the form of guaranteed salary or variable revenue-based compensation; |
| • | bonuses; |
| • | commissions; |
| • | equity compensation; and |
| • | health and welfare benefits and certain perquisites and other benefits generally offered to all employees of our company. |
Our compensation program is designed to be flexible and complementary and to collectively serve all of the executives’ compensation objectives described above. Therefore, we do not currently have, and we do not expect to have, formal policies relating to the allocation of total compensation among the various elements of our compensation program.
Each of our named executive officers, other than Mr. Ferrari, is a member in Phoenix Equity and may become entitled to future distributions with respect to their membership interests under the Phoenix Equity Operating Agreement. Under the terms of the Phoenix Equity Operating Agreement, any payments of wages, consulting fees, bonuses, commissions, or other cash compensation for services rendered and the out-of-pocket costs incurred by us for any health, welfare, retirement, fringe, or other similar benefits provided to our members, including our named executive officers, are deemed to be a draw against and will reduce future distributions to the named executive officer with respect to such named executive officer’s membership interest in Phoenix Equity (or, for Mr. Ferrari, payable to LJC). Accordingly, base compensation, variable revenue-based compensation, bonuses, and commission payment amounts are agreed upon from time to time by our named executive officers and our chief executive officer, in consultation with or, with respect to Mr. Ferrari, the approval of LJC, and are subject to change. We continue to evaluate the mix of base compensation, bonuses, commissions, and equity-based compensation to appropriately align the interests of our named executive officers with those of our members and investors.
Base Compensation
Certain of our named executive officers receive a base salary determined by our chief executive officer in consultation with LJC and certain other executive officers. Base salary is a visible and stable fixed component of our compensation program. Base salaries for our named executive officers were initially established at the time each executive was hired and may be adjusted from time to time as determined by our chief executive officer based on our company’s performance, market conditions, and individual performance and to be competitive within our market and industry.
Messrs. Ferrari and Curtis Allen and Ms. Wilson are entitled to receive variable revenue-based compensation tied to revenue targets of our company set by LJC, in lieu of a base salary. LJC may exercise discretion in determining variable compensation for the named executive officers, and may also approve additional variable or other compensation for the named executive officers as it determines in its discretion, in each case, taking into consideration such factors as LJC determines are appropriate.
The following table sets forth the base compensation of our named executive officers for 2024:
| Named Executive Officer |
2024 Annual Base Compensation | |||
| Adam Ferrari |
$ | 3,135,000 | (1) | |
| Curtis Allen |
$ | 1,567,500 | (1) | |
| Sean Goodnight |
$ | 455,000 | (2) | |
| Brandon Allen |
$ | 300,000 | (2) | |
| Lindsey Wilson |
$ | 399,000 | (1) | |
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| (1) | Represents variable revenue-based compensation. |
| (2) | Represents annual base salary. |
The increase in the compensation for Messrs. Ferrari and Curtis Allen for 2024 was determined by LJC based on our significant growth year over year, as evidenced by the fact that our gross revenue more than doubled from 2023 to 2024, our overall operational performance, and an analysis of the compensation of executive officers of similarly sized companies within our industry.
For 2024, variable revenue-based compensation for Messrs. Ferrari and Curtis Allen and Ms. Wilson was tied to a gross revenue target of $285 million set by LJC. No other revenue targets were used to determine the named executive officers’ 2024 variable revenue-based compensation. Messrs. Ferrari and Curtis Allen and Ms. Wilson were entitled to 1.10%, 0.55%, and 0.14% of our 2024 gross revenue, respectively, upon achievement of the gross revenue target. Payments were made twice monthly throughout 2024 based on the assumed achievement of our revenue target with a final true-up payment at year end.
Our actual gross revenue for 2024 was $281 million. LJC determined in its discretion that our gross revenue of $281 million for the year substantially satisfied the gross revenue target of $285 million, and Messrs. Ferrari and Curtis Allen and Ms. Wilson accordingly received their full variable compensation amounts (i.e., $3,135,000, $1,567,500, and $399,000, respectively), even though we did not meet our gross revenue target of $285 million upon which variable compensation was contingent under the named executive officers’ 2024 employee agreements.
LJC may exercise similar discretion in the future with respect to the variable compensation, and may determine to pay full variable compensation amounts even where our gross revenue falls short of a stated target.
We have not implemented formal agreements, policies, or other arrangements or mechanisms to facilitate recovery of variable revenue-based compensation paid to the named executive officers in the event actual revenue differs from an estimated or assumed level used to calculate the variable revenue-based compensation payments made to our named executive officers throughout the year or otherwise falls below an applicable revenue target. The appropriateness and manner of seeking any such recovery would be within LJC’s and (except as to his own compensation) Mr. Ferrari’s discretion, taking into account any factors that they determine are appropriate, including that, as discussed elsewhere in this compensation discussion and analysis, all compensation paid to Messrs. Ferrari and Curtis Allen and Ms. Wilson is a draw against, and will reduce, future distributions payable to the member with respect to such member’s membership interest in Phoenix Equity (or, for Mr. Ferrari, payable to LJC with respect to LJC’s interest in Phoenix Equity). LJC and, for the named executive officers other than himself, Mr. Ferrari, have broad discretion to approve the compensation of our named executive officers on an annual basis and from time to time, and could account for such an event in a number of ways, including, for example, by updating the assumed level of revenue upon which semi-monthly payments are made during a year, or, to the extent any such difference is not reflected in the final true up payment for a given year, considering any overage amount when setting assumed revenue amounts, revenue sharing percentages, or annual discretionary bonuses for future years.
Bonuses
Our chief executive officer, in consultation with LJC, determined that each of Messrs. Goodnight and Brandon Allen should be eligible to earn discretionary bonuses as part of each such named executive officer’s 2024 compensation package based on each such named executive officer’s individual performance and the performance of our company.
Mr. Goodnight’s bonus earned for 2024 was $205,000 and will be payable in March 2025. Mr. Goodnight received a discretionary additional bonus in the amount of $95,000 in December 2024. Mr. Brandon Allen’s bonus earned for 2024 was $225,000 and will be payable in March 2025.
While Ms. Wilson is not expressly entitled to a bonus as part of her 2024 compensation package, our chief executive officer may determine in his discretion to grant her a bonus based on her individual performance and the performance of our company. During 2024, Ms. Wilson received aggregate bonus payments in the amount of $32,000.
Commissions
During 2024, Mr. Goodnight was eligible to receive sales commissions based on a percentage of the adjusted purchase price of mineral interests and interests in oil and gas properties that he is directly responsible for our company acquiring in connection with our operations. Pursuant to the terms of the Commission Agreement by and between Mr. Goodnight and us, effective as of January 16, 2024 (the “Goodnight Commission Agreement”), Mr. Goodnight was eligible to earn a commission of 3.5% for closed mineral deals and 3% for closed lease deals during 2024. No such commissions were earned during 2024.
Equity Compensation
We view equity-based compensation as a critical component of our total compensation program. Equity-based compensation creates an ownership culture among our employees that provides an incentive to contribute to the continued growth and development of our business and aligns interests of executives with those of our members and investors. We do not currently have any formal policy for determining the number of equity-based awards to grant to named executive officers, but all named executive officers, along with all employees of our company, are eligible for awards under our 2024 Long-Term Incentive Plan.
Each of Mr. Curtis Allen, Mr. Goodnight, and Ms. Wilson was previously granted equity compensation in the form of profits interests in our company, which were exchanged for profits interests in Phoenix Equity effective as of October 18, 2024. The profits interests were designed to align the interests of our named executive officers with the interests of other members of Phoenix Equity and its affiliates and represented interests in the future profits in Phoenix Equity. The profits interests were fully vested at grant, subject to certain repurchase rights in the event of the death or incapacity of the profits interest holder.
On December 4, 2024, except as otherwise described for Mr. Curtis Allen and Ms. Wilson, the profits interests in Phoenix Equity held by our named executive officers (along with all other profits interests in Phoenix Equity) were cancelled in exchange for restricted units in Phoenix Equity. With respect to each of Mr. Curtis Allen and Ms. Wilson, on December 4, 2024, 50% of the vested profits interests in Phoenix Equity held by each of Mr. Curtis Allen and Ms. Wilson was cancelled in exchange for restricted units in Phoenix Equity, and 50% of the vested profits interests held by such named executive officers was cancelled in exchange for vested units in Phoenix Equity (the “retained units”). In addition, at the same time, Mr. Brandon Allen was issued restricted units in Phoenix Equity.
The restricted units issued to each of our named executive officers are Class A Units and Class B Units in Phoenix Equity subject to restrictions on transferability as set forth in the Phoenix Equity Operating Agreement. In addition, as set forth in the applicable award agreement evidencing the issuance of the restricted units, the restricted units are subject to forfeiture in the event that such named executive officer ceases to be employed with Phoenix Equity and its subsidiaries prior to a change in control of Phoenix Equity. The restricted units are also subject to our repurchase rights under the Phoenix Equity Operating Agreement in the event of the named executive officer’s termination of employment for any reason other than upon a “Liquidity Event” (as defined in the Phoenix Equity Operating Agreement), except as set forth in an agreement between us and the named executive officer.
The retained units issued to Mr. Curtis Allen and Ms. Wilson in exchange for 50% of each such named executive officer’s vested profits interests in Phoenix Equity are fully vested Class A Units and Class B Units in Phoenix Equity that are not subject to forfeiture upon a termination of the named executive officer’s employment. In addition, as set forth in the applicable award agreement evidencing the issuance of the retained units, the retained units are not subject to repurchase by Phoenix Equity, and Phoenix Equity has also agreed that neither Mr. Curtis Allen nor Ms. Wilson will be subject to expulsion as a member of Phoenix Equity.
In connection with the conversion described above and the issuance of restricted units to certain other employees, our named executive officers were issued the following number of Class A Units and Class B Units:
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| Name |
Restricted Class A Units | Vested Class A Units | Restricted Class B Units | Vested Class B Units | ||||||||||||
| Adam Ferrari |
— | — | — | — | ||||||||||||
| Curtis Allen |
262,505 | 262,505 | 96,245 | 96,245 | ||||||||||||
| Sean Goodnight |
53,570 | — | 210,930 | — | ||||||||||||
| Brandon Allen |
53,570 | — | 176,930 | — | ||||||||||||
| Lindsey Wilson |
26,785 | 26,785 | 153,215 | 153,215 | ||||||||||||
In addition to the Class A Units and Class B Units granted to Ms. Wilson, Ms. Wilson was also entitled to receive a cash payment equal to $1,185,300 in lieu of any additional Class A Units or Class B Units she would otherwise have been entitled to as part of the conversion of her profits interests in Phoenix Equity to units in Phoenix Equity. Ms. Wilson received $150,000 of this amount in December 2024 with the remaining portion expected to be paid in 2025.
Retirement Savings and Health and Welfare Benefits
We currently maintain a 401(k) retirement savings plan for our employees, including our named executive officers, who satisfy certain eligibility requirements. Our named executive officers are eligible to participate in the 401(k) plan on the same terms as apply to our other employees generally. The U.S. Internal Revenue Code of 1986, as amended (the “Code”), allows eligible participants to defer a portion of their compensation, within prescribed limits, through elective contributions to the 401(k) plan. During the year ended December 31, 2024, we made company contributions to the 401(k) plan equal to 100% of elective contributions made by participants in the 401(k) plan, up to 3% of a participant’s eligible compensation.
All of our full-time employees, including our named executive officers, are eligible to participate in our health and welfare plans, including medical, dental, and vision benefits.
Perquisites and Other Personal Benefits
Each of Mr. Ferrari, Mr. Curtis Allen, Mr. Goodnight, and Ms. Wilson received an automobile allowance from January 1, 2024 until March 31, 2024. We ceased to provide this automobile allowance to any of our named executive officers beginning in April 2024.
Other than the automobile allowance provided to certain of our named executive officers, we did not provide any perquisites or special personal benefits to our named executive officers during 2024, but our chief executive officer may from time to time approve them in the future when it is determined that such perquisites are necessary or advisable to fairly compensate or incentivize our employees.
Employment Arrangements
In November 2023, we entered into an employment letter agreement with Mr. Ferrari that provides that he will be paid approximately $29,167 per month and be eligible to receive company benefits. We entered into a revised employee agreement with Mr. Ferrari, effective January 1, 2024, that provides that he will receive variable compensation based on a percentage of our revenues, and that he is eligible to participate in our employee benefit plans. See “—Elements of Our Executive Compensation Program—Base Compensation” above for more information regarding Mr. Ferrari’s variable compensation.
We entered into an employee agreement with each of Mr. Curtis Allen and Ms. Wilson, effective January 1, 2024, that provides that each such named executive officer will receive variable compensation based on a percentage of our revenues, and that they are eligible to participate in our employee benefit plans. See “—Elements of Our Executive Compensation Program—Base Compensation” above for more information regarding Mr. Curtis Allen’s and Ms. Wilson’s variable compensation.
We entered into an offer letter with Mr. Goodnight in June 2020 in connection with his commencement of employment with our company. Mr. Goodnight’s offer letter provides that his compensation package will be composed entirely of commission payments. In January 2024 we entered into the Goodnight Commission Agreement outlining the terms of Mr. Goodnight’s commission payments, as described above under “—Elements of Our Executive Compensation Program—Commissions.”
We also entered into an offer letter with Mr. Brandon Allen in March 2023 in connection with his commencement of employment with our company. Mr. Brandon Allen’s offer letter sets forth the terms of his initial compensation package, including annual base salary, ability to receive additional discretionary bonuses based on our company’s performance, and eligibility to participate in our employee benefit plans.
Each of Messrs. Goodnight’s and Brandon Allen’s compensation arrangements have been adjusted from time to time as determined by our
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chief executive officer and agreed to by each such named executive officer, based on our company’s performance, market conditions, and individual performance and as needed to remain competitive within our market and industry. For 2024, the compensation arrangements for each of Messrs. Goodnight and Brandon Allen were not subject to a written agreement, but included base salaries as described above under “—Elements of Our Executive Compensation Program—Base Compensation” and discretionary bonuses as described above under “—Elements of Our Executive Compensation Program—Bonuses.”
Tax Considerations
As a general matter, our chief executive officer, in consultation with certain other executive officers and outside advisors, reviews and considers the various tax and accounting implications of compensation programs we utilize.
Compensation Policies
We do not currently maintain any formal compensation policies due to our governance structure and the nature in which compensation is mutually determined by our named executive officers and our chief executive officer in consultation with LJC.
Material Compensation Decisions Following December 31, 2024
We entered into an employee agreement with each of Mr. Ferrari, Mr. Curtis Allen, and Ms. Wilson, effective January 1, 2025, that provides that each such named executive officer will continue to receive variable compensation based on a percentage of our revenue, and continue to be eligible to participate in our employee benefit plans.
LJC determined that 2025 variable revenue-based compensation would again be based only on our gross revenues. No changes were made to the percentage of gross revenue to which each of Messrs. Ferrari and Curtis Allen is entitled in 2025 as compared to 2024, but the percentage of revenue to which Ms. Wilson is entitled in 2025 was reduced from 0.14% to 0.10% of our company’s revenue. Subject to the advance to Mr. Ferrari described below, payments will continue to be made twice a month throughout 2025. These payments will be made based on an assumed gross revenue amount for 2025 set by LJC. As of the date of this prospectus, the assumed gross revenue amount for 2025 set by LJC for purposes of calculating the twice-a-month payments is $500 million. LJC may revise such assumed gross revenue amount and at its discretion during the course of the year. The total variable compensation may potentially be trued up on December 15, 2025, using annual gross revenue estimates prepared from the books and records of our company as of such date, to the extent LJC determines that additional variable compensation is payable.
Consistent with the terms of our 2025 employment agreement with Mr. Ferrari, we paid Mr. Ferrari $3,000,000 of his total 2025 variable compensation in January 2025. The remaining portion of Mr. Ferrari’s variable compensation is payable twice a month through December 31, 2025 as set forth above, but with each such payment reduced to account for the January 2025 advance and with a potential final true up at year end using annual gross revenue estimates prepared from our books and records as of December 15, 2025 to the extent LJC determines that additional variable compensation is payable.
LJC elected this structure for 2025 in the exercise of its business judgement and taking into account factors that included the substantial growth in operations our company experienced under the executive officers’ leadership, including our successful and rapid expansion into oil and gas production and execution of our business strategy, as well as, for Mr. Ferrari, LJC’s determination that his prior pay was below market-competitive levels.
We have not implemented formal agreements, policies, or other arrangements or mechanisms to facilitate recovery of variable revenue-based compensation paid to the named executive officers in the event revenue differs from an estimated or assumed level used to calculate the variable revenue-based compensation payments made to our named executive officers throughout the year or otherwise falls below an applicable revenue target. For additional information regarding potential recovery of variable revenue-based compensation, refer to the discussion under “—Elements of Our Executive Compensation Program—Base Compensation” above.
In addition, in January 2025, we entered into an amendment to Mr. Brandon Allen’s offer letter eliminating his ability to receive annual bonuses beginning in 2025 and providing that, effective for our 2025 fiscal year and future years, any salary changes and discretionary bonuses would be payable in the sole discretion of LJC. Mr. Brandon Allen’s base salary for 2025 was increased to $575,000. Such amounts were determined by the chief executive officer in consultation with LJC and certain other of our executive officers and were agreed to by Mr. Brandon Allen.
In January 2025, we also increased Mr. Goodnight’s base salary to $460,000, as determined by the chief executive officer in consultation with LJC and certain other of our executive officers.
For our 2025 fiscal year, our company has increased the maximum company contributions to the 401(k) plan to an amount equal to up to 4% of the amount eligible participants invest in the 401(k) plan. All named executive officers remain eligible to participate on the same terms as all other employees of our company.
As described above under “—Details of Our Compensation Program—Executive Compensation Philosophy and Objectives,” the Phoenix Equity Operating Agreement was amended on April 25, 2025 to clarify that any payments of wages, consulting fees, commissions, or other cash compensation for services rendered, and the out-of-pocket costs incurred, by us for any health, welfare, retirement, fringe, or other similar benefits provided to Mr. Ferrari, whether such amounts are paid on, prior to, or following April 25, 2025, will reduce future distributions from Phoenix Equity to LJC with respect to LJC’s membership interests in Phoenix Equity. Because Mr. Ferrari holds 100% of the economic interests of LJC, the indirect impact of the amendment to the Phoenix Equity Operating Agreement is that any above-described amounts paid by us to Mr. Ferrari ultimately reduce the future distributions by us to LJC, and from LJC to Mr. Ferrari.
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Executive Compensation
2024 Summary Compensation Table
The following table (the “Summary Compensation Table”) sets forth information concerning the compensation of our named executive officers for the year ended December 31, 2024:
| Name and Principal Position |
Year | Salary ($)(1) |
Bonus ($)(2) |
Stock Awards ($)(3) |
All Other Compensation ($)(4) |
Total ($) |
||||||||||||||||||
| Adam Ferrari Chief Executive Officer |
2024 | 3,135,000 | — | — | 19,571 | 3,154,571 | ||||||||||||||||||
| 2023 | 408,334 | — | — | 48,395 | 456,729 | |||||||||||||||||||
| Curtis Allen Chief Financial Officer |
2024 | 1,567,500 | — | — | (5) | 12,611 | 1,580,111 | |||||||||||||||||
| 2023 | 360,355 | — | 29,337 | 389,692 | ||||||||||||||||||||
| 2022 | 196,000 | — | — | — | 196,000 | |||||||||||||||||||
| Sean Goodnight Chief Acquisitions Officer |
2024 | 455,000 | 300,000 | — | (5) | 6,218 | 761,218 | |||||||||||||||||
| 2023 | 483,402 | — | — | 19,447 | 502,849 | |||||||||||||||||||
| 2022 | 364,000 | — | — | — | 364,000 | |||||||||||||||||||
| Brandon Allen Chief Operating Officer |
2024 | 300,000 | 225,000 | — | 9,583 | 534,583 | ||||||||||||||||||
| Lindsey Wilson Chief Business Officer |
2024 | 399,000 | 32,000 | — | (5) | 16,189 | 447,189 | |||||||||||||||||
| 2023 | 300,000 | — | |
— |
|
38,453 | 338,453 | |||||||||||||||||
| 2022 | 180,000 | — | |
— |
|
— | 180,000 | |||||||||||||||||
| (1) | For 2024, the amount shown for Messrs. Ferrari and Curtis Allen and Ms. Wilson represents variable revenue-based compensation. Under the Phoenix Equity Operating Agreement, all such compensatory payments made to or for the benefit of the named executive officers that are also members of Phoenix Equity are deemed to be a draw against and will reduce future distributions to such executive with respect to the executive’s membership interest in Phoenix Equity. As described above under “—Material Compensation Decisions Following December 31, 2024,” the Phoenix Equity Operating Agreement was amended on April 25, 2025 to clarify that all such compensatory payments made to Mr. Ferrari will reduce the future distributions to LJC with respect to LJC’s membership interest in Phoenix Equity. |
| (2) | The amounts included for 2024 represent the amount of discretionary annual bonuses paid to each of Messrs. Goodnight and Brandon Allen and Ms. Wilson for services rendered during 2024. Under the Phoenix Equity Operating Agreement, all such bonuses are deemed to be a draw against and will reduce future distributions to each such named executive officer with respect to the named executive officer’s membership interest in Phoenix Equity. |
| (3) | The amounts included for 2024 represent the grant date fair value of the restricted Class A Units and restricted Class B Units in Phoenix Equity issued to each of our named executive officers, other than Mr. Ferrari, which will remain unvested until the date of a change in control of Phoenix Equity. The occurrence of a change in control of Phoenix Equity was deemed improbable such that no compensatory value has been assigned to such units under ASC Topic 718. Assuming a change in control of Phoenix Equity was probable, the grant date fair value of all restricted Class A Units granted to Messrs. Curtis Allen, Goodnight, and Brandon Allen and Ms. Wilson is $14,632,029, $2,985,992, $2,985,992, and $1,492,996, respectively, and the grant date fair value of all restricted Class B Units granted to each of Messrs. Curtis Allen, Goodnight, and Brandon Allen and Ms. Wilson is $5,364,697, $11,757,238, $9,862,078, and $8,540,204, respectively. See “—Elements of Our Executive Compensation Program—Equity Compensation” and “—Grants of Plan-Based Awards in 2024” for more information. |
| (4) | Amounts included for 2024 for each of Messrs. Ferrari and Goodnight and Ms. Wilson reflect the total cost to us of a company-provided automobile allowance for each such named executive officer. The amount included for 2024 for Mr. Curtis Allen reflects $12,611, the cost of a company-provided automobile allowance for such named executive officer, and company matching 401(k) plan contributions of $2,683. Amounts included for 2024 for Mr. Brandon Allen reflect company matching 401(k) plan contributions. We ceased to provide the named executive officers with a company-provided automobile allowance in April 2024. |
| (5) | Mr. Curtis Allen, Mr. Goodnight, and Ms. Wilson were previously granted profits interests in our company, which were exchanged for profits interests in Phoenix Equity effective as of October 18, 2024. On December 4, 2024, 50% of the profits interests in Phoenix Equity held by each of Mr. Curtis Allen and Ms. Wilson and 100% of the profits interests in Phoenix Equity held by Mr. Goodnight were converted into restricted Class A Units and Class B Units in Phoenix Equity. See “—Elements of Our Executive Compensation Program—Equity Compensation” and “—Grants of Plan-Based Awards in 2024” for more information. |
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Grants of Plan-Based Awards in 2024
The following table provides supplemental information relating to grants of plan-based awards made during 2024 to help explain information provided above in our Summary Compensation Table. This table presents information regarding all grants of plan-based awards occurring during 2024.
| Name |
Grant Date | All Other Stock Awards: Number of Shares of Stock (#) |
Grant Date Fair value of Stock Awards ($)(1) |
|||||||||
| Adam Ferrari |
— | — | $ | — | ||||||||
| Curtis Allen |
12/04/2024 | 262,505 | (2) | $ | — | (4) | ||||||
| 12/04/2024 | 96,245 | (3) | $ | — | (4) | |||||||
| Sean Goodnight |
12/04/2024 | 53,570 | (2) | $ | — | (4) | ||||||
| 12/04/2024 | 210,930 | (3) | $ | — | (4) | |||||||
| Brandon Allen |
12/04/2024 | 53,570 | (2) | $ | — | |||||||
| 12/04/2024 | 176,930 | (3) | $ | — | ||||||||
| Lindsey Wilson |
12/04/2024 | 26,785 | (2) | $ | — | (4) | ||||||
| 12/04/2024 | 153,215 | (3) | $ | — | (4) | |||||||
| (1) | These amounts represent the grant date fair value of restricted Class A Units and restricted Class B Units in Phoenix Equity issued to the named executive officers that are subject to forfeiture until the date of a change in control of Phoenix Equity, based on the probable outcome of such performance condition. See note 3 to the Summary Compensation Table above for more information. |
| (2) | Represents restricted Class A Units granted to each of our named executive officers other than Mr. Ferrari that are subject to forfeiture upon the named executive officer’s termination of employment for any reason prior to a change in control of Phoenix Equity. Such restricted Class A Units will remain unvested until the date of a change in control of Phoenix Equity. |
| (3) | Represents restricted Class B Units granted to each of our named executive officers other than Mr. Ferrari that are subject to forfeiture upon the named executive officer’s termination of employment for any reason prior to a change in control of Phoenix Equity. Such restricted Class B Units will remain unvested until the date of a change in control of Phoenix Equity. |
| (4) | Each of Mr. Curtis Allen, Mr. Goodnight, and Ms. Wilson was previously granted equity compensation in the form of profits interests in our company, which were exchanged for profits interests in Phoenix Equity effective as of October 18, 2024. On December 4, 2024, 50% of the profits interests in Phoenix Equity held by each of Mr. Curtis Allen and Ms. Wilson and 100% of the profits interests in Phoenix Equity held by Mr. Goodnight were converted into restricted Class A Units and Class B Units in Phoenix Equity. See “—Elements of Our Executive Compensation Program—Equity Compensation” and “— 2024 Summary Compensation Table” for more information. |
Outstanding Equity Awards at 2024 Fiscal Year-End
The following table sets forth certain information about restricted units granted to our named executive officers outstanding as of December 31, 2024:
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| Name |
Stock Awards | |||||||
| Number of Shares or Units of Stock that Have Not Vested (#) |
Market Value of Shares or Units of Stock that Have Not Vested ($)(1) |
|||||||
| Adam Ferrari |
— | — | ||||||
| Curtis Allen |
262,505 | (2) | $ | 14,632,029 | ||||
| 96,245 | (3) | $ | 5,364,696 | |||||
| Sean Goodnight |
53,570 | (2) | $ | 2,985,992 | ||||
| 210,930 | (3) | $ | 11,757,238 | |||||
| Brandon Allen |
53,570 | (2) | $ | 2,985,992 | ||||
| 176,930 | (3) | $ | 9,862,078 | |||||
| Lindsey Wilson |
26,785 | (2) | $ | 1,492,996 | ||||
| 153,215 | (3) | $ | 8,540,204 | |||||
| (1) | Market value based on $55.74, the fair market value of the Class A Units and Class B Units of Phoenix Equity on December 31, 2024, based on an independent third-party valuation we received. |
| (2) | Represents the number of restricted Class A Units held by each of our named executive officers (other than Mr. Ferrari) that are subject to forfeiture upon the named executive officer’s termination of employment for any reason prior to a change in control of Phoenix Equity. As discussed above under the heading “—Elements of Our Executive Compensation Program—Equity Compensation,” the profits interests previously held by each of our named executive officers (other than Mr. Ferrari) were exchanged for profits interests in Phoenix Equity effective as of October 18, 2024, and were subsequently converted into restricted units (and, for Mr. Curtis Allen and Ms. Wilson, retained units) in Phoenix Equity on December 4, 2024. Refer to “—Elements of Our Executive Compensation Program—Equity Compensation” above for additional information. |
| (3) | Represents the number of restricted Class B units held by each of our named executive officers (other than Mr. Ferrari) that are subject to forfeiture upon the named executive officer’s termination of employment for any reason prior to a change in control of Phoenix Equity. As discussed above under the heading “—Elements of Our Executive Compensation Program—Equity Compensation,” the profits interests previously held by each of our named executive officers (other than Mr. Ferrari) were exchanged for profits interests in Phoenix Equity effective as of October 18, 2024, and were subsequently converted into restricted units (and, for Mr. Curtis Allen and Ms. Wilson, retained units) in Phoenix Equity on December 4, 2024. Refer to “—Elements of Our Executive Compensation Program—Equity Compensation” above for additional information. |
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Potential Payments Upon Termination or Change in Control
None of our named executive officers are entitled to cash severance or benefits upon his or her termination of employment for any reason, provided that our company may determine to pay cash severance or grant severance benefits upon a named executive officer’s termination of employment in the discretion of our chief executive officer and/or LJC. We do not have a written or formal severance plan or policy that applies to any employees of our company, including any of the named executive officers.
Upon a “Liquidity Event” (as defined in the Phoenix Equity Operating Agreement) the forfeiture and repurchase provisions applicable to the restricted Class A Units and restricted Class B Units held by any of our named executive officers will lapse.
For purposes of the restricted Class A Units and restricted Class B Units in Phoenix Equity, a “Liquidity Event” generally means the occurrence of one of the following:
| • | a sale or disposition, whether in one transaction or a series of transactions, of all or substantially all of the equity securities of Phoenix Equity (including by way of merger, consolidation, share exchange, or similar transaction); or |
| • | a sale or disposition, whether in one transaction or a series of transactions, of all or substantially all of the assets of Phoenix Equity and its subsidiaries. |
Assuming a Liquidity Event occurred as of December 31, 2024, the value received by each of our named executive officers in respect of their restricted Class A Units and restricted Class B Units would be:
| Name |
Value of Class A Units for which Forfeiture Restrictions Cease to Apply upon Liquidity Event(1) |
Value of Class B Units for which Forfeiture Restrictions Cease to Apply upon Liquidity Event(1) |
||||||
| Adam Ferrari |
— | — | ||||||
| Curtis Allen |
$ | 14,632,029 | $ | 5,364,696 | ||||
| Sean Goodnight |
$ | 2,985,992 | $ | 11,757,238 | ||||
| Brandon Allen |
$ | 2,985,992 | $ | 9,862,078 | ||||
| Lindsey Wilson |
$ | 1,492,996 | $ | 8,540,204 | ||||
| (1) | Market value based on $55.74, the fair market value of the Class A Units and Class B Units of Phoenix Equity on December 31, 2024, based on an independent third-party valuation. |
Manager Compensation
Our company is managed indirectly by Adam Ferrari, our Chief Executive Officer, who was employed by us during the year ended December 31, 2024, and did not receive any additional compensation from us for his service as a manager of Phoenix Equity or our company.
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CERTAIN RELATIONSHIPS AND RELATED-PARTY TRANSACTIONS
In addition to the compensation arrangements, including employment, termination of employment, and change in control and indemnification arrangements, discussed in the section titled “Compensation Discussion and Analysis,” the following is a description of each transaction since January 1, 2022 and each currently proposed transaction in which:
| • | we or any subsidiaries have been or will be a participant; |
| • | the amount involved exceeded or exceeds $120,000; and |
| • | any of our executive officers, or beneficial owners of more than 5% of our capital stock had or will have a direct or indirect material interest. |
Second Amended and Restated Limited Liability Company Agreement of Phoenix Energy One, LLC
We are governed by that certain Second Amended and Restated Limited Liability Company Agreement, dated as of January 23, 2025 (as amended, amended and restated, or supplemented from time to time, the “Phoenix Energy LLCA”), between ourselves and our sole member, Phoenix Equity.
The Phoenix Energy LLCA provides that Phoenix Equity is the sole member of the Issuer, entitled to 100% of any distributions made by the Issuer. The management of the Issuer is exclusively vested in Phoenix Equity and, as such, Phoenix Equity directs our business and operations, including appointment and compensation of our officers. The Phoenix Energy LLCA further provides that the managers of Phoenix Equity shall be deemed to be “managers” of the Issuer for all purposes under the DLLCA. LJC controls Phoenix Equity and, therefore, indirectly has control over the Issuer’s management. Daniel Ferrari and Charlene Ferrari each own 50% of the voting membership interests in, and are the managers of, LJC. Adam Ferrari, our Chief Executive Officer, the manager of Phoenix Equity, and the son of Daniel and Charlene Ferrari, owns 100% of the economic interests in LJC, but has no voting or managerial interest in LJC. This summary is qualified in its entirety by the full text of the Phoenix Energy LLCA, which is included as an exhibit to the registration statement of which this prospectus forms a part.
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Consulting Agreement
We and Adam Ferrari, our Chief Executive Officer, entered into a consulting agreement (the “Consulting Agreement”) in November 2021 pursuant to which Mr. Ferrari provided us with petroleum engineering consulting services. The Consulting Agreement terminated commencing with Mr. Ferrari’s employment as our Vice President of Engineering in April 2023. We paid Mr. Ferrari $323,000 in consulting fees in 2022 pursuant to the Consulting Agreement.
Investments in Company Debt
From time to time certain of our managers or executive officers and their respective family members may purchase and hold our debt securities, including the Notes.
The following table sets forth, for the period from January 1, 2022 to March 31, 2025, investments made by such persons in our debt securities where such investments exceeded $120,000:
| Related Party(1) |
Debt Security |
Interest Rate | Principal Amount During Period(2) |
Principal Amount Outstanding as of March 31, 2025 |
Principal Paid During Period(2) |
Interest Paid During Period |
||||||||||||||
| Adam Ferrari |
July 2022 506(c) Bonds | 8.0% - 11.0% | $ | 455,000 | $ | — | $ | 455,000 | $ | 16,433 | ||||||||||
| Adam Ferrari |
December 2022 506(c) Bonds | 9.0% - 12.0% | $ | 1,143,000 | $ | 481,000 | $ | 662,000 | $ | 177,215 | ||||||||||
| Adam Ferrari |
August 2023 506(c) Bonds | 10.0% - 14.0% | $ | 3,347,000 | $ | 1,784,000 | $ | 1,563,000 | $ | 339,930 | ||||||||||
| Adam Ferrari |
Reg A Bonds | 9.0% | $ | 200,000 | $ | — | $ | 200,000 | $ | 14,963 | ||||||||||
| Curtis Allen |
December 2022 506(c) Bonds | 12.0% | $ | 386,000 | $ | — | $ | 386,000 | $ | 28,668 | ||||||||||
| Curtis Allen |
August 2023 506(c) Bonds | 13.0% - 14.0% | $ | 3,026,000 | $ | 1,036,000 | $ | 1,990,000 | $ | 194,370 | ||||||||||
| Curtis Allen |
Reg A Bonds | 9.0% | $ | 14,000 | $ | — | $ | 14,000 | $ | 1,928 | ||||||||||
| Lindsey Wilson |
December 2022 506(c) Bonds | 9.0% | $ | 50,000 | $ | — | $ | 50,000 | $ | 4,690 | ||||||||||
| Lindsey Wilson |
August 2023 506(c) Bonds | 13.0% | $ | 184,000 | $ | 184,000 | $ | — | $ | 20,179 | ||||||||||
| Justin Arn |
December 2022 506(c) Bonds | 10.0% | $ | 50,000 | $ | — | $ | 50,000 | $ | 5,236 | ||||||||||
| Justin Arn |
August 2023 506(c) Bonds | 13.0% | $ | 186,000 | $ | 186,000 | $ | — | $ | 26,609 | ||||||||||
| Justin Arn |
Reg A Bonds | 9.0% | $ | 2,000 | $ | — | $ | 2,000 | $ | 540 | ||||||||||
| David Wheeler |
August 2023 506(c) Bonds | 12.0% | $ | 179,000 | $ | 179,000 | $ | — | $ | 7,268 | ||||||||||
| (1) | Includes any debt securities known by such person to be held by any child, stepchild, parent, step-parent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law of such person and any person (other than a tenant or employee) sharing the household of such person. |
| (2) | Reflects the largest aggregate amount of principal of such debt securities outstanding and paid during the period from January 1, 2022 to March 31, 2025. |
Discretionary Payments
For the year ended December 31, 2024, we paid interest expense of less than $0.2 million to a financial institution on behalf of LJC related to a certain financing agreement between LJC and this financial institution. Such payments were discretionary in nature, and we are under no obligation to continue to make such payments on behalf of LJC. For the year ending December 31, 2025, we expect to make additional payments up to an amount equal to approximately $0.1 million.
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Indemnification of Directors and Officers
We intend to enter into indemnification agreements with each of our managers and executive officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under the DLLCA against expenses, losses, and liabilities that may arise in connection with actual or threatened proceedings in which they are involved by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified.
The Phoenix Energy LLCA provides that we will indemnify our members and executive officers, to the fullest extent permitted by law, from any liability, loss, or damage incurred by any member or officer or by reason of any act performed or omitted to be performed by any member or officer in connection with our business, subject to certain exceptions.
Related Persons Transaction Policy
Prior to the commencement of this offering, we expect to adopt a written policy on transactions with related persons, which we refer to as our “related person policy.” We expect that our related person policy will require that all “related persons” (as defined in paragraph (a) of Item 404 of Regulation S-K) must promptly disclose to our chief financial officer any “related person transaction” (defined as any transaction that is anticipated would be reportable by us under Item 404(a) of Regulation S-K in which we were or are to be a participant and the amount involved exceeds $120,000 and in which any related person had or will have a direct or indirect material interest) and all material facts with respect thereto. Our chief legal officer or chief financial officer will communicate that information to our manager. We expect that our related person policy will provide that no related person transaction will be executed without the approval or ratification of our manager. We do not expect that our related person policy will specify the standards to be applied by our manager in determining whether or not to approve or ratify a related person transaction, and we accordingly anticipate that these determinations will be made in accordance with the principles of Delaware law generally applicable to managers of a Delaware limited liability company.
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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
We are a wholly owned subsidiary of Phoenix Equity. LJC controls Phoenix Equity and, therefore, indirectly has control over our management. The table below sets forth, as of the date of this prospectus, information regarding the beneficial ownership of Phoenix Equity’s outstanding membership interests by: (1) each person who is known to us to be the beneficial owner of 5% or more of Phoenix Equity’s outstanding membership interests; (2) each of our named executive officers and managers; and (3) all of our executive officers and managers as a group. The SEC has defined “beneficial ownership” of a security to mean the possession, directly or indirectly, of sole or shared voting power and/or investment power over such security, including options and warrants that are currently exercisable or exercisable within 60 days.
Unless otherwise indicated, we believe that all persons named in the table below have sole voting and investment power with respect to the voting securities beneficially owned by them. Unless otherwise noted, the business address of the persons listed in the table below is 18575 Jamboree Road, Suite 830 Irvine, California 92612.
| Name of Beneficial Holder |
Class A Units(1) |
Class A Unit Percentage |
Class B Units(2) |
Class B Unit Percentage |
||||||||||||
| 5% Holders |
||||||||||||||||
| Lion of Judah Capital, LLC(3) |
1,100,000 | 55.0 | % | 4,186,100 | 59.8 | % | ||||||||||
| Managers and Named Executive Officers |
||||||||||||||||
| Adam Ferrari(4) |
— | — | % | — | — | % | ||||||||||
| Curtis Allen |
525,010 | 26.3 | % | 192,490 | 2.7 | % | ||||||||||
| Sean Goodnight |
53,570 | 2.7 | % | 210,930 | 3.0 | % | ||||||||||
| Lindsey Wilson |
53,570 | 2.7 | % | 306,430 | 4.4 | % | ||||||||||
| Brandon Allen |
53,570 | 2.7 | % | 176,930 | 2.5 | % | ||||||||||
| All executive officers and managers as a group (seven individuals) |
739,290 | 40.0 | % | 1,222,210 | 17.5 | % | ||||||||||
| (1) | Class A Units are entitled to vote on any matter involving Phoenix Equity or its subsidiaries. |
| (2) | Class B Units are not entitled to vote on any matter involving Phoenix Equity or its subsidiaries. |
| (3) | Daniel Ferrari and Charlene Ferrari each own 50% of the voting membership interests in, and are the managers of, LJC. Their address is 1983 Water Chase Drive, New Lenox, Illinois 60451. Adam Ferrari, the son of Daniel and Charlene Ferrari, owns 100% of the economic interests in LJC, but has no voting or managerial interest in LJC and, therefore, is not a beneficial owner of our membership interests by virtue of his economic interest ownership in LJC. |
| (4) | Pursuant to the terms of the Phoenix Energy LLCA, because Adam Ferrari is the manager of Phoenix Equity, he is deemed for all purposes of the DLLCA to be the manager of the Issuer. |
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General
In this description, (i) the terms “we,” “us,” and “our” each refer to Phoenix Energy One, LLC, a Delaware limited liability company, and its consolidated Subsidiaries and (ii) the term “Issuer” refers to Phoenix Energy One, LLC, a Delaware limited liability company, and not any of its Subsidiaries. For purposes of this description, the Senior Subordinated Notes to be issued under the Indenture described below are referred to as the “Notes.” The Notes will be issued pursuant to an indenture, to be dated on or around the date of this prospectus (as amended and supplemented from time to time, the “Indenture”), between the Issuer and UMB Bank, N.A., as trustee (in such capacity, the “Trustee”). A copy of the form of Indenture is filed as an exhibit to the registration statement of which this prospectus forms a part. See “Where You Can Find Additional Information” for more information about where you can obtain copies of the Indenture and any supplemental indentures thereto. You may also review the Indenture (and any supplemental indentures) at the Trustee’s corporate trust office at 928 Grand Blvd., 12th Floor, Kansas City, Missouri 64106.
The following summary of certain provisions of the Indenture and the Notes does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of the Indenture and the Notes. The terms of the Notes include those stated in the Indenture and those made part of the Indenture by reference to the U.S. Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”). Capitalized terms used in this “Description of Notes” section and not otherwise defined have the meanings set forth in the section “—Certain Definitions.”
The Issuer is offering up to $750,000,000 in aggregate principal amount of Notes on a continuous basis pursuant to Rule 415 under the Securities Act. The Notes will vote as a single class (except as otherwise described under “—Amendments and Waivers”).
If a holder has given wire transfer instructions to the Issuer or the paying agent, the paying agent will distribute the payments received of principal of, and, if applicable, interest and premium, if any, on that holder’s Notes in accordance with those instructions. Distribution of all other payments on the Notes will be made at the office or agency of the paying agent unless the Issuer elects to make interest payments through the paying agent by check mailed to the holders at their addresses set forth in the register of holders.
The registered holder of a Note will be treated as the owner of it for all purposes. Only registered holders will have rights under the Indenture.
The Notes will be issued only in fully registered form, without coupons, in minimum denominations of $1,000 and any integral multiple of $1,000 in excess thereof.
The net proceeds of this offering of the Notes will be used by the Issuer as described in this prospectus under “Use of Proceeds.”
The initial minimum investment amount per holder will be $5,000 (the “Minimum Purchase Amount”). From time to time, we may, however, accept investments of less than the Minimum Purchase Amount or increase or decrease the Minimum Purchase Amount. There is no aggregate minimum purchase amount of Notes we are seeking to offer. We have the right to reject any investment, in whole or in part, for any reason. Investors will be required to satisfy the suitability requirements described in this prospectus in order to purchase Notes. The method for submitting subscriptions and a more detailed description of the offering process are included in “Plan of Distribution—Offering Process” beginning on page 148 of this prospectus.
Ranking
The Notes will be the Issuer’s senior subordinated unsecured obligations and will:
| • | rank contractually senior in right of payment to all of the Issuer’s existing and future Indebtedness that is contractually subordinated to the Notes, including the Subordinated Reg D Bonds; |
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| • | without giving effect to collateral arrangements, rank equally in right of payment with all of the Issuer’s existing and future senior Indebtedness (other than Senior Debt); |
| • | be contractually subordinated to any Senior Debt, including Indebtedness under the Fortress Credit Agreement, the Adamantium Debt, and the Senior Reg D/Reg A Bonds; |
| • | be effectively subordinated to any of the Issuer’s existing or future secured Indebtedness and other Obligations, including under the Fortress Credit Agreement and the Adamantium Loan Agreement, to the extent of the value of the assets securing such Indebtedness; and |
| • | be structurally subordinated to all of the existing and future liabilities (including trade payables) and preferred equity of each of the Issuer’s Subsidiaries, including Adamantium Capital LLC, a Delaware limited liability company and a direct wholly owned subsidiary of the Issuer (“Adamantium”). |
The Notes will not be guaranteed by any of our Subsidiaries or Affiliates or any other Person. See “Risk Factors—Risks Related to the Notes and this Offering—The Notes are the Issuer’s obligations alone, and will be structurally subordinated to all obligations of the Issuer’s existing and future subsidiaries.” The Issuer is a holding company with limited direct operations. Substantially all of the operations of the Issuer are conducted through its Subsidiaries. As a result, the Issuer is dependent upon dividends and other payments from its Subsidiaries to generate the funds necessary to meet its outstanding Indebtedness service and other obligations, including with respect to the Notes, and such dividends and other payments may be restricted by law or the instruments governing our Indebtedness. The Issuer’s Subsidiaries may not generate sufficient cash from operations to enable it to make principal and interest payments on our Indebtedness, including the Notes. Claims of creditors of such Subsidiaries (including trade creditors) and claims of preferred stockholders (if any) of such Subsidiaries generally will have priority with respect to the assets and earnings of such Subsidiaries over the claims of creditors of the Issuer, including holders of Notes. The Notes, therefore, will be structurally subordinated to claims of creditors (including trade creditors) and preferred stockholders (if any) of the Issuer’s Subsidiaries. See “Risk Factors—Risks Related to the Notes and this Offering—The Notes are the Issuer’s obligations alone, and will be structurally subordinated to all obligations of the Issuer’s existing and future subsidiaries.”
As of March 31, 2025, after giving effect to the borrowing of an additional $25.0 million under the Fortress Credit Agreement in April 2025, we had approximately $1,109.4 million of Indebtedness outstanding, including $438.0 million of secured Indebtedness outstanding, consisting of (i) $275.0 million aggregate principal amount outstanding under that certain Amended and Restated Senior Secured Credit Agreement (as the same may be amended and supplemented from time to time, the “Fortress Credit Agreement”) with PhoenixOp, as borrower, each of the lenders from time to time party thereto, and Fortress Credit Corp., as administrative agent for the lenders, which consists of a $100.0 million term loan borrowed in full on August 12, 2024 and a $35.0 million delayed draw term loan facility, which was fully drawn in October 2024, a $115.0 million term loan borrowed in full on December 18, 2024, and a $25.0 million term loan facility, borrowed in full on April 16, 2025, and (ii) (A) $163.0 million aggregate principal amount outstanding under that certain Loan Agreement, dated as of September 14, 2023, by and among the Issuer and PhoenixOp, as borrowers, and Adamantium, as lender (as the same may be amended and supplemented from time to time, the “Adamantium Loan Agreement”), which provides for up to $407.0 million in aggregate principal amount of borrowings in one or more advances and is secured by mortgages on certain of our properties, which mortgages are junior to the security interest of the Fortress Credit Agreement and other existing and future senior secured Indebtedness, and (B) without duplication, $7.0 million aggregate principal amount outstanding under the Adamantium Secured Note, which initially matures in November 2031, has an interest rate of 16.5% per annum, and is secured by Adamantium’s rights under the Adamantium Loan Agreement (as the same may be amended and supplemented from time to time, the “Adamantium Secured Note”). Borrowings under the Adamantium Loan Agreement correspond to the $7.0 million issued under the Adamantium Secured Note and the receipt by Adamantium of proceeds from any Adamantium Bonds issued. The Fortress Credit Agreement also provides for an $8.5 million tranche of loans that represents a contingent principal obligation that is only due and payable (together with accrued interest thereon) upon certain conditions occurring, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing by the obligors thereunder. All obligations under the Fortress Credit Agreement are secured on a first-lien priority basis, subject to certain exceptions and excluded assets, by security interests in, and mortgages on, substantially all personal property and owned real property of Phoenix Equity and its Subsidiaries. The Fortress Credit Agreement, the Adamantium Loan Agreement, and the Adamantium Secured Note will constitute Senior Debt and will rank contractually senior to the Notes. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Adamantium Debt” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement” for more information regarding the Adamantium Loan Agreement and the Fortress Credit Agreement, respectively.
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As of March 31, 2025, we had $156.0 million aggregate principal amount outstanding of unsecured bonds offered and sold by Adamantium pursuant to an offering under Rule 506(c) of Regulation D that commenced in September 2023 with maturity dates ranging from five to eleven years from the issue date and interest rates ranging from 13.0% to 16.0% per annum (the “Adamantium Bonds” and, together with the Adamantium Secured Note, the “Adamantium Securities”; the Adamantium Securities, together with the Adamantium Loan Agreement, the “Adamantium Debt”). The Adamantium Bonds and the Adamantium Secured Note will be structurally senior to the Notes to the extent of the value of Adamantium’s assets, including the collateral securing the Adamantium Loan Agreement. Adamantium may, but is not guaranteed to, issue $400.0 million in aggregate principal amount of Adamantium Bonds to fund advances to the Issuer and PhoenixOp pursuant to the Adamantium Loan Agreement. The Adamantium Bonds will also constitute Senior Debt and will rank contractually senior to the Notes. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Adamantium Debt” for more information regarding the Adamantium Bonds.
As of March 31, 2025, the Issuer had $671.2 million aggregate principal amount outstanding of bonds issued pursuant to Regulation D or Regulation A, consisting of: (i) $0.9 million aggregate principal amount outstanding of unsecured bonds offered and sold pursuant to an offering under Rule 506(b) of Regulation D that commenced in July 2020 and terminated in September 2021, with initial maturity dates ranging from one to four years from the issue date and an interest rate of 5.0% per annum (the “2020 506(b) Bonds”); (ii) $1.4 million aggregate principal amount outstanding of unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in October 2020 and terminated in July 2022, with maturity dates ranging from one to four years from the issue date and interest rates ranging from 13.0% to 15.0% per annum (the “2020 506(c) Bonds”); (iii) $10.1 million aggregate principal amount outstanding of unsecured bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in July 2022 and terminated in December 2022, with a maturity date of five years from the issue date and an interest rate of 11.0% per annum (the “July 2022 506(c) Bonds” and, together with the 2020 506(b) Bonds and the 2020 506(c) Bonds, the “Senior Reg D Bonds”); (iv) $65.9 million aggregate principal amount outstanding of Series AAA through Series D-1 Bonds offered and sold pursuant to an offering under Rule 506(c) of Regulation D that commenced in December 2022 and terminated in August 2023, with maturity dates ranging from nine months to seven years from the issue date and interest rates ranging from 8.0% to 12.0% per annum (the “December 2022 506(c) Bonds”); (v) $493.3 million aggregate principal amount outstanding of Series U through Series JJ-1 Bonds offered pursuant to an offering under Rule 506(c) of Regulation D that commenced in August 2023 and are being offered on a continuous basis, with maturity dates ranging from one to eleven years from the issue date and interest rates ranging from 9.0% to 14.0% per annum (the “August 2023 506(c) Bonds” and, together with the December 2022 506(c) Bonds, the “Subordinated Reg D Bonds” and, together with the Senior Reg D Bonds, the “Reg D Bonds”); and (v) $99.6 million aggregate principal amount outstanding of unsecured bonds offered and sold to date pursuant to an offering under Regulation A, which commenced in December 2021 and are being offered on a continuous basis, with a term of three years and an interest rate of 9.0% per annum (the “Reg A Bonds” and, collectively with the Reg D Bonds, the “Reg D/Reg A Bonds”). The Reg D/Reg A Bonds that are not Subordinated Reg D Bonds (the “Senior Reg D/Reg A Bonds”) will constitute Senior Debt and will be contractually senior to the Notes. The Subordinated Reg D Bonds are contractually subordinated to the Senior Reg D/Reg A Bonds and will be contractually subordinated to the Notes.
As indicated above and as discussed in detail below under the caption “—Subordination,” payments on the Notes may be subordinated to the payment of Senior Debt. The Indenture will not restrict our ability to incur additional Indebtedness, including additional Senior Debt, secured Indebtedness, or other Indebtedness that may rank effectively equal with, or senior to, the Notes. See “Risk Factors—Risks Related to the Notes and this Offering—Your right to receive payment under the Notes is contractually subordinated to Senior Debt” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness.”
Subordination
The payment of principal of and interest, if any, on the Notes will be subordinated to the prior payment in full of all Senior Debt, including Senior Debt created, incurred, assumed, or guaranteed after the date of the Indenture. As of March 31, 2025, after giving effect to the borrowing of an additional $25.0 million under the Fortress Credit Agreement in April 2025, we had approximately $550.2 million of indebtedness that will rank contractually senior to the Notes.
“Senior Debt” will be defined in the Indenture as:
| (1) | all Indebtedness of the Issuer or any of its Subsidiaries outstanding under Credit Facilities, all Swap Contracts, and all Treasury Management Arrangements; |
| (2) | any other Indebtedness of the Issuer or any Subsidiary or Affiliate thereof that the Issuer expressly determines is senior to the Notes; and |
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| (3) | all Obligations with respect to the items listed in the preceding clauses (1) and (2). |
Notwithstanding anything to the contrary in the preceding, Senior Debt will not include:
| (1) | any liability for federal, state, local, or other taxes owed or owing by the Issuer or any of its Subsidiaries or Affiliates; |
| (2) | any trade payables; or |
| (3) | Indebtedness that is classified as non-recourse in accordance with GAAP or any unsecured claim arising in respect thereof by reason of the application of Section 1111(b)(1) of the Bankruptcy Code. |
The holders of Senior Debt will be entitled to receive payment in full of all Obligations due in respect of such Senior Debt (including interest after the commencement of any bankruptcy proceeding at the rate specified in the applicable Senior Debt), before the holders of Notes will be entitled to receive any payment with respect to the Notes (except that holders of Notes may receive and retain Permitted Junior Securities and payments made from any of the trusts created pursuant to the provisions described below under “—Satisfaction and Discharge” and “—Defeasance”), in the event of any distribution to creditors of the Issuer in:
| (1) | a liquidation or dissolution of the Issuer; |
| (2) | a bankruptcy, reorganization, insolvency, receivership, or similar proceeding relating to the Issuer or its property; |
| (3) | an assignment for the benefit of creditors; or |
| (4) | any marshaling of the Issuer’s assets and liabilities. |
The Issuer also may not make any payment or distribution to the Trustee or any holder in respect of Obligations with respect of the Notes and may not acquire from the Trustee or any holder any Notes for cash or property if:
| (1) | a payment default on Senior Debt occurs and is continuing; or |
| (2) | any other default occurs and is continuing on any series of Senior Debt that permits holders of that series of Senior Debt to accelerate its Stated Maturity and the Trustee receives a notice of such default (a “Payment Blockage Notice”) from the Issuer or the holders of any Senior Debt. |
The Issuer may and will resume payments on and distributions in respect of the Notes and may acquire them beginning on the date on which such default is cured or waived; provided that the Indenture otherwise permits such payment, distribution, or acquisition at the time of such payment, distribution, or acquisition.
If the Trustee or any holder of the Notes receives any payment of any Obligations with respect to the Notes when:
| (1) | the payment is prohibited by these subordination provisions; and |
| (2) | the Trustee or the holder has actual knowledge that the payment is prohibited; |
the Trustee or the holder, as the case may be, will hold the payment in trust for the benefit of the holders of Senior Debt. Upon the proper written request of the holders of Senior Debt, the Trustee or the holder, as the case may be, will deliver the amounts in trust to the holders of Senior Debt or their proper representative.
So long as any Senior Debt remains outstanding, neither the Trustee nor the holders of Notes shall, without prior written consent of the holders of such Senior Debt:
| (1) | exercise or seek to exercise any right or remedy with respect to a Default or an Event of Default, including any collection or enforcement right or remedy; |
| (2) | institute any action or proceeding against the Issuer or any of its assets, including, without limitation, any possession, sale, or foreclosure action or proceeding; or |
| (3) | contest, protest, or object to any enforcement proceeding or other action commenced under such Senior Debt; |
in each case, for a period of 90 days after delivery of notice of an Event of Default to the holders of such Senior Debt (the “Standstill Period”). The Trustee and the holders shall only be permitted to commence such enforcement proceedings upon the receipt of written consent from the holders of such Senior Debt or upon the expiration of the Standstill Period.
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As a result of the subordination provisions described above, in the event of a bankruptcy, liquidation, reorganization, or similar proceeding relating to the Issuer or its property, holders of Notes may recover less ratably than creditors of the Issuer who are holders of Senior Debt. As a result of the obligation to deliver amounts received in trust to holders of Senior Debt, holders of Notes may recover less ratably than trade creditors of the Issuer. See “Risk Factors—Risks Related to the Notes and this Offering—Your right to receive payment under the Notes is contractually subordinated to Senior Debt.”
Terms of the Notes
The Notes offered hereby will mature three, five, seven, and/or eleven years from the date of initial issuance of such Notes, in the aggregate principal amounts per maturity and interest payment method set forth in the table below. Interest on the Notes will be payable to holders of record of the Notes monthly in arrears on the tenth day of each month or, if such day is not a Business Day, the following Business Day. Interest on the Notes will accrue from and including the date of initial issuance. We will pay interest on the Notes either in cash (such Notes, “Cash Interest Notes”) or by adding such interest to the then-outstanding principal amount of the Notes (such Notes, “Compound Interest Notes”). Interest will accrue on the Notes on the basis of a 360-day year consisting of twelve 30-day months at the rates set forth in the table below for each maturity and interest payment method.
An available maturity, interest payment method, and related interest rate will be selected by you when you make your investment. The maturities, interest payment methods, interest rates, and aggregate principal amounts of the Notes offered hereby are set forth in the table below:
| Maturity |
Interest Payment Method |
Interest Rate | Aggregate Principal Amount | |||||||
| 3 Years |
Cash Interest | 9.0% | $ | 140,000,000 | ||||||
| 3 Years |
Compound Interest | 9.0% | $ | 110,000,000 | ||||||
| 5 Years |
Cash Interest | 10.0% | $ | 40,000,000 | ||||||
| 5 Years |
Compound Interest | 10.0% | $ | 40,000,000 | ||||||
| 7 Years |
Cash Interest | 11.0% | $ | 30,000,000 | ||||||
| 7 Years |
Compound Interest | 11.0% | $ | 30,000,000 | ||||||
| 11 Years |
Cash Interest | 12.0% | $ | 170,000,000 | ||||||
| 11 Years |
Compound Interest | 12.0% | $ | 190,000,000 | ||||||
We will notify each holder no less than 30 and no more than 60 days prior to maturity of such holder’s Notes of the pending maturity, and such holder will be required to provide us with confirmation of the account details for payment of amounts owed at maturity. We will not be required to make such payment at maturity unless and until we receive such confirmation to our satisfaction (any failure to provide confirmation of account details, an “Account Confirmation Failure”). If an Account Confirmation Failure occurs and we elect not to make the required payment at maturity of such Notes, no Default or Event of Default shall occur or be deemed to occur as a result thereof, interest will cease to accrue on such Notes on the Stated Maturity of such Notes, and we will set aside an amount sufficient to pay all amounts due at the Stated Maturity of such Notes for one year (or such longer period as required by relevant state escheat laws). Following the end of such one-year period following the Stated Maturity of such Notes while an Account Confirmation Failure persists, we will no longer be required to make such payment and the relevant holder shall have forfeited such holder’s rights to payment of such amounts.
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Paying Agent and Registrar for the Notes
The Issuer will maintain a paying agent and registrar for the Notes in the United States. The Issuer will initially act as paying agent and registrar for the Notes. The Issuer may change the paying agent or registrar under the Indenture without prior notice to the holders, and any of the Issuer’s Subsidiaries or Affiliates may also act as paying agent or registrar in the future.
Upon written request from the Issuer, at any time when the Issuer is not the registrar, the registrar shall provide the Issuer with a copy of the register to enable the Issuer to maintain a register of the Notes at its registered office.
Optional Redemption
The Issuer may redeem the Notes, at its option, in whole at any time or in part from time to time, upon notice as described below, at a redemption price equal to the principal amount of such Notes, plus accrued and unpaid interest, if any, to, but excluding, the date of the redemption.
In the case of any partial redemption of the Notes, selection of the Notes for redemption will be made by the Issuer in its sole discretion, in which case the Issuer may determine to redeem some or all of certain Notes with specific maturities, interest payment methods, or interest rates, and may not redeem Notes pro rata. If any Note is to be purchased or redeemed in part only, the notice of purchase or redemption relating to such Note shall state the portion of the principal amount thereof that has been or is to be purchased or redeemed. A new Note in a principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the original Note. On and after the redemption date, interest will cease to accrue on Notes or portions thereof called for redemption so long as, (x) at all times when the Issuer is the paying agent, the Issuer has paid the redemption price to the relevant holders, or (y) at all times when the Issuer is not the paying agent, the Issuer has deposited with the paying agent funds sufficient to pay the principal of and accrued and unpaid interest, if any, on the Notes to be redeemed.
Notices of redemption will be delivered at least five but not more than 60 days before the redemption date to each holder to be redeemed at its registered address or otherwise in accordance with the terms of the Indenture, except that redemption notices may be delivered more than 60 days prior to the redemption date if (a) the notice is issued in connection with a defeasance of the Notes or a satisfaction and discharge of the Indenture or (b) in the case of a redemption that is subject to one or more conditions precedent, the date of redemption is extended as permitted under the Indenture.
Any redemption of the Notes may, at the Issuer’s discretion, be subject to one or more conditions precedent. The redemption date of any redemption that is subject to satisfaction of one or more conditions precedent may, in the Issuer’s discretion, be delayed until such time as any or all such conditions shall be satisfied (or waived by the Issuer in its sole discretion), or such redemption may not occur and any notice with respect to such redemption may be modified or rescinded in the event that any or all such conditions shall not have been satisfied (or waived by the Issuer in its sole discretion) by the redemption date, or by the redemption date so delayed (which may exceed 60 days from the date of the redemption notice in such case). In addition, such notice of redemption may be extended, if such conditions precedent have not been satisfied or waived by the Issuer, by providing notice to the holders.
The Issuer or its Affiliates may at any time and from time to time purchase Notes. Any such purchases may be made through open-market or privately negotiated transactions with third parties or pursuant to one or more tender or exchange offers or otherwise, upon such terms and at such prices, as well as with such consideration, as the Issuer or any such Affiliates may determine.
Mandatory Redemption; Repurchase at the Option of the Holders
Subject to the provisions described above under “—Subordination,” each holder of a Note may request, in whole at any time and in part from time to time, by written notice to the Issuer, that the Issuer redeem such holder’s Notes at a redemption price equal to 95.0% of the principal amount of such Notes, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption; provided that the Issuer will not be required to redeem any Notes at any time when the Issuer or any of its Subsidiaries or Affiliates is prohibited by law or contract from doing so; provided further that the Issuer will not be required to redeem Notes in an amount that exceeds, in any calendar year, 10.0% of the aggregate principal amount of the Notes issued and outstanding as of the first day of the calendar quarter in which such request is made (the “10% Limit”). Each tranche of Reg D/Reg A Bonds (except the 2020 506(b) Bonds and the 2020 506(c) Bonds, which do not have a mandatory redemption right) and Adamantium Securities have similar mandatory redemption rights, and amounts redeemed under such debt will not count towards the 10% Limit under the Notes. Furthermore, the principal amount of any Notes requested for redemption by, and redeemed from, our manager, executive officers, or their respective family members (an “executive redemption request”) during any calendar year will not be included in calculating the 10% Limit with respect to any other holder (a “non-executive redemption request”) for such calendar year; however, such redemptions will be included in calculating the 10% Limit with respect to an executive redemption request. As a result, in no circumstance will an executive redemption request decrease the 10% Limit with respect to a non-executive redemption request, but a non-executive redemption request will decrease the 10% Limit with respect to an executive redemption request. For example, if the 10% Limit at the time of a redemption request is $10.0 million, and an executive redemption request is made for $7.5 million aggregate principal amount of Notes and such Notes are redeemed by the Issuer, the 10% Limit remains at $10.0 million for any non-executive redemption requests; however, the 10% Limit for a subsequent executive redemption request would become $2.5 million. Conversely, if the 10% Limit at the time of a redemption request is $10.0 million, and a non-executive redemption request is made for $7.5 million aggregate principal amount of Notes and such Notes are redeemed by the Issuer, the 10% Limit for a subsequent redemption request, whether an executive redemption request or a non-executive redemption request, would become $2.5 million. Therefore, we may be required to purchase up to 20% of the then-outstanding Notes pursuant to the 10% Limit in any calendar year to the extent that executive redemption requests made prior to any non-executive redemption request reach the 10% Limit in such calendar year and subsequent non-executive redemption requests also reach the 10% Limit in such calendar year.
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If required by the foregoing or otherwise permitted by the Issuer, in its sole discretion, the Issuer will redeem such Notes on a date to be determined by the Issuer that is no earlier than one and no later than 120 days from the date the Issuer receives written notice from the holder.
If the Issuer is prohibited by law or contract (including the terms of our indebtedness) from redeeming Notes, or the 10.0% Limit limits a holder’s ability to have its Notes redeemed, the holder may have to hold its Notes to maturity. Redemption requests for the Notes will be processed in the order they are received by the Issuer without regard to date of issuance, maturity date, interest payment method, or interest rates of the Notes for which redemption has been requested. Except as set out in the preceding sentence with respect to redemption requests for the Notes relative to other redemption requests for the Notes, we intend to process redemption requests for any holder of our debt securities, regardless of which tranche of debt such holder holds, in the order in which such request is received, and do not intend to, prioritize redemption requests under the Reg D/Reg A Bonds or Adamantium Securities over redemption requests under the Notes, and vice versa; however, we are not obligated to do so and may, in the future, determine to honor redemption requests as among the tranches of our debt securities under different criteria, whether prioritizing near-term maturities, higher interest rates, specific interest payment methods, or otherwise. Any such determination will be made in our sole discretion. As a result, redemption requests for the Notes may receive lower priority as compared to redemption requests for our other debt securities. The Issuer’s ability to redeem Notes may also be limited by the Issuer’s then-existing financial resources. We cannot assure you that sufficient funds will be available when necessary to make any required purchases.
The Issuer will not otherwise be required to make any mandatory redemption or sinking fund payments with respect to the Notes. The Issuer will also not be required to offer to purchase any Notes with the proceeds of asset sales, in the event of a change of control, or otherwise. See “Risk Factors—Risks Related to the Notes and this Offering—Your right to receive payment under the Notes is contractually subordinated to Senior Debt” and “Risk Factors—Risks Related to the Notes and this Offering—Holders of Notes will have a limited right to require us to redeem their Notes, and we may not be able to repurchase such Notes when requested.”
Covenants
Set forth below are summaries of certain covenants contained in the Indenture. The terms of the Notes and the Indenture do not otherwise contain financial maintenance covenants or covenants that otherwise limit the ability of the Issuer or any of its Subsidiaries or Affiliates to take actions that may negatively impact your investment, such as incurring Indebtedness; paying dividends or making other distributions in respect of, or repurchasing or redeeming, capital stock; prepaying, redeeming, or repurchasing Indebtedness; issuing preferred stock or similar equity securities; making loans and investments; selling or otherwise disposing of assets; incurring liens; entering into transactions with affiliates; or entering into agreements restricting Subsidiaries’ ability to pay dividends. See “Risk Factors—Risks Related to the Notes and this Offering—The terms of the Indenture and the Notes will not necessarily restrict our ability to take actions that may impair our ability to pay interest on and principal of the Notes.”
Reports and Other Information
The Indenture will provide that so long as any Notes are outstanding, the Issuer will deliver to the Trustee within 15 days after it files them with the SEC copies of the annual reports and of the information, documents, and other reports (or copies of such portions of any of the foregoing as the SEC may by rules and regulations prescribe) that the Issuer is required to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act. The Issuer will also comply with the other provisions of Section 314(a) of the Trust Indenture Act. Reports, information, and documents filed with the SEC via the EDGAR system (or any successor system) will be deemed to be delivered to the Trustee at the time of such filing via EDGAR (or any successor system).
Delivery of reports, information, and documents to the Trustee is for informational purposes only and the Trustee’s receipt of the foregoing will not constitute constructive or actual notice of any information contained therein or determinable from information contained therein, including the Issuer’s compliance with any of the covenants contained in the Indenture (as to which the Trustee is entitled to rely exclusively on Officer’s Certificates).
Consolidation, Merger, and Sale of Assets
The Issuer may not consolidate with or merge with or into, or convey, transfer, or lease all or substantially all of its properties and assets to any Person (a “successor person”) unless:
| • | the Issuer is the surviving entity or the successor person (if other than the Issuer) is a corporation, partnership, trust, or other entity organized and validly existing under the laws of any U.S. domestic jurisdiction and expressly assumes the Issuer’s obligations on the Notes and under the Indenture; and |
| • | immediately after giving effect to the transaction, no Default or Event of Default shall have occurred and be continuing. |
Notwithstanding the above, any of the Issuer’s Subsidiaries or Affiliates may consolidate with, merge into, or transfer all or part of its properties to the Issuer.
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Events of Default
An “Event of Default” will be defined in the Indenture as:
| (1) | a default in the payment of interest on any Note when due, continued for 60 days; |
| (2) | a default in the payment of principal of any Note when due at its Stated Maturity, upon optional redemption, upon acceleration, or otherwise, continued for 60 days; |
| (3) | the failure by the Issuer to comply for 120 days after receipt of written notice referred to below with any of its obligations, covenants, or agreements (other than a Default referred to in clause (1) or (2) above) contained in the Notes or the Indenture; and |
| (4) | certain voluntary or involuntary events of bankruptcy, insolvency, or reorganization of the Issuer. |
Except as described below, the foregoing will constitute Events of Default, whatever the reason for any such Event of Default and whether it is voluntary or involuntary or is effected by operation of law or pursuant to any judgment, decree, or order of any court or any order, rule, or regulation of any administrative or governmental body. The occurrence of certain Defaults or Events of Default or an acceleration under the Indenture may constitute an event of default under certain of our other Indebtedness. See “Risk Factors—Risks Related to the Notes and this Offering—Your right to receive payment under the Notes is contractually subordinated to Senior Debt” and “Risk Factors—Risks Related to Our Indebtedness—The terms of our outstanding indebtedness restrict, and the terms of future indebtedness we may incur may restrict, our current and future operations, particularly our ability to respond to changes in the economy or our industry or to take certain actions, which could harm our long-term interests.”
No Event of Default under clause (1) or (2) of the second preceding paragraph with respect to a particular Note will constitute an Event of Default with respect to any other Notes. A Default under clause (3) of the second preceding paragraph will not constitute an Event of Default until the Trustee or the holders of at least a majority in aggregate principal amount of outstanding Notes notify the Issuer in writing of the Default and such Default is not cured within the time specified in clause (3) of the second preceding paragraph after receipt of such notice. If the Issuer fails because of the provisions set forth above under “—Subordination” to pay the principal of and accrued unpaid interest, if any, on a Note when due, such failure shall not constitute a Default or Event of Default.
Subject to the provisions described above under “—Subordination,” if an Event of Default (other than an Event of Default relating to certain events of bankruptcy, insolvency, or reorganization of the Issuer) occurs and is continuing, then the Trustee or the holders of not less than a majority in aggregate principal amount of the outstanding Notes may, by a notice in writing to the Issuer (and to the Trustee if given by the holders), declare to be due and payable immediately the principal of and accrued and unpaid interest, if any, on all outstanding Notes. Subject to the provisions described above under “—Subordination,” in the case of an Event of Default resulting from certain events of bankruptcy, insolvency, or reorganization of the Issuer, the principal of and accrued and unpaid interest, if any, on all outstanding Notes will become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holder of outstanding Notes. The holders of a majority in aggregate principal amount of the outstanding Notes may, on behalf of the holders of all of the Notes, waive, rescind, cancel, and annul any declaration of an existing or past Default or Event of Default and its consequences under the Indenture and the Notes, including an acceleration, if such waiver, rescission, cancellation, or annulment would not conflict with any judgment or decree (except a continuing Default or Event of Default in the payment of interest on, or the principal of, the Notes (other than such nonpayment of principal or interest that has become due as a result of such acceleration), which may be waived, rescinded, canceled, or annulled by the holder of such Note). Upon any such waiver, rescission, cancellation, or annulment of a Default or Event of Default, any such Default or Event of Default shall cease to exist, and any Event of Default arising from any such Default shall be deemed to have been cured for every purpose of the Indenture; but no such waiver shall extend to any subsequent or other Default or impair any right consequent thereon.
The Indenture will provide that the Trustee may refuse to perform any duty or exercise any of its rights or powers under the Indenture unless the Trustee receives indemnity satisfactory to it against any cost, liability, or expense that might be incurred by it in performing such duty or exercising such right or power. Subject to certain rights of the Trustee and the provisions described above under “—Subordination,” the holders of a majority in aggregate principal amount of the outstanding Notes will have the right to direct the time, method, and place of conducting any proceeding for any remedy available to the Trustee or exercising any trust or power conferred on the Trustee with respect to the Notes.
Subject to the provisions described above under “—Subordination,” no holder of any Note will have any right to institute any proceeding, judicial or otherwise, with respect to the Notes or the Indenture or for the appointment of a receiver or trustee, or for any remedy under the Notes or the Indenture, unless:
| • | that holder has previously given to the Trustee written notice of a continuing Event of Default with respect to the Notes; and |
| • | the holders of not less than a majority in aggregate principal amount of the outstanding Notes have made a written request, and offered indemnity or security satisfactory to the Trustee, to the Trustee to institute the proceeding as trustee, and the |
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| Trustee has not received from the holders of not less than a majority in principal amount of the outstanding Notes a direction inconsistent with that request and has failed to institute the proceeding within 60 days. |
Subject to the other provisions of the Indenture, including the provisions described above under “—Subordination,” the holder of any Note will have an absolute and unconditional right to receive payment of the principal of and any interest on that Note on or after the due dates expressed in that Note and to institute suit for the enforcement of payment.
The Indenture will require the Issuer, within 120 days after the end of its fiscal year, to furnish to the Trustee a statement as to compliance with the Indenture. If a Default or Event of Default occurs and is continuing with respect to the Notes and if a responsible officer of the Trustee has received notice of such Default or Event of Default, the Trustee shall mail to each holder of Notes notice of a Default or Event of Default within 90 days after it occurs or, if later, after a responsible officer of the Trustee has received notice of such Default or Event of Default. The Indenture will provide that the Trustee may withhold notice to the holders of Notes of any Default or Event of Default (except in payment on such holder’s Notes) with respect to such Notes if the Trustee determines in good faith that withholding notice is in the interest of the holders of those Notes. The Issuer will provide the Trustee written notice of any Default or Event of Default within 30 days of any Officer becoming aware of the occurrence of such Default or Event of Default (unless such Default or Event of Default has been cured or waived within such 30-day time period), which notice will describe in reasonable detail the status of such Default or Event of Default and what action the Issuer is taking or proposes to take in respect thereof.
Modification and Waiver
The Issuer and the Trustee may modify, amend, or supplement the Indenture or any Notes without the consent of any holder of any Notes:
| • | to cure any ambiguity, omission, mistake, defect, or inconsistency; |
| • | to conform the text of the Indenture (including any supplemental indenture or other instrument pursuant to which additional Notes are issued) or the Notes to this “Description of Notes” in this prospectus or any provision of a prospectus supplement intended to supplement this “Description of Notes” or, with respect to any additional Notes and any supplemental indenture or other instrument pursuant to which such additional Notes are issued, to the “Description of Notes” relating to the issuance of such additional Notes or any provision of a prospectus supplement intended to supplement such “Description of Notes,” solely to the extent that such “Description of Notes” provides for terms of such additional Notes that differ from the terms of the Notes offered hereby; |
| • | to comply with the covenant in the Indenture described above under the heading “—Covenants—Consolidation, Merger, and Sale of Assets” or to otherwise provide for the assumption by a successor Person of the obligations of the Issuer under the Indenture and the Notes, or to add a co-issuer; |
| • | to provide for uncertificated securities in addition to or in place of certificated securities, or to provide for global Notes; |
| • | to add guarantees with respect to Notes or secure Notes; |
| • | to surrender any of the Issuer’s rights or powers under the Indenture and/or the Notes; |
| • | to add covenants or events of default for the benefit of the holders of Notes; |
| • | to comply with the applicable procedures of any applicable depositary; |
| • | to make any change that does not adversely affect the rights of any holder of Notes in any material respect; |
| • | to provide for the issuance of and establish the form and terms and conditions of Notes as permitted by the Indenture; |
| • | to make any amendment to the provisions of the Indenture relating to the transfer of the Notes as permitted by the Indenture, including, without limitation, to facilitate the issuance and administration of the Notes; |
| • | to effect the appointment of a successor trustee, a collateral agent, or a successor collateral agent with respect to the Notes and to add to or change any of the provisions of the Indenture to provide for or facilitate administration by a successor trustee, a collateral agent, a successor collateral agent, and/or more than one trustee and/or collateral agent; |
| • | to add to, delete from, or revise the conditions, limitations, and restrictions on the authorized amount, terms, or purposes of the issue, authentication, and delivery of the Notes (prior to issuance thereof), in each case, as set forth in the Indenture; or |
| • | to comply with requirements of the SEC in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act. |
The Issuer may also modify and amend the Indenture or any Notes with the consent of the holders of at least a majority in principal amount of the outstanding Notes affected by the modifications or amendments (including, without limitation, consents
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obtained in connection with a purchase of, or tender offer or exchange offer for, the Notes), and any existing or past Default or compliance with any provisions of such documents may be waived with the consent of the holders of at least a majority in aggregate principal amount of the outstanding Notes affected by such waiver (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, any Notes). The Issuer may not make any modification, amendment, or waiver without the consent of the holders of each affected Note then outstanding (including, for the avoidance of doubt, any Notes held by Affiliates) if that modification, amendment, or waiver will (with respect to any Notes held by a non-consenting holder):
| • | reduce the percentage of the aggregate principal amount of Notes whose holders must consent to an amendment, supplement, or waiver; |
| • | reduce the rate or extend the time for payment of interest (including default interest) on any Note; |
| • | reduce the principal of or change the Stated Maturity of any Note; |
| • | waive a Default in the payment of the principal of or interest on any Note (except a rescission of acceleration of the Notes by the holders of at least a majority in aggregate principal amount of the then-outstanding Notes and a waiver of the payment default that resulted from such acceleration); |
| • | make the principal of or interest on any Note payable in currency other than that stated in such Note; or |
| • | make any change to certain provisions of the Indenture relating to, among other things, the right of holders of Notes to receive payment of the principal of and interest on those Notes and to institute suit for the enforcement of any such payment and to waivers or amendments. |
It will not be necessary under the Indenture or the Notes for holders to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. A Note does not cease to be outstanding because the Issuer or any Affiliate of the Issuer holds the Note; provided that, in determining whether the holders of the requisite majority of outstanding Notes have given any request, demand, authorization, direction, notice, consent, or waiver under the Indenture and/or the Notes, Notes owned by the Issuer or any Affiliate of the Issuer shall be disregarded and deemed not to be outstanding if such ownership is actually known by a responsible officer of the Trustee.
No Personal Liability of Directors, Officers, Employees, or Securityholders
None of the past, present, or future managers, managing directors, directors, officers, employees, incorporators, or securityholders of the Issuer or any Subsidiary or Affiliate of the Issuer, as such, will have any liability for any of the Issuer’s obligations under the Notes or the Indenture or for any claim based on, or in respect or by reason of, such obligations or their creation. By accepting a Note, each holder waives and releases all such liability. This waiver and release is part of the consideration for the issue of the Notes. However, this waiver and release may not be effective to waive liabilities under U.S. federal securities laws, and it is the view of the SEC that such a waiver is against public policy.
Transfer
Under the terms of the Indenture, no holder may transfer Notes without the prior written consent of the Issuer, which may be given or rejected in the Issuer’s sole discretion and determined on an ad hoc basis. A holder may request to transfer all or a portion of its Notes by submitting its request in writing to the Issuer no earlier than 10 Business Days and no later than five Business Days prior to the requested transfer date (which date must be a Business Day). Such request must include (i) the name of the holder, (ii) the Note(s) to be transferred, (iii) the identity of the transferee, and (iv) a completed subscription agreement by the transferee in a form satisfactory to the Issuer. The Issuer will use commercially reasonable efforts to respond to any such request prior to the Business Day immediately preceding the requested transfer date. The Issuer may request additional information regarding the transfer, the transferor, and the transferee as it desires in its sole discretion prior to determining whether to approve of the requested transfer. If a transfer of Notes is consented to in writing by the Issuer, a holder may not transfer any Note until the registrar has received, among other things, appropriate endorsements and transfer documents and any taxes and fees required by law or permitted by the Indenture. The Notes will be issued in registered form and the registered holder of a Note will be treated as the owner of such Note for all purposes.
Satisfaction and Discharge
The Indenture, the Notes, and any related guarantees will be discharged and will cease to be of further effect, and any collateral then securing the Notes shall be released (except as to surviving rights of registration of transfer or exchange of Notes and certain rights, indemnities, and immunities of the Trustee, as expressly provided for in the Indenture), as to all outstanding Notes when:
| (1) | either (a) all of the Notes theretofore authenticated and delivered (except lost, stolen, or destroyed Notes that have been replaced or paid and Notes for whose payment money has theretofore been deposited in trust or segregated and held in trust |
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| by the Issuer and thereafter repaid to the Issuer or discharged from such trust) have been delivered to the Trustee for cancellation or (b) all of the Notes not previously delivered to the Trustee for cancellation (i) have become due and payable, (ii) will become due and payable at their Stated Maturity within one year, or (iii) have been called for redemption or are to be called for redemption within one year under arrangements satisfactory to the Trustee for the giving of notice of a full redemption by the Trustee in the name, and at the expense, of the Issuer, and the Issuer has deposited or caused to be deposited with the Trustee (in a manner that is not revocable by the Issuer or any of its Affiliates) money or U.S. Government Obligations in an amount sufficient to pay and discharge the entire Indebtedness on the Notes not theretofore delivered to the Trustee for cancellation, for principal of and interest on the Notes to the date of maturity or redemption, as the case may be, together with irrevocable instructions from the Issuer directing the Trustee to apply such funds to the payment thereof at maturity or redemption, as the case may be; |
| (2) | the Issuer has paid all other sums then due and payable under the Indenture; and |
| (3) | the Issuer has delivered to the Trustee a certificate stating that all conditions precedent under the Indenture relating to the satisfaction and discharge of the Indenture have been complied with. |
Defeasance
Legal Defeasance. The Indenture will provide that the Issuer and any guarantors of the Notes may be discharged from any and all obligations in respect of any or all Notes and related guarantees (subject to certain exceptions) and cure all then-existing Defaults and Events of Default (“legal defeasance”). We will be so discharged upon the irrevocable deposit with the Trustee, in trust, of money and/or U.S. Government Obligations that, through the payment of interest and principal in accordance with their terms, will provide money in an amount sufficient in the opinion of a nationally recognized firm of independent public accountants or investment bank to pay and discharge each installment of principal of and interest on such Notes on the Stated Maturity of those payments in accordance with the terms of the Indenture and those Notes.
This discharge may occur only if, among other things, the Issuer has delivered to the Trustee an opinion of counsel stating that the Issuer has received from, or there has been published by, the U.S. Internal Revenue Service a ruling or, since the date of execution of the Indenture, there has been a change in the applicable U.S. federal income tax law, in either case, to the effect that, and based thereon such opinion shall confirm that, the holders of such Notes will not recognize income, gain, or loss for U.S. federal income tax purposes as a result of the deposit, defeasance, and discharge and will be subject to U.S. federal income tax on the same amounts and in the same manner and at the same times as would have been the case if the deposit, defeasance, and discharge had not occurred. If the Issuer exercises its legal defeasance option, any Liens and guarantees, as they pertain to the Notes, will be released. The Issuer may exercise its legal defeasance option notwithstanding its prior exercise of its covenant defeasance option.
Defeasance of Certain Covenants. The Indenture will provide that, upon compliance with certain conditions:
| • | the Issuer may omit to comply with the covenant described under the heading “—Covenants—Consolidation, Merger, and Sale of Assets” and certain other covenants set forth in the Indenture; |
| • | any omission to comply with those covenants will not constitute a Default or an Event of Default with respect to the Notes (“covenant defeasance”); and |
| • | any Liens and guarantees, as they pertain to the Notes, will be released. |
The conditions include:
| • | depositing with the trustee money and/or U.S. Government Obligations that, through the payment of interest and principal in accordance with their terms, will provide money in an amount sufficient in the opinion of a nationally recognized firm of independent public accountants or investment bank to pay and discharge each installment of principal of and interest on such Notes on the Stated Maturity of those payments in accordance with the terms of the Indenture and such Notes; and |
| • | delivering to the Trustee an opinion of counsel to the effect that the holders of such Notes will not recognize income, gain, or loss for U.S. federal income tax purposes as a result of the deposit and related covenant defeasance and will be subject to U.S. federal income tax on the same amounts and in the same manner and at the same times as would have been the case if the deposit and related covenant defeasance had not occurred. |
Notices
Notices given by publication will be deemed given on the first date on which publication is made and notices given by first-class mail, postage prepaid, will be deemed given five calendar days after mailing; notices personally delivered will be deemed given at the time delivered by hand; notices given by facsimile or email will be deemed given when receipt is acknowledged; and notices given by overnight air courier guaranteeing next day delivery will be deemed given the next Business Day after timely delivery to the courier.
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Concerning the Trustee
UMB Bank, N.A. will be the Trustee under the Indenture.
The Indenture will contain certain limitations on the rights of the Trustee thereunder, should it become a creditor of the Issuer, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The Trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest, it must eliminate such conflict within 90 days, apply to the SEC for permission to continue, or resign.
The Indenture will provide that in case an Event of Default shall occur (which shall not be cured), the Trustee will be required, in the exercise of its power, to use the degree of care of a prudent person in the conduct of such person’s own affairs.
Where the Indenture requires delivery of a certificate in connection with any request or application to the Trustee to take or refrain from taking any action thereunder, the Trustee may, in its sole discretion, waive or amend such requirement.
By their acceptance of the Notes, the holders of the Notes will be deemed to have authorized any collateral agent appointed under the Indenture from time to time to enter into and perform any security documentation.
Governing Law
The Indenture will provide that it and the Notes, including any claim or controversy arising out of or relating thereto, will be governed by and construed in accordance with the laws of the State of New York.
The Indenture will provide that the Issuer, the Trustee, and the holders of the Notes (by their acceptance of the Notes) irrevocably waive, to the fullest extent permitted by applicable law, any and all right to trial by jury in any legal proceeding arising out of or relating to the Indenture, the Notes, or the transactions contemplated thereby.
The Indenture will provide that any legal suit, action, or proceeding arising out of or based upon the Indenture or the transactions contemplated thereby may be instituted in the federal courts of the United States of America located in the City of New York or the courts of the State of New York, in each case, located in the City of New York, and the Issuer, the Trustee, and the holders of the Notes (by their acceptance of the Notes) irrevocably submit to the non-exclusive jurisdiction of such courts in any such suit, action, or proceeding. The Indenture will further provide that service of any process, summons, notice, or document by mail (to the extent allowed under any applicable statute or rule of court) to such party’s address set forth in the Indenture will be effective service of process for any suit, action, or other proceeding brought in any such court. The Indenture will further provide that the Issuer, the Trustee, and the holders of the Notes (by their acceptance of the Notes) irrevocably and unconditionally waive any objection to the laying of venue of any suit, action, or other proceeding in the courts specified above and irrevocably and unconditionally waive and agree not to plead or claim any such suit, action, or other proceeding has been brought in an inconvenient forum.
Certain Definitions
“10% Limit” has the meaning given to it in “—Mandatory Redemption; Repurchase at the Option of the Holders.”
“2020 506(b) Bonds” has the meaning given to it in “—Ranking.”
“2020 506(c) Bonds” has the meaning given to it in “—Ranking.”
“Account Confirmation Failure” has the meaning given to it in “—Terms of the Notes.”
“Adamantium” has the meaning given to it in “—Ranking.”
“Adamantium Bonds” has the meaning given to it in “—Ranking.”
“Adamantium Debt” has the meaning given to it in “—Ranking.”
“Adamantium Loan Agreement” has the meaning given to it in “—Ranking.”
“Adamantium Secured Note” has the meaning given to it in “—Ranking.”
“Adamantium Securities” has the meaning given to it in “—Ranking.”
“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under common control with such specified Person. For the purposes of this definition, “control” (including, with correlative meanings, the terms
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“controlled by” and “under common control with”), as used with respect to any Person, shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities or by agreement or otherwise.
“August 2023 506(c) Bonds” has the meaning given to it in “—Ranking.”
“Bankruptcy Code” means Title 11 of the United States Code, as amended.
“Board of Directors” means as to any Person, the board of directors, board of managers, sole member, managing member, or other governing body of such Person or, if such Person is owned or managed by a single entity or has a general partner, the board of directors, board of managers, sole member, managing member, or other governing body of such entity or general partner, or, in each case, any duly authorized committee thereof, and the term “directors” means members of the Board of Directors.
“Business Day” means a day other than a Saturday, Sunday, or other day on which banking institutions are authorized or required by law or regulation to close in the State of New York or, with respect to any payments to be made under the Indenture, the place of payment.
“Capital Stock” means:
| (1) | in the case of a corporation, corporate stock; |
| (2) | in the case of an association or business entity, any and all shares, interests, participations, rights, or other equivalents (however designated) of corporate stock; |
| (3) | in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and |
| (4) | any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing person, but excluding from all of the foregoing any debt securities convertible into Capital Stock, whether or not such debt securities include any right of participation with Capital Stock. |
“Capitalized Lease Obligation” means, at the time any determination thereof is to be made, the amount of the liability in respect of a capital lease that would at such time be required to be capitalized and reflected as a liability on a balance sheet (excluding the notes thereto) in accordance with GAAP.
“Cash Interest Notes” has the meaning given to it in “—Terms of the Notes.”
“Compound Interest Notes” has the meaning given to it in “—Terms of the Notes.”
“continuing” means, with respect to any Default or Event of Default, that such Default or Event of Default has not been cured or waived.
“covenant defeasance” has the meaning given to it in “—Defeasance.”
“Credit Facilities” means one or more debt facilities (including, without limitation, the Fortress Credit Agreement), indentures, or commercial paper facilities, in each case, with banks or other institutional lenders, accredited investors, or institutional investors providing for revolving credit loans, term loans, term debt, debt securities, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables), or letters of credit, in each case, as amended, restated, modified, renewed, extended, increased, refunded, replaced in any manner (whether upon or after termination or otherwise), or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time.
“December 2022 506(c) Bonds” has the meaning given to it in “—Ranking.”
“Default” means any event which is, or after notice, passage of time, or both would be, an Event of Default.
“Equity Interests” means Capital Stock and all warrants, options, or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).
“Event of Default” has the meaning given to it in “—Events of Default.”
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“Fortress Credit Agreement” has the meaning given to it in “—Ranking.”
“GAAP” means generally accepted accounting principles in the United States of America, as in effect from time to time, including those set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession.
“Indebtedness” means, with respect to any Person, without duplication:
| (1) | the principal of any indebtedness of such Person, whether or not contingent, (a) in respect of borrowed money, (b) evidenced by bonds, notes, debentures, or similar instruments, or letters of credit or bankers’ acceptances (or, without duplication, reimbursement agreements in respect thereof), (c) representing the deferred and unpaid purchase price of any property, (d) in respect of Capitalized Lease Obligations, or (e) representing any Swap Contracts, in each case, if and to the extent that any of the foregoing Indebtedness (other than letters of credit and Swap Contracts) would appear as a liability on a balance sheet (excluding the notes thereto) of such Person prepared in accordance with GAAP; |
| (2) | to the extent not otherwise included, any guarantee by such Person of the Indebtedness of another Person (other than by endorsement of negotiable instruments for collection in the ordinary course of business); and |
| (3) | to the extent not otherwise included, Indebtedness of another Person secured by a Lien on any asset owned by such Person (whether or not such Indebtedness is assumed by such Person). |
“Indenture” has the meaning given to it in “—General.”
“Issuer” has the meaning given to it in “—General.”
“July 2022 506(c) Bonds” has the meaning given to it in “—Ranking.”
“legal defeasance” has the meaning given to it in “—Defeasance.”
“Lien” means, with respect to any asset, any mortgage, lien, pledge, hypothecation, charge, security interest, preference, priority, or encumbrance of any kind in respect of such asset, whether or not filed, recorded, or otherwise perfected under applicable law (including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in, and any filing of or agreement to give any financing statement under the Uniform Commercial Code of any jurisdiction).
“Minimum Purchase Amount” has the meaning given to it in “—General.”
“Notes” has the meaning given to it in “—General.”
“Obligations” means any principal, interest (including any interest, fees, or expenses accruing subsequent to the filing of a petition in an insolvency, liquidation, or similar proceeding at the rate provided for in the documentation with respect thereto, whether or not such interest, fees, or expenses are an allowed claim under applicable state, federal, or foreign law), premium, penalties, fees, expenses, indemnifications, reimbursements (including, without limitation, reimbursement obligations with respect to letters of credit and bankers’ acceptances), damages, and other liabilities payable under the documentation governing any Indebtedness.
“Officer” means, with respect to any Person, the Chairman of the Board of Directors, Chief Executive Officer, Chief Financial Officer, Chief Operating Officer, or President, or any Vice President, Treasurer, Controller, Secretary, or the Assistant Secretary (or any Person serving the equivalent function of any of the foregoing) of such Person (or of any direct or indirect parent, general partner, managing member, or sole member of such Person), or any individual designated as an “Officer” for purposes of the Indenture by the Board of Directors of such Person (or the Board of Directors of any direct or indirect parent, general partner, managing member, or sole member of such Person).
“Officer’s Certificate” means a certificate signed on behalf of the Issuer or any direct or indirect parent of the Issuer by an Officer of the Issuer or such parent entity that meets the requirements set forth in the Indenture.
“Payment Blockage Notice” has the meaning given to it in “—Subordination.”
“Permitted Junior Securities” means:
| (1) | Equity Interests in the Issuer; and |
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| (2) | debt securities that are subordinated to all Senior Debt and any debt securities issued in exchange for Senior Debt to substantially the same extent as, or to a greater extent than, the Notes are subordinated to Senior Debt under the Indenture. |
“Person” means any individual, corporation, company, partnership, limited liability company, joint venture, association, joint stock company, trust, unincorporated organization, government (or any agency or political subdivision thereof), or other entity.
“PhoenixOp” has the meaning given to it in “—Ranking.”
“Reg A Bonds” has the meaning given to it in “—Ranking.”
“Reg D Bonds” has the meaning given to it in “—Ranking.”
“Reg D/Reg A Bonds” has the meaning given to it in “—Ranking.”
“Regulation A” means Regulation A promulgated under the Securities Act.
“Regulation D” means Regulation D promulgated under the Securities Act.
“Securities Act” means the U.S. Securities Act of 1933, as amended, and the rules and regulations of the SEC promulgated thereunder.
“Senior Debt” has the meaning given in “—Subordination.”
“Senior Reg D Bonds” has the meaning given to it in “—Ranking.”
“Senior Reg D/Reg A Bonds” has the meaning given to it in “—Ranking.”
“Standstill Period” has the meaning given to it in “—Subordination.”
“Stated Maturity” means, when used with respect to any Note, the date specified in such Note as the fixed date on which the principal of such Note is due and payable in cash.
“Subordinated Reg D Bonds” has the meaning given to it in “—Ranking.”
“Subsidiary” of any specified Person means: (1) any corporation, association, or other business entity of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers, or trustees thereof is at the time owned or controlled, directly or indirectly, by such person or one or more of the other Subsidiaries of that person or a combination thereof; or (2) any partnership or limited liability company of which (a) more than 50% of the capital accounts, distribution rights, total equity, and voting interests or general and limited partnership interests, as applicable, are owned or controlled, directly or indirectly, by such person or one or more of the other Subsidiaries of that person or a combination thereof, whether in the form of membership, general, special, or limited partnership interests or otherwise, and (b) such person or any Subsidiary of such Person is a controlling general partner or otherwise controls such entity.
“successor person” has the meaning given to it in “—Covenants—Consolidation, Merger, and Sale of Assets.”
“Swap Contract” means (a) any and all rate swap transactions, basis swaps, credit derivative transactions, forward rate transactions, commodity swaps, commodity options, forward commodity contracts, equity or equity index swaps or options, bond or bond price or bond index swaps or options, forward bond or forward bond price or forward bond index transactions, interest rate options, forward foreign exchange transactions, cap transactions, floor transactions, collar transactions, currency swap transactions, cross-currency rate swap transactions, currency options, spot contracts, or any other similar transactions or any combination of any of the foregoing (including any options to enter into any of the foregoing), whether or not any such transaction is governed by or subject to any master agreement, and (b) any and all transactions of any kind, and the related confirmations, which are subject to the terms and conditions of, or governed by, any form of master agreement published by the International Swaps and Derivatives Association, Inc., any International Foreign Exchange Master Agreement, or any other master agreement, including any obligations or liabilities under any such master agreement.
“Treasury Management Arrangement” means any agreement or other arrangement governing the provision of treasury or cash management services, including deposit accounts, overdraft, credit or debit card, funds transfer, automated clearinghouse, zero balance accounts, returned check concentration, controlled disbursement, lockbox, account reconciliation and reporting and trade finance services, and other cash management services.
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“Trust Indenture Act” has the meaning given to it in “—General.”
“Trustee” has the meaning given to it in “—General.”
“U.S. Government Obligations” means securities that are:
| (1) | direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged; or |
| (2) | obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America, the timely payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States of America |
which, in each case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depository receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act) as custodian with respect to any such U.S. Government Obligations or a specific payment of principal of or interest on any such U.S. Government Obligations held by such custodian for the account of the holder of such depository receipt; provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the U.S. Government Obligations or the specific payment of principal of or interest on the U.S. Government Obligations evidenced by such depository receipt.
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CERTAIN MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS
The following discussion is a summary of certain material U.S. federal income tax considerations relevant to the purchase, ownership, and disposition of the Notes issued pursuant to this offering, but does not purport to be a complete analysis of all potential tax effects. The effects of other U.S. federal tax laws, such as estate and gift tax laws, and any applicable state, local, or foreign tax laws are not discussed. This discussion is based on the Code, Treasury Regulations promulgated thereunder, judicial decisions, and published rulings and administrative pronouncements of the IRS, in each case, in effect as of the date hereof. These authorities may change or be subject to differing interpretations. Any such change or differing interpretation may be applied retroactively in a manner that could adversely affect a holder of the Notes. We have not sought and will not seek any rulings from the IRS regarding the matters discussed below. There can be no assurance the IRS or a court will not take a contrary position to that discussed below regarding the tax consequences of the purchase, ownership, and disposition of the Notes.
This discussion is limited to holders who hold the Notes as “capital assets” within the meaning of Section 1221 of the Code (generally, property held for investment). In addition, this discussion is limited to persons purchasing the Notes for cash at original issue and at their original “issue price” within the meaning of Section 1273 of the Code (i.e., the first price at which a substantial amount of the Notes is sold to the public for cash). This discussion does not address all U.S. federal income tax consequences relevant to a holder’s particular circumstances, including the impact of the Medicare contribution tax on net investment income. In addition, it does not address consequences relevant to holders subject to special rules, including, without limitation:
| • | U.S. expatriates and former citizens or long-term residents of the United States; |
| • | persons subject to the alternative minimum tax; |
| • | U.S. Holders (as defined below) whose functional currency is not the U.S. dollar; |
| • | persons holding the Notes as part of a hedge, straddle, or other risk reduction strategy or as part of a conversion transaction or other integrated investment; |
| • | banks, insurance companies, and other financial institutions; |
| • | real estate investment trusts or regulated investment companies; |
| • | brokers, dealers, or traders in securities; |
| • | “controlled foreign corporations,” “passive foreign investment companies,” and corporations that accumulate earnings to avoid U.S. federal income tax; |
| • | S corporations, partnerships, or other entities or arrangements treated as partnerships for U.S. federal income tax purposes (and investors therein); |
| • | tax-exempt organizations or governmental organizations; |
| • | persons deemed to sell the Notes under the constructive sale provisions of the Code; and |
| • | persons subject to special tax accounting rules as a result of any item of gross income with respect to the Notes being taken into account in an applicable financial statement. |
This summary assumes that the Notes are sold to unrelated parties and properly treated as debt for U.S. federal income tax purposes. If an entity treated as a partnership for U.S. federal income tax purposes holds the Notes, the tax treatment of a partner in the partnership will depend on the status of the partner, the activities of the partnership, and certain determinations made at the partner level. Accordingly, partnerships holding the Notes and the partners in such partnerships should consult their tax advisors regarding the U.S. federal income tax consequences to them.
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THIS DISCUSSION IS FOR INFORMATIONAL PURPOSES ONLY AND IS NOT TAX ADVICE. INVESTORS SHOULD CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATIONS AS WELL AS ANY TAX CONSEQUENCES OF THE PURCHASE, OWNERSHIP, AND DISPOSITION OF THE NOTES ARISING UNDER OTHER U.S. FEDERAL TAX LAWS (INCLUDING ESTATE AND GIFT TAX LAWS), UNDER THE LAWS OF ANY STATE, LOCAL, OR NON-U.S. TAXING JURISDICTION OR UNDER ANY APPLICABLE TAX TREATY.
Tax Considerations Applicable to U.S. Holders
Definition of a U.S. Holder
For purposes of this discussion, a “U.S. Holder” is a beneficial owner of a Note that, for U.S. federal income tax purposes, is or is treated as:
| • | an individual who is a citizen or resident of the United States; |
| • | a corporation created or organized under the laws of the United States, any state thereof, or the District of Columbia; |
| • | an estate, the income of which is subject to U.S. federal income tax regardless of its source; or |
| • | a trust that (1) is subject to the primary supervision of a U.S. court and the control of one or more “United States persons” (within the meaning of Section 7701(a)(30) of the Code) or (2) has a valid election in effect to be treated as a United States person for U.S. federal income tax purposes. |
Payments of Qualified Stated Interest
Payments of “qualified stated interest” on a Note generally will be taxable to a U.S. Holder as ordinary income at the time such interest is received or accrued, in accordance with such U.S. Holder’s method of tax accounting for U.S. federal income tax purposes. The term “qualified stated interest” means stated interest that is unconditionally payable in cash or in property (other than debt instruments of the issuer) at least annually at a single fixed rate or, subject to certain conditions, based on one or more interest indices. It is expected, and the following discussion assumes, that stated interest on the Cash Interest Notes (fixed on or before the issuance of such Cash Interest Notes) will be qualified stated interest. However, none of the stated interest on the Compound Interest Notes will be qualified stated interest.
Original Issue Discount
If the issue price (as defined above) of the Cash Interest Notes is less than their principal amount payable at maturity by an amount equal to or greater than a statutorily defined de minimis amount (generally 1/4 of 1% of the Cash Interest Notes’ stated redemption price at maturity multiplied by the number of complete years to maturity from its issue date), the Cash Interest Notes will be treated as being issued with OID in an amount equal to such difference for U.S. federal income tax purposes.
The Compound Interest Notes will be treated as being issued with OID for U.S. federal income tax purposes because stated interest on the Compound Interest Notes will be paid in the form of increase in the principal amount of the Compound Interest Notes. The Compound Interest Notes will be issued with OID in an amount equal to the excess of the sum of all principal and interest payments provided by the Compound Interest Notes over the issue price (as defined above) of the Compound Interest Notes.
U.S. Holders must include OID in gross income (as ordinary income) as it accrues (on a constant yield to maturity basis), in advance of the receipt of cash attributable to that income irrespective of their regular method of accounting. However, U.S. Holders generally will not be required to include separately in income cash payments of previously accrued OID. The amount of OID includible in gross income by a U.S. Holder in any taxable year is the sum of the “daily portions” of OID with respect to the Note for each day during that taxable year on which the U.S. Holder holds the Note. The daily portion is determined by allocating to each day in any “accrual period” a pro rata
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portion of the OID allocable to that accrual period. The OID allocable to any accrual period, subject to the possible adjustments described below, will be an amount equal to the product of the Note’s “adjusted issue price” at the beginning of the accrual period and its yield to maturity (determined on a constant yield method, compounded at the close of each accrual period and properly adjusted for the length of the accrual period) reduced by qualified stated interest paid or accrued for such period. OID allocable to the final accrual period is the difference between the amount payable at maturity and the adjusted issue price at the beginning of the final accrual period. The “adjusted issue price” of a Note as of the beginning of any accrual period is equal to its issue price increased by the accrued OID for each prior accrual period and reduced by any payments previously made on the Note, other than payments of qualified stated interest. The “yield to maturity” of the Notes is the discount rate that, when used in computing the present value (as of the Issue Date) of all principal and interest payments to be made on the Notes, produces an amount equal to the issue price of the Notes.
Payments of stated interest on Compound Interest Notes will not be treated as payments of interest on the Compound Interest Notes for U.S. federal income tax purposes. Instead, any stated interest paid on Compound Interest Notes will be treated together with the Compound Interest Notes as a single note for U.S. federal income tax purposes.
Sale or Other Taxable Disposition
A U.S. Holder will recognize gain or loss on the sale, exchange, redemption, retirement, or other taxable disposition of a Note. The amount of such gain or loss will generally equal the difference between the amount received for the Note in cash or other property valued at fair market value (less amounts attributable to any accrued but unpaid interest, which will be taxable as interest to the extent not previously included in income) and the U.S. Holder’s adjusted tax basis in the Note. A U.S. Holder’s adjusted tax basis in a Note generally will be equal to the amount the U.S. Holder paid for the Note, increased by the amount of any OID previously included in income with respect to the Note and decreased by the amount of any cash payments other than payments of qualified stated interest previously made on the Note. Although not free from doubt, when we pay stated interest on a Compound Interest Note by increasing the principal amount of such Compound Interest Note, a U.S. Holder’s adjusted tax basis in the Compound Interest Note would likely be allocated pro rata to all of the principal amount of the Compound Interest Note including the increased amount. A U.S. Holder’s holding period in such Compound Interest Note would remain identical with respect to all of the principal amount of such Compound Interest Note including the increased amount. Any gain or loss will be capital gain or loss, and will be long-term capital gain or loss if the U.S. Holder has held the Note for more than one year at the time of sale or other taxable disposition. Otherwise, such gain or loss will be short-term capital gain or loss. Long-term capital gains recognized by certain non-corporate U.S. Holders, including individuals, generally will be taxable at a reduced rate. The deductibility of capital losses is subject to limitations.
Information Reporting and Backup Withholding
A U.S. Holder may be subject to information reporting and backup withholding with respect to payments on a Note, accrual of OID on a Note, or proceeds from the sale or other taxable disposition of a Note (including a redemption or retirement of a Note). Certain U.S. Holders are exempt from backup withholding, including corporations and certain tax-exempt organizations. A U.S. Holder will be subject to backup withholding if such holder is not otherwise exempt and:
| • | the holder fails to furnish the holder’s taxpayer identification number, which for an individual is ordinarily his or her social security number; |
| • | the holder furnishes an incorrect taxpayer identification number; |
| • | the applicable withholding agent is notified by the IRS that the holder previously failed to properly report payments of interest or dividends; or |
| • | the holder fails to certify under penalties of perjury that the holder has furnished a correct taxpayer identification number and that the IRS has not notified the holder that the holder is subject to backup withholding. |
Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a U.S. Holder’s U.S. federal income tax liability; provided the required information is timely furnished to the IRS. U.S. Holders should consult their tax advisors regarding their qualification for an exemption from backup withholding and the procedures for obtaining such an exemption.
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Tax Considerations Applicable to Non-U.S. Holders
Definition of a Non-U.S. Holder
For purposes of this discussion, a “Non-U.S. Holder” is a beneficial owner of a Note that is neither a U.S. Holder nor an entity treated as a partnership for U.S. federal income tax purposes.
Interest and OID
Interest paid on a Note to a Non-U.S. Holder (for this purpose, including any OID accrued with respect to a Non-U.S. Holder), in each case, that is not effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States, generally will not be subject to U.S. federal income tax, or withholding tax of 30% (or such lower rate specified by an applicable income tax treaty); provided that:
| • | the Non-U.S. Holder does not, actually or constructively, own 10% or more of our capital or profits; |
| • | the Non-U.S. Holder is not a controlled foreign corporation related to us through actual or constructive stock ownership; and |
| • | either: (1) the Non-U.S. Holder certifies in a statement provided to the applicable withholding agent under penalties of perjury that it is not a United States person and provides its name and address (generally on a properly executed IRS Form W-8BEN or W-8BEN-E (or other applicable documentation)); (2) a securities clearing organization, bank, or other financial institution that holds customers’ securities in the ordinary course of its trade or business and holds the Note on behalf of the Non-U.S. Holder certifies to the applicable withholding agent under penalties of perjury that it, or the financial institution between it and the Non-U.S. Holder, has received from the Non-U.S. Holder such a statement and provides a copy of such statement to the applicable withholding agent; or (3) the Non-U.S. Holder holds its Note directly through a “qualified intermediary” (within the meaning of applicable Treasury Regulations) which has received such a statement from the non-U.S. Holder and certain conditions are satisfied. |
If a Non-U.S. Holder does not satisfy the requirements above, such Non-U.S. Holder may be still entitled to a reduction in or an exemption from withholding on such interest if it qualifies for the benefits of an applicable tax treaty. To claim such entitlement, the Non-U.S. Holder must provide the applicable withholding agent with a properly executed IRS Form W-8BEN or W-8BEN-E (or other applicable documentation) claiming a reduction in or exemption from withholding tax under the benefit of an income tax treaty between the United States and the country in which the Non-U.S. Holder resides or is established.
If interest paid to a Non-U.S. Holder is effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, the Non-U.S. Holder maintains a permanent establishment in the United States to which such interest is attributable), the Non-U.S. Holder will be exempt from the U.S. federal withholding tax described above. To claim the exemption, the Non-U.S. Holder must furnish to the applicable withholding agent a valid IRS Form W-8ECI, certifying that interest paid on a Note is not subject to withholding tax because it is effectively connected with the conduct by the Non-U.S. Holder of a trade or business within the United States.
Any such effectively connected interest generally will be subject to U.S. federal income tax at the regular graduated rates. A Non-U.S. Holder that is a corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on such effectively connected interest, as adjusted for certain items.
The certifications described above must be provided to the applicable withholding agent prior to the payment of interest and must be updated periodically. Non-U.S. Holders that do not timely provide the applicable withholding agent with the required certification, but that qualify for a reduced rate under an applicable income tax treaty, may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS. Non-U.S. Holders should consult their tax advisors regarding their entitlement to benefits under any applicable income tax treaty.
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Sale or Other Taxable Disposition
A Non-U.S. Holder will not be subject to U.S. federal income tax on any gain realized upon the sale, exchange, redemption, retirement, or other taxable disposition of a Note (such amount excludes any amount allocable to accrued and unpaid interest, which generally will be treated as interest and may be subject to the rules discussed above in “—Payments of Interest”) unless:
| • | the gain is effectively connected with the Non-U.S. Holder’s conduct of a trade or business within the United States (and, if required by an applicable income tax treaty, the Non-U.S. Holder maintains a permanent establishment in the United States to which such gain is attributable); or |
| • | the Non-U.S. Holder is a nonresident alien individual present in the United States for 183 days or more during the taxable year of the disposition and certain other requirements are met. |
Gain described in the first bullet point above generally will be subject to U.S. federal income tax on a net income basis at the regular graduated rates. A Non-U.S. Holder that is a foreign corporation also may be subject to a branch profits tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty) on such effectively connected gain, as adjusted for certain items.
Gain described in the second bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate specified by an applicable income tax treaty), which may be offset by U.S. source capital losses of the Non-U.S. Holder (even though the individual is not considered a resident of the United States); provided the Non-U.S. Holder has timely filed U.S. federal income tax returns with respect to such losses.
Non-U.S. Holders should consult their tax advisors regarding any applicable income tax treaties that may provide for different rules.
Information Reporting and Backup Withholding
Payments of interest (including OID) generally will not be subject to backup withholding; provided the applicable withholding agent does not have actual knowledge or reason to know the holder is a United States person and the holder certifies its non-U.S. status as described above under “—Payments of Interest.” However, information returns are required to be filed with the IRS in connection with any interest paid to the Non-U.S. Holder, regardless of whether any tax was actually withheld. In addition, proceeds of the sale or other taxable disposition of a Note (including a retirement or redemption of the Note) within the United States or conducted through certain U.S.-related brokers generally will not be subject to backup withholding or information reporting, if the applicable withholding agent receives the statement described above and does not have actual knowledge or reason to know that such holder is a United States person or the holder otherwise establishes an exemption. Proceeds of a disposition of a Note paid outside the United States and conducted through a non-U.S. office of a non-U.S. broker generally will not be subject to backup withholding or information reporting.
Copies of information returns that are filed with the IRS may also be made available under the provisions of an applicable treaty or agreement to the tax authorities of the country in which the Non-U.S. Holder resides or is established.
Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be allowed as a refund or a credit against a Non-U.S. Holder’s U.S. federal income tax liability; provided the required information is timely furnished to the IRS.
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Additional Withholding Tax on Payments Made to Foreign Accounts
Withholding taxes may be imposed under Sections 1471 to 1474 of the Code (such Sections commonly referred to as the Foreign Account Tax Compliance Act, or “FATCA”) on certain types of payments made to non-U.S. financial institutions and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on payments of interest (or accrual of OID) on, or (subject to the proposed Treasury Regulations discussed below) gross proceeds from the sale or other disposition of, a Note paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code), unless (1) the foreign financial institution undertakes certain diligence and reporting obligations, (2) the non-financial foreign entity either certifies it does not have any “substantial United States owners” (as defined in the Code) or furnishes identifying information regarding each substantial United States owner, or (3) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules. If the payee is a foreign financial institution and is subject to the diligence and reporting requirements in (1) above, it must enter into an agreement with the U.S. Department of the Treasury requiring, among other things, that it undertake to identify accounts held by certain “specified United States persons” or “United States owned foreign entities” (each as defined in the Code), annually report certain information about such accounts, and withhold 30% on certain payments to non-compliant foreign financial institutions and certain other account holders. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules.
Under the applicable Treasury Regulations and administrative guidance, withholding under FATCA generally applies to payments of interest on a Note. While withholding under FATCA would have applied also to payments of gross proceeds from the sale or other disposition of a Note, certain proposed Treasury Regulations eliminate FATCA withholding on payments of gross proceeds entirely. Taxpayers generally may rely on these proposed Treasury Regulations until final Treasury Regulations are issued.
Prospective investors should consult their tax advisors regarding the potential application of withholding under FATCA to their investment in the Notes.
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The following is a summary of certain considerations associated with the purchase and, in certain instances, holding of the Notes, or any interest therein, by (i) employee benefit plans subject to Title I of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), (ii) plans described in Section 4975 of the Code which are subject to Section 4975 of the Code (including an individual retirement account (“IRA”)) or provisions under other U.S. or non-U.S. federal, state, local, or other laws or regulations that are similar to the fiduciary responsibility or prohibited transaction provisions of Title I of ERISA or Section 4975 of the Code (collectively, “Similar Laws”), and (iii) entities whose underlying assets are considered to include “plan assets” of any such plan, account, or arrangement (each of clauses (i), (ii) and (iii), a “Plan”).
General Fiduciary Matters
ERISA and the Code impose certain duties on persons who are fiduciaries of a Plan subject to Title I of ERISA or Section 4975 of the Code (each, a “Covered Plan”) and prohibit certain transactions involving the assets of a Covered Plan and its fiduciaries or other interested parties. Under ERISA and the Code, any person who exercises discretionary authority or control over the administration of a Covered Plan or the management or disposition of the assets of a Covered Plan, or who renders investment advice for a fee or other compensation to a Covered Plan, is generally considered to be a fiduciary of the Covered Plan.
When considering an investment in the Notes, or any interest therein, with the assets of any Plan, a fiduciary should determine whether the investment is in accordance with the documents and instruments governing the Plan and the applicable provisions of ERISA, the Code, and any Similar Laws relating to a fiduciary’s duties to the Plan including, without limitation, the prudence, diversification, delegation of control, and prohibited transaction provisions of ERISA, the Code, and any applicable Similar Laws.
Plan fiduciaries should consider the fact that neither we nor any of our affiliates (the “Transaction Parties”) is acting, or will act, as a fiduciary to any Plan with respect to the decision to purchase and/or hold the Notes, or any interest therein. The Transaction Parties are not undertaking to provide impartial investment advice or advice based on any particular investment need, or to give advice in a fiduciary capacity, with respect to such decision to purchase the Notes, or any interest therein.
Prohibited Transaction Issues
Section 406 of ERISA and Section 4975 of the Code prohibit Covered Plans from engaging in specified transactions involving plan assets with persons or entities who are “parties in interest,” within the meaning of Section 406 of ERISA, or “disqualified persons,” within the meaning of Section 4975 of the Code, unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Code and may result in the disqualification of an IRA. In addition, the fiduciary of the Plan that engages in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and/or the Code.
The acquisition and/or holding of the Notes, or any interest in therein, by a Covered Plan with respect to which a Transaction Party is considered a party in interest or a disqualified person may constitute or result in a direct or indirect prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code, unless the investment is acquired and is held in accordance with an applicable statutory, class, or individual prohibited transaction exemption. Included among these statutory exemptions are Section 408(b)(17) of ERISA and Section 4975(d)(20) of the Code, which exempt certain transactions (including, without limitation, a sale and purchase of securities) between a Covered Plan and a party in interest so long as (i) such party in interest is treated as such solely by reason of providing services to the Covered Plan, (ii) such party in interest is not a fiduciary that renders investment advice, or has or exercises discretionary authority or control, with respect to the plan assets involved in such transaction, or an affiliate of any such person, and (iii) the Covered Plan neither receives less than nor pays more than “adequate consideration” (as defined in such Sections) in connection with such transaction. In addition, the U.S. Department of Labor has issued prohibited transaction class exemptions (“PTCEs”) that may apply to the acquisition and holding of the Notes. These class exemptions include, without limitation, PTCE 84-14 respecting transactions determined by independent qualified professional asset managers, PTCE 90-1 respecting insurance company pooled separate accounts, PTCE 91-38
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respecting bank collective investment funds, PTCE 95-60 respecting life insurance company general accounts, and PTCE 96-23 respecting transactions determined by in-house asset managers. Each of the above-noted exemptions contains conditions and limitations on its application. Fiduciaries of Covered Plans considering acquiring and/or holding the Notes in reliance on these or any other exemption should carefully review the exemption to assure it is applicable. There can be no assurance that all of the conditions of any such exemptions will be satisfied.
Government plans, foreign plans, and certain church plans, while not subject to the prohibited transaction provisions of Section 406 of ERISA or Section 4975 of the Code, may nevertheless be subject to Similar Laws. Fiduciaries of such Plans should consult with their counsel before acquiring the Notes, or any interest in the Notes.
Because of the foregoing, the Notes, or any interest in the Notes, should not be purchased or held by any person investing “plan assets” of any Plan, unless such purchase and holding will not constitute a nonexempt prohibited transaction under ERISA and the Code or similar violation of any applicable Similar Laws.
Representations
Accordingly, by its acceptance of a Note, or any interest therein, each purchaser and holder a of Note, or interest therein, and any subsequent transferee of a Note, or any interest therein, will be deemed to have represented and warranted that (a) either (i) such purchaser or subsequent transferee is not, and is not using the assets of, a Plan to acquire or hold the Note, or any interest therein, or (ii) the purchase and holding of a Note, or any interest therein, by such purchaser or transferee does not, and will not, constitute a non-exempt prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code or a similar violation under any applicable Similar Laws and (b) none of the Transaction Parties is acting, or will act, as a fiduciary to any Plan with respect to the decision to purchase or hold the Notes or is undertaking to provide impartial investment advice or give advice in a fiduciary capacity with respect to the decision to purchase or hold the Notes.
The foregoing discussion is general in nature and is not intended to be all-inclusive. Due to the complexity of these rules and the penalties that may be imposed upon persons involved in non-exempt prohibited transactions, it is particularly important that fiduciaries or other persons considering purchasing and/or holding of the Notes, or any interest therein, on behalf of, or with the assets of, any Plan, consult with their counsel regarding the potential applicability of ERISA, Section 4975 of the Code, or any Similar Law and whether an exemption would be required. Neither this discussion nor anything provided in this prospectus is, or is intended to be, investment advice directed at any potential Plan purchasers, or at Plan purchasers generally, and such purchasers of the Notes should consult and rely on their own counsel and advisers as to whether an investment in the Notes, or any interest therein, is suitable for the Plan.
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We are offering up to $750,000,000 in aggregate principal amount of Notes on a continuous basis. We will offer the Notes at a price equal to 100% of the principal amount of such Notes, directly to the public without an underwriter or placement agent. We have arbitrarily determined the selling price of the Notes and such price bears no relationship to our book or asset values, or to any other established criteria for valuing issued or outstanding Notes.
The Notes will be offered to prospective investors on a commercially reasonable efforts basis by the Managing Broker-Dealer, which means that our broker/dealer of record is not obligated to purchase any specific number or dollar amount of Notes, but will use commercially reasonable efforts to sell the Notes. We reserve the right to engage additional selling group members to assist in the sale of the Notes.
We may market Notes in many ways, including, but not limited to, in a newspaper, through direct mail, tradeshow presentations, or television commercials, or over the Internet, in each case, in states in which we have properly registered the offering or qualified for an exemption from registration. Viewers of print or online advertising are referred to our website at https://invest.phoenixenergy.com. The established features are available to investors on our website at https://invest.phoenixenergy.com or by calling (303) 376-9778. If, upon review of our website, a potential investor becomes interested in purchasing Notes, a prospectus will be sent upon request. We may also make oral solicitations in limited circumstances and use other methods of marketing the offering, all in compliance with applicable laws and regulations, including federal and state securities laws. Our employees and independent managers that are not registered broker-dealers have been instructed not to solicit offers to purchase Notes or provide advice regarding the purchase of Notes. The information contained on our website is not part of this prospectus or the registration statement of which this prospectus forms a part. If you have questions about the suitability of an investment in the Notes for you, you should consult with your own investment, tax, or other professional financial advisor. Prospective investors will be required to complete an application prior to investing in the Notes. We reserve the right to reject any investment.
Adam Ferrari, our Chief Executive Officer, and Curtis Allen, our Chief Financial Officer, will market the Notes in reliance on Rule 3a4-1 under the Exchange Act, which permits officers, directors, and employees to participate in the sale of the Notes without registering as a broker-dealer under certain circumstances. Messrs. Ferrari and Allen are not subject to a statutory disqualification as such term is defined in Section 3(a)(39) of the Exchange Act. Messrs. Ferrari and Allen serve as executive officers and primarily perform substantial duties for us or on our behalf otherwise than in connection with transactions in securities and will continue to do so at the end of this offering. They are familiar with the selling practices permitted to officers relying on Rule 3a4-1. Neither Mr. Ferrari nor Mr. Allen has been a broker or dealer, or an associated person of a broker or dealer, within the preceding 12 months, and has not and will not participate in the sale of securities for any issuer more than once every 12 months, other than on our behalf in reliance on Rule 3a4-1. Messrs. Ferrari and Allen are not compensated in connection with any participation in this offering by the payment of commissions or other remuneration based either directly or indirectly on transactions in the Notes. Messrs. Ferrari and Allen have been instructed in the limitations of the selling practices allowed under Rule 3a4-1.
Broker-Dealer Compensation and Expenses
We will pay the Managing Broker-Dealer the Broker-Dealer Fee of 0.75% of the gross proceeds of the offering with respect to the first $100.0 million of gross proceeds, 0.65% of the gross proceeds of the offering with respect to the second $100.0 of gross proceeds, and 0.55% of the gross proceeds of the offering thereafter, in each case, occurring during each 12-month period following effectiveness of the registration statement of which this prospectus forms a part. In addition, we will pay Dalmore Group a sales commission to be paid to certain of our non-executive personnel, including Matthew Willer, our Managing Director, Capital Markets, as compensation with respect to the sale of Notes, of 0.50%, 0.75%, 0.88%, or 1.00% with respect to the sale of the Notes with maturities of three years, five years, seven years, or eleven years, respectively. Such non-executive personnel are paid a base salary of $60,000 and are entitled to participate in the benefits we provide to all of our employees, including 401(k) contributions, medical-insurance options, and programs to encourage and support the employees’ development. Such non-executive personnel are eligible to receive sales commissions once the commissions they would have earned in such year (either pursuant to this offering or pursuant to any of our other securities offerings) are in excess of their base salary. Total compensation to be received by or paid to selling group members, including, without limitation, the Broker-Dealer Fee and sales commissions, will not exceed 1.75% of the proceeds raised with the assistance of those selling group members.
The following table sets forth the per Note and total maximum Broker-Dealer Fee that we may pay to the Managing Broker-Dealer, plus sales commissions, in connection with this offering, assuming the entire amount of Notes offered hereby is issued and sold:
| Broker-Dealer Compensation |
Per Note | Total | ||||||
| Broker-Dealer Fee |
$ | 6.70 | $ | 5,025,000 | (1) | |||
| Sales Commissions |
$ | 7.97 | $ | 5,978,000 | (2) | |||
| Total |
$ | 11,003,000 | ||||||
| (1) | Reflects $250.0 million of Notes sold per year following effectiveness of the registration statement of which this prospectus forms a part, representing the maximum Broker-Dealer Fee. |
| (2) | Reflects the full amount of Notes sold with each maturity and assumes sales commissions are not otherwise reduced by any amounts of base salary. Sales commissions increase based on the maturity of the Notes sold as described above. |
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The aggregate proceeds to us are set forth on the cover page of this prospectus before deducting our expenses. Excluding the Broker-Dealer Fee and sales commissions, we estimate that we will pay approximately $4.6 million for expenses, including $40,000 of fees paid or payable to Dalmore Group consisting of (i) a one-time advance set up fee of $15,000 to cover reasonable out-of-pocket expenses incurred by Dalmore Group in connection with the offering and (ii) a one-time consulting fee of $25,000 that will be due once FINRA issues a “No Objections Letter” with respect to this offering.
We have agreed to indemnify the Managing Broker-Dealer, and expect to indemnify other selling group members and selected registered investment advisors, against certain liabilities arising under the Securities Act.
We may forego paying the Broker-Dealer Fee, or pay a reduced Broker-Dealer Fee, in connection with the sale of Notes in this offering to:
| • | registered principals or representatives of our dealer-manager or a participating broker (and immediate family members of any of the foregoing persons); |
| • | our employees, officers, and directors or those of our members, or the affiliates of any of the foregoing persons (and the immediate family members of any of the foregoing persons), any benefit plan established exclusively for the benefit of such persons or entities, and, if approved by our managers, joint venture partners, consultants, and other service providers; |
| • | clients of an investment advisor registered under the U.S. Investment Advisers Act of 1940, as amended, or under applicable state securities laws (other than any registered investment advisor that is also registered as a broker-dealer, with the exception of clients who have “wrap” accounts that have asset-based fees with such dually registered investment advisor/broker-dealer); or |
| • | persons investing in a bank trust account with respect to which the authority for investment decisions made has been delegated to the bank trust department. |
For purposes of the foregoing, “immediate family members” means such person’s spouse, parents, children, brothers, sisters, grandparents, grandchildren, and any such person who is so related by marriage such that this includes “step-” and “-in-law” relations, as well as such persons so related by adoption.
It is illegal for us to pay or award any commissions or other compensation to any person engaged by you for investment advice as an inducement to such advisor to advise you to purchase the Notes; however, nothing herein will prohibit a registered broker-dealer or other properly licensed person from earning a sales commission in connection with a sale of Notes.
New Issue of Securities
The Notes will be a new issue of securities with no established trading market or trading platform. We do not intend to apply for listing of the Notes on any national securities exchange or for inclusion of the Notes on any automated dealer quotation system. We cannot assure you of the development of a trading platform or the development or liquidity of any trading market for the Notes. If no trading platform is established, or an active trading market for the Notes does not develop, the market price and liquidity of the Notes may be adversely affected. If the Notes are traded, they may trade at a discount from their initial offering price, depending on prevailing interest rates, the market for similar securities, our operating performance and financial condition, general economic conditions, and other factors. Therefore, you must be prepared to hold your Notes to maturity.
Offering Process
The process being used for this offering differs from methods that have been traditionally used in most other public offerings of debt securities in the United States. We will offer the Notes on a continuous basis pursuant to Rule 415 under the Securities Act, directly to the public without an underwriter or placement agent. We have not made any arrangement to place any of the proceeds from this offering in an escrow, trust, or similar account.
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From time to time, we may prepare prospectus supplements to update this prospectus for various purposes, such as to disclose changes to the terms of the offering of the Notes, provide quarterly updates of financial and other information included in this prospectus, and disclose other material developments. These prospectus supplements will be filed with the SEC pursuant to Rule 424(b) promulgated under the Securities Act and will be posted on our website. When required by SEC rules, such as when there is a “fundamental change” in the offering or the information contained in this prospectus, or when an annual update of financial information is required by the Securities Act or SEC rules, we will file post-effective amendments to the registration statement of which this prospectus forms a part, which will include either a prospectus supplement or an entirely new prospectus to replace this prospectus. We currently anticipate that post-effective amendments will be required, among other times, when there are changes to the material terms of the Notes.
In order to invest in Notes, you will be required to complete and execute a subscription agreement substantially in the form attached as an exhibit to the registration statement of which this prospectus forms a part. The subscription agreement may be submitted in paper form and, if so submitted, must be delivered to the address set forth for such purposes on our website. As of the date of this prospectus, the address to which you should submit paper form subscription agreements is as follows:
Phoenix Energy One, LLC
Attention: David Wheeler
18575 Jamboree Road, Suite 830
Irvine, California 92612
Subscription agreements may be also submitted electronically through our website. Generally, when submitting a subscription agreement electronically, you will be required to agree to various terms and conditions by checking boxes, and to review and electronically sign any necessary documents. You may pay the purchase price for your Notes by check, ACH, or wire transfer in accordance with the instructions in the subscription agreement. All checks should be made payable to “Phoenix Energy One, LLC.” By completing and executing your subscription agreement you will also acknowledge and represent that you have received a copy of this prospectus, including all amendments and supplements thereto, you are purchasing the Notes for your own account, and that your rights and responsibilities regarding your Notes will be governed by the Indenture, including the form of Note, each included as an exhibit to the registration statement of which this prospectus forms a part. Neither we nor any selling group member have undertaken any efforts to qualify this offering for offers to investors in any jurisdiction outside the United States. Investors must have a U.S. mailing address (other than a P.O. Box) and a U.S. social security number and/or a U.S. tax identification number to be eligible to participate in this offering.
Upon review of the information that you provide in the subscription agreement, we will determine, in our sole discretion, whether to issue any Notes to you or whether you meet the criteria for investing in the Notes. See “—Financial Suitability Requirements” below. We will not accept any subscription requests prior to the effective date of the registration statement of which this prospectus forms a part. If we determine that you are eligible to participate in the offering and to issue you Notes, then we will notify you of our acceptance of your subscription agreement and related subscription payment. If we do not accept your request, your subscription payment will be returned to you. We caution you that the Notes may not be a suitable investment for you even if you do qualify to purchase Notes. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”
Once a subscription agreement and related subscription payment have been submitted to and accepted by us, you will not have the right to request the return of your subscription payment. We intend to hold closings on a weekly basis assuming there are funds to close. On each closing date, offering proceeds for that closing will be disbursed to us, and Notes will be issued to investors participating in that closing in registered form on the books and records of the Issuer. If we are dissolved or liquidated after the acceptance by us of a subscription agreement and related subscription payment and prior to the next closing date, your subscription payment will be returned to you.
This offering of Notes will continue until the earliest of: (i) the date we issue and sell all of the Notes registered in this offering, including pursuant to any registration statement filed pursuant to Rule 462(b) under the Securities Act; (ii) any required date of termination pursuant to Rule 415 under the Securities Act; and (iii) such earlier date on which we determine, in our sole discretion, to terminate this offering. If this offering is terminated after the acceptance by us of a subscription agreement and related subscription payment and prior to the next closing date, your subscription payment will be returned to you.
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Financial Suitability Requirements
An investment in the Notes involves significant risks and is only suitable for investors who have adequate financial means, desire a relatively long-term investment, and will not need liquidity from their investment. This investment is not suitable for investors who seek liquidity or guaranteed income. You should only consider purchasing Notes if you can afford the loss of your entire investment.
Notes will only be sold to investors representing that they have (i) a gross income of at least $70,000 and a liquid net worth of $70,000 or (ii) a liquid net worth of at least $250,000 (the “general suitability standards”). For these purposes, “liquid net worth” is defined as the portion of net worth consisting of cash, cash equivalents, and readily marketable securities. Certain states in which we intend to sell the Notes have established special suitability standards that are different from the general suitability standards. Notes will be sold only to investors in these states who also meet the special suitability standards set forth below:
| • | For Idaho Residents – Notes will only be sold to residents of the State of Idaho in an amount such that the investor’s total investment in the Notes does not exceed 10% of such investor’s liquid net worth. |
| • | For Iowa Residents – Notes will only be sold to residents of Iowa in an amount such that the investor’s total investment in the Notes does not exceed 10% of such investor’s liquid net worth. |
| • | For Kansas Residents – It is required by the Office of the Kansas Securities Commissioner that Kansas investors limit their aggregate investment in our securities and other similar programs to not more than 10% of their liquid net worth. For these purposes, “liquid net worth” is defined as that portion of total net worth (total assets minus liabilities) that comprises cash equivalents and readily marketable securities, as determined in conformity with GAAP. |
| • | For Missouri Residents – Notes will only be sold to residents of Missouri in an amount such that the investor’s total investment in the Notes does not exceed no more than 10% of such investor’s liquid net worth. |
We will not sell Notes in any jurisdiction until registration is complete for that particular jurisdiction, or there is a valid exemption from such registration in such jurisdiction.
As of the date of this prospectus, we are in the process of applying to register the Notes described in this prospectus for sale in the following states: Colorado, Connecticut, Delaware, Florida, Georgia, Idaho, Illinois, Indiana, Iowa, Kansas, Maine, Massachusetts, Minnesota, Missouri, Montana, Nevada, New Hampshire, New Jersey, New York, North Dakota, Ohio, Oklahoma, Oregon, Rhode Island, South Carolina, South Dakota, Tennessee, Vermont, West Virginia, Wisconsin, and Wyoming. As of the date of this prospectus, we have been approved or otherwise have a valid exemption to sell Notes in the following states: Hawaii, Louisiana, and Utah. We expect that, concurrent with the effectiveness of the registration statement of which this prospectus forms a part, we will be qualified to sell Notes in this offering under the blue sky laws of the following states: Colorado, Connecticut, Florida, Georgia, Illinois, Iowa, New York, Rhode Island, South Dakota, Wisconsin, and Wyoming. We may register the offer and sale of the Notes in additional jurisdictions in the future. As part of this process, we expect that jurisdictions in addition to those referenced above will impose minimum financial suitability standards and maximum investment limits for investors who reside in such jurisdictions. Should this occur, we will set forth these requirements in a supplement to this prospectus. Investors are required in their subscription agreement to represent and warrant that they satisfy the applicable minimum financial suitability standards and maximum investment limits of the state in which they reside. Investors who fail to satisfy any such requirements will not be permitted to purchase Notes.
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The selling group members and other registered investment advisors recommending the purchase of Notes in this offering have the responsibility to make every reasonable effort to determine that your purchase of Notes in this offering is a suitable and appropriate investment for you based on information provided by you regarding your financial situation and investment objectives. In making this determination, these persons have the responsibility to ascertain that you:
| • | meet minimum income and net worth standards; |
| • | can reasonably benefit from an investment in the Notes based on your overall investment objectives and portfolio structure; |
| • | are able to bear the economic risk of the investment based on your overall financial situation; |
| • | are in a financial position appropriate to enable you to realize to a significant extent the benefits described in this prospectus of an investment in the Notes; and |
| • | have apparent understanding of: |
| • | the fundamental risks of the investment; |
| • | the risk that you may lose your entire investment; |
| • | the lack of liquidity of the Notes; |
| • | the restrictions on transferability of the Notes; and |
| • | the tax consequences of your investment. |
Relevant information for this purpose will include at least your age, investment objectives, investment experience, income, net worth, financial situation, and other investments, as well as any other pertinent factors. The selling group members and other registered investment advisors recommending the purchase of Notes in this offering must maintain, for a six-year period, records of the information used to determine that an investment in Notes is suitable and appropriate for you. The selling group members or other registered investment advisors may not execute any transaction related to the offering of the Notes in a discretionary account without your prior written approval of such transaction.
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The validity of the Notes offered hereby will be passed upon for us by Latham & Watkins LLP, Washington, District of Columbia.
The consolidated financial statements of Phoenix Energy One, LLC as of December 31, 2024, 2023, and 2022 and for the years then ended included in this prospectus have been so included in reliance on the report of Ramirez Jimenez International CPAs, an independent registered public accounting firm, given upon the authority of such firm as experts in accounting and auditing.
CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT
On December 4, 2023, we dismissed Cherry Bekaert LLP as our principal accountant and approved the engagement of Ramirez Jimenez International CPAs as our principal accountant to audit our consolidated financial statements as of and for the years ended December 31, 2023 and 2022.
Cherry Bekaert LLP’s audit reports on our consolidated financial statements as of and for the years ended December 31, 2022 and 2021 did not contain any adverse opinion or disclaimer of opinion, and were not qualified or modified as to any uncertainty, audit scope, or accounting principles.
During the years ended December 31, 2022 and 2021, and the subsequent interim period through December 4, 2023, there were no disagreements (as defined in Item 304(a)(1)(iv) of Regulation S-K under the Securities Act) between us and Cherry Bekaert LLP on any matter of accounting principles or practices, financial disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Cherry Bekaert LLP, would have caused it to make reference to the subject matter of the disagreements in its reports on our financial statements for such period. During the years ended December 31, 2022 and 2021, and the subsequent interim period through December 4, 2023, there were no “reportable events” (as defined in Item 304(a)(1)(v) of Regulation S-K under the Securities Act).
During the years ended December 31, 2022 and 2021, and the subsequent interim period through December 4, 2023, we did not consult with Ramirez Jimenez International CPAs with respect to (i) the application of accounting principles to a specified transaction, either completed or proposed, the type of audit opinion that might be rendered on our financial statements, and neither a written report nor oral advice was provided to us that Ramirez Jimenez International CPAs concluded was an important factor considered by us in reaching a decision as to any accounting, auditing, or financial reporting issue or (ii) any other matter that was the subject of a disagreement or a reportable event (each as defined above).
We provided Cherry Bekaert LLP with a copy of the foregoing disclosures and requested that Cherry Bekaert LLP furnish us with a letter addressed to the SEC stating whether Cherry Bekaert LLP agrees with the statements made by us as set forth above. A copy of Cherry Bekaert LLP’s letter is filed as an exhibit to the registration statement of which this prospectus forms a part.
WHERE YOU CAN FIND ADDITIONAL INFORMATION
We have filed with the SEC a registration statement on Form S-1 under the Securities Act to register with the SEC the Notes being offered by this prospectus. This prospectus, which constitutes a part of the registration statement, does not contain all of the information set forth in the registration statement or the exhibits and schedules to the registration statement, portions of which have been omitted as permitted by the rules and regulations of the SEC. For further information about us and the Notes, you should refer to the registration statement and the exhibits and schedules filed as part of the registration statement. Statements contained in this prospectus regarding the contents of any contract, agreement, or any other document are summaries of certain terms thereof and are not necessarily complete, and each such statement is qualified in all respects by reference to the full text of such contract, agreement, or other document filed as an exhibit to the registration statement. You can read the registration statement at the SEC’s website at www.sec.gov.
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As a result of this offering, we will become subject to the information and reporting requirements of the Exchange Act and, in accordance with this law, will file annual, quarterly, and current reports and other information with the SEC. Our filings with the SEC will be made available to the public on the SEC’s website at www.sec.gov. Those filings will also be made available to the public on, or accessible through, our website at https://phoenixenergy.com. The information we file with the SEC or contained on or accessible through our website is not part of, and is not incorporated by reference into, this prospectus or the registration statement of which this prospectus is a part. We do not intend to deliver annual reports to security holders if such reports are not required pursuant to Section 15(d) of the Exchange Act.
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PHOENIX ENERGY ONE, LLC
AND SUBSIDIARIES
Consolidated Financial Statements
As of and for the years ended December 31, 2024, 2023, and 2022
Table of Contents
| Audited Consolidated Financial Statements |
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| F-3 | ||||
| F-5 | ||||
| F-6 | ||||
| F-7 | ||||
| F-8 | ||||
| F-9 |
F-2
Table of Contents
|
18012 Sky Park Circle, Suite 100 Irvine, California 92614 tel 949-852-1600 fax 949-852-1606 www.rjicpas.com |
Report of Independent Registered Public Accounting Firm
To the Members of Phoenix Energy One, LLC
Irvine, California
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Phoenix Energy One, LLC and Subsidiaries (the Company) as of December 31, 2024, 2023 and 2022, and the related consolidated statements of operations, changes in equity (deficit) and cash flows for the years then ended, and the related notes to the consolidated financial statements (collectively referred to as the “financial statements”). In our opinion, the 2024, 2023 and 2022 consolidated financial statements present fairly, in all material respects, the financial position of Phoenix Energy One, LLC and Subsidiaries as of December 31, 2024, 2023 and 2022, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Restatement of 2023 and 2022 Financial Statements
As discussed in Note 3 to the consolidated financial statements, the 2023 and 2022 financial statements have been restated to correct misstatements. The 2022 financial statements of Phoenix Energy One, LLC before the adjustments described in Note 3 were audited by another auditor whose report, dated May 1, 2023, expressed an unqualified opinion on those financial statements. We have audited the 2022 and 2023 financial statements, as restated, as of and for the years ended December 31, 2023 and 2022, including the adjustments described in Note 3 that were applied to restate the 2023 and 2022 financial statements. In our opinion, such adjustments are appropriate and have been properly applied.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Phoenix Energy One, LLC in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Phoenix Energy One, LLC is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
F-3
Table of Contents
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the Audit Committee (those charged with governance) of the Board of Directors/Members and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts and disclosures to which they relate.
Estimation and Valuation of Proven Reserves
The estimation and valuation of proven reserves is identified as a critical audit matter. The valuation of these reserves is highly subjective due to the complexities involved in estimating the reserves, and the significant judgment required in determining the valuation assumptions, such as future commodity prices, production rates, and capital expenditures. The estimation of volumes and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or impairment expense.
The following are the primary procedures we performed to address this critical audit matter. We performed the following audit procedures in relation to the evaluation of proved reserves:
| 1. | We sampled additions and disposals of reserve assets during the year to test the accuracy and completeness of the recording processes. |
| 2. | We gained an understanding of the Company’s process for estimating reserve quantities and valuing the reserves. |
| 3. | We validated the mathematical accuracy, formulas, and inputs used in the depletion reserve calculations to ensure the reserve expense calculation was appropriate for the type of reserves reported. |
| 4. | We performed reasonability tests to confirm whether the proved reserve balances for oil and gas properties were within expected ranges, based on historical data. |
| 5. | We tested the completeness and accuracy of data for selected wells to verify that the Company’s system was pulling accurate and relevant well data. |
| 6. | We reviewed the third-party reserve engineer’s report to assess the reasonableness and appropriateness of the Company’s approach and methodology in calculating their reserve estimates. |
| 7. | We assessed the knowledge, skills and expertise of the third-party reserve engineer involved in testing the reasonableness and approach to the reserve estimates. |
| 8. | We obtained and evaluated the third-party legal opinion from a title attorney concerning the Company’s ownership percentages of sampled wells, to validate the accuracy of these percentages. |
| 9. | We compared the estimated pricing and pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year for the pricing differentials. |
| 10. | Assessed the reasonableness of forecasted capital expenditures by comparing drilling forecasts applied in the reserve report to recent drilling costs. |
| 11. | Obtained evidence supporting the amount of development of proved undeveloped properties reflected in the reserve report and compared with forecasted drilling plans and budgets. |
We have served as the Company’s auditors since 2023.
Irvine, California
March 26, 2025, except for Note 17, as to which the date is April 23, 2025
F-4
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Consolidated Balance Sheets
(in thousands)
| December 31, | ||||||||||||
| 2024 | 2023 (As Restated) |
2022 (As Restated) |
||||||||||
| ASSETS | ||||||||||||
| Current assets |
||||||||||||
| Cash and cash equivalents |
$ | 120,814 | $ | 5,428 | $ | 4,607 | ||||||
| Accounts receivable |
28,218 | 32,822 | 4,013 | |||||||||
| Earnest payments |
154 | 25,387 | 794 | |||||||||
| Other current assets |
7,528 | 647 | 376 | |||||||||
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| Total current assets |
156,714 | 64,284 | 9,790 | |||||||||
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| Oil and gas properties | 1,006,221 | 478,339 | 165,390 | |||||||||
| Accumulated depletion and impairment | (140,376 | ) | (54,671 | ) | (20,635 | ) | ||||||
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| Net oil and gas properties |
865,845 | 423,668 | 144,755 | |||||||||
| Right-of-use assets, net | 6,010 | 4,542 | 1,798 | |||||||||
| Other noncurrent assets | 501 | 673 | 677 | |||||||||
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| Total Assets |
$ | 1,029,070 | $ | 493,167 | $ | 157,020 | ||||||
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| LIABILITIES AND MEMBER’S EQUITY (DEFICIT) | ||||||||||||
| Current liabilities | ||||||||||||
| Accounts payable |
$ | 41,824 | $ | 47,272 | $ | 19,438 | ||||||
| Short-term debt |
— | 25,819 | 6,818 | |||||||||
| Current portion of long-term debt |
103,240 | 87,038 | 46,039 | |||||||||
| Current portion of deferred closings |
7,189 | 10,196 | 5,696 | |||||||||
| Escrow account |
16,356 | 6,491 | 701 | |||||||||
| Current operating lease liabilities |
656 | 567 | 305 | |||||||||
| Accrued and other liabilities | 57,346 | 6,388 | 2,236 | |||||||||
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| Total current liabilities |
226,611 | 183,771 | 81,233 | |||||||||
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| Long-term debt, net of current portion | 795,215 | 295,167 | 59,481 | |||||||||
| Accrued interest | 26,079 | 6,369 | 291 | |||||||||
| Deferred closings | 3,324 | 7,884 | 5,533 | |||||||||
| Operating lease liabilities | 5,860 | 4,225 | 1,597 | |||||||||
| Asset retirement obligations | 1,181 | 585 | 212 | |||||||||
| Other noncurrent liabilities | 4,858 | — | — | |||||||||
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| Total liabilities |
1,063,128 | 498,001 | 148,347 | |||||||||
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| Member’s equity (deficit) | ||||||||||||
| Member’s equity |
434 | 4,865 | 2,183 | |||||||||
| Retained earnings (accumulated deficit) |
(34,492 | ) | (9,699 | ) | 6,490 | |||||||
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| Total member’s equity (deficit) |
(34,058 | ) | (4,834 | ) | 8,673 | |||||||
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| Total Liabilities and Member’s Equity (Deficit) |
$ | 1,029,070 | $ | 493,167 | $ | 157,020 | ||||||
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The accompanying notes are an integral part of these consolidated financial statements.
F-5
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Consolidated Statements of Operations
(in thousands)
| Year Ended December 31, | ||||||||||||
| 2024 | 2023 (As Restated) |
2022 (As Restated) |
||||||||||
| REVENUES | ||||||||||||
| Mineral and royalty revenues | $ | 152,999 | $ | 118,088 | $ | 54,554 | ||||||
| Product sales | 125,649 | — | — | |||||||||
| Water services | 2,478 | — | — | |||||||||
| Other revenues | 101 | 17 | — | |||||||||
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| Total revenues |
281,227 | 118,105 | 54,554 | |||||||||
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| OPERATING EXPENSES | ||||||||||||
| Cost of sales | 63,947 | 19,733 | 9,573 | |||||||||
| Depreciation, depletion, amortization and accretion | 85,977 | 34,228 | 12,144 | |||||||||
| Selling, general and administrative | 29,167 | 14,314 | 5,563 | |||||||||
| Payroll and payroll-related expenses | 27,934 | 12,733 | 6,023 | |||||||||
| Advertising and marketing | 679 | 4,136 | 1,353 | |||||||||
| Loss on sale of assets | 564 | — | — | |||||||||
| Impairment expense | 564 | 974 | — | |||||||||
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| Total operating expenses |
208,832 | 86,118 | 34,656 | |||||||||
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| Income from operations | 72,395 | 31,987 | 19,898 | |||||||||
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| OTHER INCOME (EXPENSE) | ||||||||||||
| Interest income | 705 | 66 | — | |||||||||
| Interest expense | (90,210 | ) | (47,882 | ) | (11,893 | ) | ||||||
| Loss on derivatives | (5,986 | ) | (32 | ) | (2,239 | ) | ||||||
| Loss on debt extinguishment | (1,697 | ) | (328 | ) | (92 | ) | ||||||
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| Total other expenses |
(97,188 | ) | (48,176 | ) | (14,224 | ) | ||||||
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| NET INCOME (LOSS) |
$ | (24,793 | ) | $ | (16,189 | ) | $ | 5,674 | ||||
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The accompanying notes are an integral part of these consolidated financial statements.
F-6
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Consolidated Statements of Changes in Equity (Deficit)
(in thousands)
| Member’s Equity |
Retained Earnings (Accumulated Deficit) |
Total Member’s Equity (Deficit) |
||||||||||
| Balance, December 31, 2021 (As Restated) | $ | 2,088 | $ | 816 | $ | 2,904 | ||||||
| Contributions |
200 | — | 200 | |||||||||
| Distributions |
(105 | ) | — | (105 | ) | |||||||
| Net income (As Restated) |
— | 5,674 | 5,674 | |||||||||
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| Balance, December 31, 2022 (As Restated) | 2,183 | 6,490 | 8,673 | |||||||||
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| Contributions |
10,150 | — | 10,150 | |||||||||
| Distributions |
(7,468 | ) | — | (7,468 | ) | |||||||
| Net loss (As Restated) |
— | (16,189 | ) | (16,189 | ) | |||||||
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| Balance, December 31, 2023 (As Restated) | 4,865 | (9,699 | ) | (4,834 | ) | |||||||
|
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| Contributions |
325 | — | 325 | |||||||||
| Distributions |
(4,756 | ) | — | (4,756 | ) | |||||||
| Net loss |
— | (24,793 | ) | (24,793 | ) | |||||||
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| Balance, December 31, 2024 |
$ | 434 | $ | (34,492 | ) | $ | (34,058 | ) | ||||
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The accompanying notes are an integral part of these consolidated financial statements.
F-7
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(in thousands)
| Year Ended December 31, | ||||||||||||
| 2024 | 2023 (As Restated) |
2022 (As Restated) |
||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
| Net income (loss) |
$ | (24,793 | ) | $ | (16,189 | ) | $ | 5,674 | ||||
| Adjustments to reconcile net income (loss) to net cash flows from operating activities: |
||||||||||||
| Depreciation, depletion, amortization, and accretion |
85,977 | 34,228 | 12,144 | |||||||||
| Impairment expense |
564 | 974 | — | |||||||||
| Amortization of right-of-use assets |
643 | 422 | 104 | |||||||||
| Amortization of debt discount and debt issuance costs |
16,621 | 13,753 | 940 | |||||||||
| Unrealized loss (gain) on derivatives |
7,518 | 32 | (46 | ) | ||||||||
| Loss on sale of assets |
564 | — | — | |||||||||
| Loss on debt extinguishment |
1,697 | 328 | 92 | |||||||||
| Changes in operating assets and liabilities: |
||||||||||||
| Accounts receivable |
4,605 | (28,809 | ) | (2,731 | ) | |||||||
| Earnest payments |
(22,639 | ) | (24,593 | ) | (788 | ) | ||||||
| Accounts payable |
(10,967 | ) | 2,832 | 344 | ||||||||
| Accrued and other liabilities |
13,020 | 4,058 | 1,870 | |||||||||
| Escrow account |
9,865 | 5,790 | 701 | |||||||||
| Accrued interest |
19,829 | 6,078 | 291 | |||||||||
| Other |
(7,265 | ) | (730 | ) | 47 | |||||||
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| Net cash (used in) provided by operating activities |
95,239 | (1,826 | ) | 18,642 | ||||||||
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| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
| Additions to oil and gas properties and leases |
(443,820 | ) | (278,661 | ) | (91,263 | ) | ||||||
| Proceeds from sale of assets |
6,200 | — | — | |||||||||
| Additions to equipment and other property |
(83 | ) | — | (625 | ) | |||||||
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| Net cash used in investing activities |
(437,703 | ) | (278,661 | ) | (91,888 | ) | ||||||
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| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
| Proceeds from issuances of debt, net of discount |
864,003 | 464,541 | 80,499 | |||||||||
| Payments of debt issuance costs |
(63,723 | ) | (43,441 | ) | (5,351 | ) | ||||||
| Repayments of debt |
(328,167 | ) | (139,494 | ) | 2,687 | |||||||
| Members’ contributions |
325 | 10,150 | 200 | |||||||||
| Members’ distributions |
(4,756 | ) | (7,468 | ) | (105 | ) | ||||||
| Payments of deferred closings |
(9,832 | ) | (2,980 | ) | (437 | ) | ||||||
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| Net cash provided by financing activities |
457,850 | 281,308 | 77,493 | |||||||||
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| Net change in cash and cash equivalents | 115,386 | 821 | 4,247 | |||||||||
| Cash and cash equivalents at beginning of year | 5,428 | 4,607 | 360 | |||||||||
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| Cash and cash equivalents at end of year | $ | 120,814 | $ | 5,428 | $ | 4,607 | ||||||
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The accompanying notes are an integral part of these consolidated financial statements.
F-8
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 1 – Business
Phoenix Energy One, LLC (“Phoenix Energy”), formerly known as Phoenix Capital Group Holdings, LLC (“Phoenix Capital”), is a Delaware limited liability company focused on oil and gas operations primarily in the Williston Basin, North Dakota/Montana, the Uinta Basin, Utah, the Permian Basin, Texas, the Denver-Julesburg Basin, Colorado/Wyoming and the Powder River Basin, Wyoming. The Company was formed in April 2019 and changed its name to Phoenix Energy in January 2025. As used in these consolidated financial statements, unless the context otherwise requires, references to the “Company,” “we,” “us,” and “our” refer to Phoenix Energy and its consolidated subsidiaries.
The Company’s strategy involves the acquisition of royalty assets, acquisition of non-operated working interests and direct drilling operations of operated working interests conducted through its wholly-owned subsidiaries, Phoenix Operating, LLC (“PhoenixOp”) and Firebird Services LLC (“Firebird”). PhoenixOp is a Delaware limited liability company formed in January 2022 to drill, complete and operate wells in the United States. Firebird is a Delaware limited liability company formed in October 2023 to perform saltwater disposal services on wells operated by PhoenixOp.
Phoenix Energy has also formed several financing entities, including Phoenix Capital Group Holdings I, LLC (“PCGH I”) in November 2022 and Adamantium Capital LLC (“Adamantium”) in June 2023, to undertake financing efforts and raise debt capital through unregistered and registered debt offerings to retail investors.
The Company operates as a limited liability company for which Lion of Judah Capital, LLC (“Lion of Judah”) was the majority profit-share owner and exclusive equity contributor until October 2024. In October 2024, as part of a reorganization of the Company, all the then-existing interests of the Company’s profit-share partners, including Lion of Judah who had previously held a 60.18% interest in Phoenix Energy, were exchanged for interests in Phoenix Equity Holdings, LLC (“Phoenix Equity”), a Delaware limited liability company and the sole member of Phoenix Energy following the transaction. Lion of Judah remains the majority equity owner and controlling member of Phoenix Equity.
Note 2 – Significant Accounting Policies
Basis of preparation and principles of consolidation
The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The consolidated financial statements include the accounts of Phoenix Energy and its wholly-owned subsidiaries. All intercompany accounts and transactions with and between Phoenix Energy and its wholly-owned subsidiaries have been eliminated in consolidation. Certain prior period amounts have been reclassified to conform to current period presentation.
Liquidity risk and management’s plans
Liquidity risk is the risk that the Company’s cash flows from operations will not be sufficient for the Company to continue operating and discharge its liabilities in the normal course of operations. The Company is exposed to liquidity risk as its continued operation is dependent upon its ability to continue to obtain financing, either in the form of debt or equity, or by achieving profitable operations in order to satisfy its liabilities as they come due.
As of December 31, 2024, the Company had negative working capital of approximately $69.9 million and a member’s deficit of approximately $34.1 million. The Company expects to repay its financial liabilities in the normal course of operations and to fund future operational and capital requirements through operating cash flows and through issuances of additional debt. As of March 26, 2025, after the balance sheet date, the Company had raised an additional $141.5 million of notes through its investor program (see Note 8 – Debt and Note 18 – Subsequent Events). Management believes its capital raises through its bond offerings will continue at or above this current pace.
F-9
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
The Company may need to conduct asset sales, which is not a planned course of action, and/or issuances of debt and/or equity if liquidity risk increases in any given period. The Company believes it has sufficient funds to meet foreseeable obligations by actively monitoring its credit facilities through use of the loans, asset sales, cost reductions and coordinating payment and revenue cycles.
The Company is required to evaluate whether or not its current financial condition, including its sources of liquidity at the date that the consolidated financial statements are issued, will enable the Company to meet its obligations as they come due within one year of the date of the issuance of these consolidated financial statements and to make a determination as to whether or not it is probable, under the application of this accounting guidance, that the Company will be able to continue as a going concern. In applying applicable accounting guidance, we considered the Company’s current financial condition and liquidity sources, including current funds available, forecasted future cash flows, the Company’s obligations due over the next twelve months as well as the Company’s recurring business operating expenses, and believe to have sufficient financial resources to operate beyond the next twelve months following the date these consolidated financial statements are issued.
Use of estimates
The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the applicable reporting period of such statements. Accordingly, actual results could differ materially from these estimates.
The accompanying consolidated financial statements are based on a number of significant estimates including quantities of oil, natural gas and natural gas liquids (“NGL”) reserves that are the basis for the calculations of depreciation, depletion, amortization, and determinations of impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas and there are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment along with estimated selling prices. As a result, reserve estimates may materially differ from the quantities of oil and natural gas that are ultimately recovered.
Segment information
The Company’s Chief Executive Officer, who is our Chief Operating Decision Maker (the “CODM”), previously reviewed the Company’s operating results on a consolidated basis and managed our operations as a single operating segment: Phoenix Capital. The objective of Phoenix Capital was to acquire mineral interests and non-operated working interests in oil and gas properties and once acquired, to share in the proceeds of the natural resources extracted and sold by the operator. The Company’s financing activities and capital raise programs were also conducted under the Phoenix Capital segment.
In 2023, the Company began operating as two segments: Phoenix Capital and a new segment, PhoenixOp, which was formed to drill, extract and operate producing wells. The Company’s performance was evaluated based on the operating profit of the respective segments.
During the first quarter of 2024, the Company’s activities associated with its debt securities offerings met the criteria specified in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280 Segments to be classified as an operating segment, resulting in a change to the composition of the Company’s reportable segments. The segment previously described as “Phoenix Capital” was split into two components: Mineral and Non-operating and Securities, and the segment previously described as “PhoenixOp” was renamed to the Operating segment. The Company began reporting these three segments during the first quarter of 2024 to align with the manner in which the CODM manages the business and allocates resources within the Company. The Company acquires mineral interests and non-operated working interests in oil and gas properties under the Mineral and Non-operating segment; drills, extracts and operates wells under the Operating segment; and conducts activities associated with its debt securities offerings under the Securities segment. All of the Company’s operations are conducted in the United States.
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Segment financial information as of and for the years ended December 31, 2023 and 2022 have been recast to reflect this change (See Note 17 – Segments).
Cash and cash equivalents
The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents at financial institutions. The balances may exceed the Federal Deposit Insurance Corporation (“FDIC”) insurance coverage and, as a result, there may be a concentration of credit risk related to amounts on deposit in excess of FDIC insurance coverage.
Asset retirement obligations
The fair value of a liability for an asset’s retirement obligations is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. Over time, the liability is accreted for the change in its present value and the capitalized cost is depreciated over the useful life of the related asset. Asset retirement obligations (“ARO”) are periodically adjusted to reflect changes in the estimated present value of the obligation resulting from revisions to the estimated timing or amount of the expected future cash flows. Upon settlement of the obligation, the Company eliminates the liability and, based on the actual cost to retire, may incur a gain or loss.
Escrow account
Proceeds from investors who intend to purchase the Company’s bonds but have not yet closed the transaction are classified as escrow account on the consolidated balance sheets. Amounts are reclassified to debt upon the execution of the subscription agreement and, where applicable, the satisfactory verification of the bondholder’s accreditation.
Accounts receivable
Accounts receivable consists of uncollateralized mineral and royalty income due from third party operators for oil and gas sales to purchasers and receipts from the Company’s mineral and non-operated working interest ownership. It also consists of receivables from crude oil, natural gas and NGL purchasers and joint interest owners on properties operated by PhoenixOp.
In circumstances where the receivables relate to the Company’s mineral and non-operated working interests, purchasers remit payment for production to the operator and the operator, in turn, remits payment to Phoenix Energy for the agreed-to royalties. Receivables are estimated in circumstances where the Company has not received actual information, either due to timing delays or due to the unavailability of data at the time when revenues are recognized. Volume estimates for wells with available historical actual data are based on (i) the historical actual data for months where the data is available or (ii) engineering estimates for months where the historical actual data is not available. Pricing estimates are based upon actual prices realized in an area by adjusting the market price for the average basis differential from market on a basin-by-basin basis.
For receivables from joint interest owners on properties operated by PhoenixOp, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, receivables due to PhoenixOp are collected within two months.
The Company routinely reviews outstanding balances, assesses the financial strength of its customers, and if applicable, would record a reserve for credit losses for amounts not expected to be fully recovered. There was no credit loss reserve as of December 31, 2024, 2023, and 2022.
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Credit risk
Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash and cash equivalents, accounts receivable, revenues and derivative instruments. Revenues are concentrated among operators and purchasers engaged in the energy industry within the United States. By using derivative instruments to economically limit exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties have been determined to have an acceptable credit risk for the size of derivative position placed; therefore, the Company does not require collateral from its counterparties. Management periodically assesses the financial condition of these entities and institutions and considers any possible credit risk to be minimal.
Joint interest
The majority of the Company’s oil and gas exploration, development, and production activities are conducted jointly with other entities and, accordingly, the consolidated financial statements reflect only the Company’s proportionate interest in such activities.
Earnest payments
Earnest payments are deposits paid to oil and gas property owners upon the execution of a purchase and sale agreement or a lease agreement for the acquisition of their interests. These deposits are generally refundable and reclassified to oil and gas properties on the consolidated balance sheets upon successful completion of title review and closing of the transaction, or expensed in the event the transaction is not consummated. Earnest payments expensed for the year ended December 31, 2024 was less than $0.1 million and no earnest payments were expensed for the years ended December 31, 2023 and 2022.
Oil and gas properties
The Company invests in crude oil and natural gas properties, including mineral interests and working interests as a non-operator and operator. Exploration and production activities are accounted for in accordance with the successful-efforts method of accounting. Under this method, costs of acquiring proved mineral interests in crude oil and natural gas properties, development wells, related plant and equipment, and related ARO assets are capitalized. Costs of proved but undeveloped wells are initially capitalized to wells-in-progress until the well becomes productive. Once the well is productive, accumulated capitalized costs are reclassified as proved and producing properties and accounted for following the successful efforts method of accounting. Costs are also capitalized for unevaluated wells that have found crude oil and natural gas reserves even if the reserves cannot be classified as proved when the drilling is completed, provided the unevaluated well has found a sufficient quality of reserves to justify its completion as an economically and operationally viable producing well. If proved reserves are not found, unevaluated well costs are expensed as dry holes. All other unevaluated wells and costs, and all general and administrative costs unrelated to acquisitions are expensed as incurred.
Depletion of capitalized costs is recorded using the units-of-production method based on proved reserves. The depletion rate is determined by dividing the cumulative recovered barrels of oil equivalent by the estimated ultimate recovery by well and averaged amongst all wells within the pooled unit. This rate is multiplied by the original cost basis and reduced by depletion taken in prior periods. The cost basis remaining represents the percentage of the asset remaining to be recovered by the wells within the pooled unit.
Capitalized interest
The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not yet subject to depletion. The amount capitalized is determined by multiplying the weighted-average cost of borrowings by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. Interest is capitalized only for the period that activities are in process to bring the projects to their intended use. The Company capitalized interest costs of $11.8 million and $2.1 million
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
for the years ended December 31, 2024 and December 31, 2023, respectively. No interest cost was capitalized for the year ended December 31, 2022. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depletion.
Equipment and other property
Equipment and other property are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives (ranging from 3 to 7 years) of the respective assets. The costs of normal maintenance and repairs are charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of equipment and other property sold or otherwise disposed of, and the related accumulated depreciation, are removed from the consolidated balance sheet and any gain or loss is reflected in current earnings. These amounts are included in other noncurrent assets on the consolidated balance sheets.
Impairment of long-lived assets
The Company follows the provisions of FASB ASC 360, Property, Plant, and Equipment (“ASC 360”). ASC 360 requires that long-lived assets be assessed for potential impairment of their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Proved oil and natural gas properties are evaluated by geologic basin for potential impairment. In accordance with the successful efforts method of accounting, impairment on proved properties is recognized when the estimated undiscounted projected future net cash flows, or evaluation value using expected future prices of a geologic basin are less than its carrying value. If impairment occurs, the carrying value of the impaired geologic basin is reduced to its estimated fair value.
Unproved oil and natural gas properties do not have producing properties and are valued on acquisition by management, with the assistance of an independent expert when necessary. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers, (i) estimated potential reserves and future net revenues from an independent expert, (ii) its history in exploring the area, (iii) its future drilling plans per its capital drilling program prepared by its reservoir engineers and operations management, and (iv) other factors associated with the area. Impairment is taken on the unproved property value if it is determined that the costs are not likely to be recoverable. The valuation of unproved oil and gas properties is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.
Revenue from contracts with customers
The Company recognizes its revenues following ASC Topic 606, Revenue from Contracts with Customers, (“ASC 606”). The Company’s revenues are primarily derived from its interests in the sale of oil and natural gas production. Oil, natural gas, and NGL sales revenues are generally recognized when control of the product is transferred to the customer, the performance obligations under the terms of the contracts with customers are satisfied and collectability is reasonably assured. In circumstances where the Company is the non-operator or mineral right owner, the Company does not consider itself to have control of the product, and revenues are recognized net of post-production expenses. The performance obligations for the Company’s contracts with customers are satisfied as of a point in time through the delivery of oil and natural gas to its customers. Given the inherent time lag between when oil, natural gas, NGL production and sales occur, and when operators or purchasers often make disbursements to royalty interest owners and due to the large potential fluctuations of both production and sale price, a significant portion of the Company’s revenue may represent accrued revenue based on estimated net sales volumes and estimated selling prices of the commodities.
For crude oil and natural gas produced by PhoenixOp, each delivery order is treated as a separate performance obligation. Revenue is recognized when the performance obligation is satisfied, which typically occurs at the point in time control of the product transfers to the customer. Revenue is measured as the amount the Company expects to receive in exchange for transferring commodities to the customer. The Company’s commodity
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
sales are typically based on prevailing market-based prices. When deliveries contain multiple products, an observable standalone selling price is generally used to measure revenue for each product. Revenues from product sales are presented separately from post-production expenses, including transportation costs, as the Company controls the operated production prior to its transfer to customers.
The Company, through Firebird, provides water disposal services to PhoenixOp and third parties with respect to oil and gas production from wells in which it is the operator. Pricing for such services represents a fixed rate fee based on the quantity of water volume processed. Intercompany charges associated with PhoenixOp’s net interests are eliminated upon consolidation. The proportionate share of fees allocable to third party working interest owners are recognized as revenues over the course of time, as services are performed. Revenues from water services are recognized only when it is probable the Company will collect the consideration it is entitled to in exchange for the services transferred to the customer.
Allocation of transaction price to remaining performance obligations
As the Company has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has utilized the practical expedient in ASC 606, which permits the Company to allocate variable consideration to one or more but not all performance obligations in the contract if the terms of the variable payment related specifically to the Company’s efforts to satisfy that performance obligation and allocating the variable amount to the performance obligation is consistent with the allocation objective under ASC 606. Additionally, the Company will not disclose variable consideration subject to this practical expedient.
Equity-based compensation
The Company accounts for equity-based compensation using the fair value method. The grant-date fair value attributable to the equity awards is calculated based on a combination of an income approach based on the present value of estimated future cash flows, and a market approach based on market data of comparable businesses. Equity awards are granted by Phoenix Equity, the Company’s parent, and are measured at fair value on the date of grant. The Company records equity-based compensation expense and a capital contribution from Phoenix Equity if the requisite service period is deemed to have been rendered and the performance-based condition, if applicable, is probable to be satisfied. Forfeitures are recognized as they occur. For further discussion, see Note 11 – Equity-Based Compensation.
Fair value measurements
The Company follows ASC 820, Fair Value Measurements and Disclosures (“ASC 820”). This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 does not require any new fair value measurements but applies to assets and liabilities that are required to be recorded at fair value under other accounting standards. ASC 820 characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable.
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
The three levels of the fair value measurement hierarchy are as follows:
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3: Measured based on prices or valuation models that required inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).
The carrying values of the Company’s current financial instruments, which include cash and cash equivalents, accounts receivable, accounts payable and accrued and other liabilities, approximated their fair values at December 31, 2024, 2023 and 2022 because of the short-term nature of these instruments. The estimated fair values of the Company’s debt and operating lease liabilities approximated their carrying values using Level 2 fair value inputs as of December 31, 2024, 2023 and 2022. For a discussion of fair value measurements on the Company’s derivatives and asset retirement obligations, refer to Note 6 – Derivatives and Note 7 – Asset Retirement Obligations.
Deferred debt issuance costs
Deferred debt issuance costs represent fees and other direct incremental costs incurred in connection with the Company’s borrowings and offerings of the Company’s debt securities. Upon issuance of the debt, the associated debt issuance costs are reclassified as a discount on the outstanding debt and amortized into interest expense, net of capitalized interest, over the term of the debt using the effective interest method.
Income taxes
The Company is a limited liability company and has elected to be treated as a partnership for income tax purposes. The pro rata share of taxable income or loss is ultimately included in the individual income tax returns of the members of Phoenix Equity, the Company’s parent. Consequently, no provision for incomes taxes is made in the accompanying consolidated financial statements.
The Company remains subject to examination of its U.S. federal partnership tax returns for the tax years ended 2021 through 2024 and its state partnership tax returns for the tax years ended 2020 through 2024. Penalties and interest are classified as selling, general and administrative expense on the consolidated statements of operations.
Recently adopted accounting standards
In November 2023, the FASB issued Accounting Standards Update (“ASU”) 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 requires companies to disclose significant segment expenses, and becomes effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. The Company adopted ASU 2023-07 for the year ended December 31, 2024, and included additional disclosures as required in Note 17 – Segments. There was no impact on our financial position and/or results of operations.
In March 2024, the FASB issued ASU 2024-01, Compensation—Stock Compensation (Topic 718): Scope Application of Profits Interest and Similar Awards (“ASU 2024-01”). ASU 2024-01 provides guidance on how to apply the scope guidance to determine whether profits interests and similar awards should be accounted for as share-based payments arrangements, and becomes effective for fiscal years beginning after December 15, 2024, and interim periods within those annual periods. The Company early adopted ASU 2024-01 effective December 31, 2024 and the adoption did not have a material impact on the Company’s consolidated financial statements. See Note 11 – Equity-Based Compensation for additional information.
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Recent accounting standards not yet adopted
In November 2024, the FASB issued ASU 2024-03, Income Statement—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”). ASU 2024-03 requires companies to provide more detailed disclosures about the disaggregation of income statement expenses. The ASU aims to enhance the transparency and usefulness of financial statements by providing better insight into the components of expense line items, and becomes effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. The Company is currently evaluating the impact of the standard on our financial statements and disclosures.
Accounting pronouncements not listed above were assessed and determined to not have a material impact to the Company’s consolidated financial statements.
Note 3 – Restatement of Prior Year Financial Statements
In December 2023, the Company engaged its current independent registered public accounting firm, Ramirez Jimenez International CPAs, to audit the consolidated financial statements as of and for the year ended December 31, 2022 (the “2022 consolidated financial statements”) in accordance with the standards of the Public Company Accounting Oversight Board (the “PCAOB”). Previously, the 2022 consolidated financial statements were audited by the Company’s former auditor, Cherry Bekaert LLP, in accordance with generally accepted auditing standards in the United States (“GAAS”) (the “2022 GAAS Financials”), as permitted for financial statements to be included in an offering circular for a Tier 2 offering pursuant to Regulation A under the U.S. Securities Act of 1933, as amended. Although Form 1-K permits an issuer to include in such form financial statements audited in accordance with GAAS, the Company was permitted, and elected, under Regulation A to file the 2022 consolidated financial statements audited in accordance with the PCAOB standards (the “2022 PCAOB Financials”). In connection with this audit, the Company and the current auditor determined that there were errors in the 2022 GAAS Financials, primarily due to the calculation of depletion expense resulting from information becoming available subsequent to the issuance of the 2022 GAAS Financials, that are being corrected in the comparative periods of these consolidated financial statements as of and for the year ended December 31, 2024.
Subsequently, the Company restated its 2022 and 2023 consolidated financial statements to correct the accounting treatment for debt issuance costs incurred in connection with the Company’s unregistered bond offerings and capitalized interest. Debt issuance costs were previously expensed immediately and interest costs were not capitalized. The Company corrected these errors in the comparative periods of these consolidated financial statements as of and for the year ended December 31, 2024, such that debt issuance costs associated with the Company’s unregistered bond offerings are deferred and amortized over the weighted average debt term using the effective interest method. Further, interest incurred on expenditures made in connection with the Company’s exploration and development projects not currently subject to depletion are capitalized and subsequently depleted in the same manner as the underlying assets.
The effects of the changes on the Company’s consolidated financial statements as of and for the years ended December 31, 2023 and 2022 are summarized below.
Description of Misstatements
The Company identified the following misstatements in the 2022 GAAS Financials:
Oil and gas properties and asset retirement obligations. The Company identified an error in the calculation of the Company’s estimated retirement costs, which understated the Company’s oil and gas properties (asset additions) and asset retirement obligation liability of $0.1 million and $0.2 million, respectively, as of December 31, 2022.
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Accumulated depletion and impairment. The Company identified an error in the timing of the recognition of depletion expense, which overstated accumulated depletion and impairment by $2.2 million as of December 31, 2022. See discussion of depreciation, depletion, amortization, and accretion below.
Right-of-use assets and operating lease liabilities. The Company adjusted its right-of-use assets to reflect the adoption of ASC 842 Leases (“ASC 842”) for public companies. The right-of-use assets amount was previously based on the Company’s adoption of ASC 842 for non-public companies. The adjustment reduced the right-of-use asset by $0.4 million with a corresponding reduction to current operating lease liabilities and operating lease liabilities of $0.1 million and $0.3 million, respectively.
Accounts payable. The Company identified errors related to the recognition of certain invoices in the proper accounting period, which understated accounts payable by $0.9 million as of December 31, 2022.
Escrow account. The Company identified an error related to the misclassification of the escrow account liability, which was previously classified as a component of long-term debt as of December 31, 2022. See discussion of long-term debt, net of current portion below.
Accrued and other liabilities. The Company identified an error in the calculation of accrued interest, which overstated accrued and other liabilities by $0.9 million as of December 31, 2022, partially offset by a $0.2 million understatement relating to year-end performance bonuses which were not previously accrued.
Long-term debt, net of current portion. See discussion of escrow account above. The remaining difference relates to the classification of bond discount accretion, which was previously classified as a component of accrued interest and accretion in the 2022 GAAS Financials. The Company corrected the classification of unamortized debt discount to be in the same line item as the debt liability.
Members’ equity. The correction of the Company’s misstatements on the consolidated statement of operations for the year ended December 31, 2022 resulted in an increase to members’ equity. See discussion below.
Revenues. The Company identified an error relating to the classification of royalty owner deductions of $3.0 million as an operating expense for the year ended December 31, 2022. The reclassification from operating expense to contra-revenue is a result of the Company’s conclusion that it is acting as the agent under its contracts with customers, and therefore must recognize revenue on a net basis in accordance with ASC 606, Revenue from Contracts with Customers.
Depreciation, depletion, amortization, and accretion: The Company identified an error in the calculation of the depletion expense, which previously excluded NGL reserves. The addition of NGL reserves decreased the depletion rate from 12.4% to 10.4%, which decreased the Company’s depletion expense by $2.2 million.
Payroll and payroll-related expense. The Company had previously not accrued year-end performance bonuses, which resulted in understated payroll and payroll-related expense of $0.2 million for the year ended December 31, 2022. In addition, the Company reclassified $3.8 million of guaranteed payments previously classified as selling, general, and administrative expense to payroll and payroll-related expense on the consolidated statement of operations.
In addition to the items noted herein, the Company identified immaterial errors in periods prior to the year ended December 31, 2022, the impact of which is reflected as an adjustment to beginning member’s equity of less than $0.1 million. The remainder of the notes to the Company’s consolidated financial statements have been updated and restated, as applicable, to reflect the impacts of the restatement described above.
Subsequently, the Company identified the following misstatements in the 2022 and 2023 consolidated financial statements during the first quarter of 2025:
Debt issuance costs. The Company had previously immediately expensed debt issuance costs related to its unregistered bond offerings rather than amortizing them over the weighted-average term of the bonds, which
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
resulted in overstated advertising and marketing expense, selling, general and administrative expense, and payroll and payroll-related expense, and understated interest expense and loss on debt extinguishment on the consolidated statements of operations for the years ended December 31, 2023 and 2022. Long-term debt, net of current portion was overstated by $34.4 million and $4.3 million on the consolidated balance sheets as of December 31, 2023 and 2022, respectively.
Capitalized interest. The Company had previously expensed all interest costs, rather than capitalizing interest incurred on expenditures made in connection with the Company’s exploration and development projects as permitted under ASC 835-20, Capitalized Interest. This resulted in overstated interest expense on the consolidated statement of operations for the year ended December 31, 2023, and a corresponding understatement of oil and gas properties on the consolidated balance sheet as of December 31, 2023. There was no impact to the 2022 consolidated financial statements for capitalized interest.
The following tables present a reconciliation from the figures as previously reported to the restated amounts for the Company’s consolidated balance sheets, statements of operations, statements of cash flows, and statements of changes in equity as of and for the years ended December 31, 2023 and 2022.
Corrected Consolidated Balance Sheets
| December 31, 2023 | ||||||||||||
| (in thousands) | As Previously Reported |
Debt Issuance Costs, Capitalized Interest and Other Corrections |
As Restated | |||||||||
| Oil and gas properties |
$ | 476,264 | $ | 2,075 | $ | 478,339 | ||||||
| Net oil and gas properties |
421,593 | 2,075 | 423,668 | |||||||||
| Total assets |
491,092 | 2,075 | 493,167 | |||||||||
| Long-term debt, net of current portion |
329,519 | (34,352 | ) | 295,167 | ||||||||
| Total liabilities |
532,353 | (34,352 | ) | 498,001 | ||||||||
| Member’s equity (deficit) |
(41,261 | ) | 36,427 | (4,834 | ) | |||||||
| Total liabilities and member’s equity (deficit) |
491,092 | 2,075 | 493,167 | |||||||||
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
| December 31, 2022 | ||||||||||||||||
| (in thousands) | As Previously Reported |
Misstatement Corrections to 2022 GAAS Financials |
Debt Issuance Costs, Capitalized Interest and Other Corrections |
As Restated | ||||||||||||
| Oil and gas properties |
$ | 165,252 | $ | 138 | $ | — | $ | 165,390 | ||||||||
| Accumulated depletion and impairment |
(22,839 | ) | 2,204 | — | (20,635 | ) | ||||||||||
| Net oil and gas properties |
142,413 | 2,342 | — | 144,755 | ||||||||||||
| Right-of-use assets |
2,152 | (354 | ) | — | 1,798 | |||||||||||
| Total assets |
155,013 | 2,007 | — | 157,020 | ||||||||||||
| Accounts payable |
18,583 | 855 | — | 19,438 | ||||||||||||
| Escrow account |
— | 701 | — | 701 | ||||||||||||
| Current operating lease liabilities |
413 | (108 | ) | — | 305 | |||||||||||
| Accrued and other liabilities |
2,908 | (672 | ) | — | 2,236 | |||||||||||
| Total current liabilities |
80,457 | 776 | — | 81,233 | ||||||||||||
| Long-term debt, net of current portion |
64,501 | (684 | ) | (4,336 | ) | 59,481 | ||||||||||
| Accrued interest |
306 | (15 | ) | — | 291 | |||||||||||
| Operating lease liabilities |
1,853 | (256 | ) | — | 1,597 | |||||||||||
| Asset retirement obligations |
62 | 150 | — | 212 | ||||||||||||
| Total liabilities |
152,712 | (29 | ) | (4,336 | ) | 148,347 | ||||||||||
| Member’s equity |
2,301 | 2,036 | 4,336 | 8,673 | ||||||||||||
| Total liabilities and member’s equity (deficit) |
155,013 | 2,007 | — | 157,020 | ||||||||||||
Corrected Consolidated Statements of Operations
| Year ended December 31, 2023 | ||||||||||||
| (in thousands) | As Previously Reported |
Debt Issuance Costs, Capitalized Interest and Other Corrections |
As Restated | |||||||||
| Advertising and marketing |
$ | 36,696 | $ | (32,560 | ) | $ | 4,136 | |||||
| Selling, general and administrative |
19,112 | (4,798 | ) | 14,314 | ||||||||
| Payroll and payroll-related |
18,817 | (6,084 | ) | 12,733 | ||||||||
| Total operating expenses |
129,560 | (43,442 | ) | 86,118 | ||||||||
| Income (loss) from operations |
(11,455 | ) | 43,442 | 31,987 | ||||||||
| Interest expense |
(36,859 | ) | (11,023 | ) | (47,882 | ) | ||||||
| Loss on debt extinguishment |
— | (328 | ) | (328 | ) | |||||||
| Total other expenses |
(36,825 | ) | (11,351 | ) | (48,176 | ) | ||||||
| Net income (loss) |
(48,280 | ) | 32,091 | (16,189 | ) | |||||||
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
| Year ended December 31, 2022 | ||||||||||||||||
| (in thousands) | As Previously Reported |
Misstatement Corrections to 2022 GAAS Financials |
Debt Issuance Costs, Capitalized Interest and Other Corrections |
As Restated | ||||||||||||
| Mineral and royalty revenues |
$ | 57,563 | $ | (3,009 | ) | $ | — | $ | 54,554 | |||||||
| Total revenues |
57,563 | (3,009 | ) | — | 54,554 | |||||||||||
| Cost of sales |
12,582 | (3,009 | ) | — | 9,573 | |||||||||||
| Depreciation, depletion, amortization, and accretion |
14,337 | (2,193 | ) | — | 12,144 | |||||||||||
| Advertising and marketing |
5,350 | — | (3,997 | ) | 1,353 | |||||||||||
| Selling, general, and administrative |
9,356 | (3,793 | ) | — | 5,563 | |||||||||||
| Payroll and payroll-related expenses |
3,412 | 3,965 | (1,354 | ) | 6,023 | |||||||||||
| Total operating expenses |
45,037 | (5,030 | ) | (5,351 | ) | 34,656 | ||||||||||
| Income from operations |
12,526 | 2,021 | 5,351 | 19,898 | ||||||||||||
| Interest expense |
(10,990 | ) | 20 | (923 | ) | (11,893 | ) | |||||||||
| Loss on debt extinguishment |
— | — | (92 | ) | (92 | ) | ||||||||||
| Total other expenses |
(13,229 | ) | 20 | (1,015 | ) | (14,224 | ) | |||||||||
| Net income (loss) |
(703 | ) | 2,041 | 4,336 | 5,674 | |||||||||||
Corrected Consolidated Statements of Changes in Equity
| (in thousands) | As Previously Reported |
Misstatement Corrections to 2022 GAAS Financials |
Debt Issuance Costs, Capitalized Interest and Other Corrections |
As Restated | ||||||||||||
| Balance at December 31, 2021 (As Restated) |
$ | 2,908 | $ | (4 | ) | $ | — | $ | 2,904 | |||||||
| Contributions |
200 | — | — | 200 | ||||||||||||
| Distributions |
(105 | ) | — | — | (105 | ) | ||||||||||
| Net loss (As Restated) |
(703 | ) | 2,041 | 4,336 | 5,674 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Balance at December 31, 2022 (As Restated) |
$ | 2,300 | $ | 2,037 | $ | 4,336 | $ | 8,673 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Balance at December 31, 2022 (As Restated) |
4,337 | — | 4,336 | 8,673 | ||||||||||||
| Contributions |
10,150 | — | — | 10,150 | ||||||||||||
| Distributions |
(7,468 | ) | — | — | (7,468 | ) | ||||||||||
| Net income (As Restated) |
(48,280 | ) | — | 32,091 | (16,189 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Balance at December 31, 2023 (As Restated) |
$ | (41,261 | ) | $ | — | $ | 36,427 | $ | (4,834 | ) | ||||||
|
|
|
|
|
|
|
|
|
|||||||||
F-20
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Corrected Consolidated Statements of Cash Flows
| Year ended December 31, 2023 | ||||||||||||
| (in thousands) | As Previously Reported |
Debt Issuance Costs, Capitalized Interest and Other Corrections |
As Restated | |||||||||
| Net loss |
$ | (48,280 | ) | $ | 32,091 | $ | (16,189 | ) | ||||
| Adjustments to reconcile net loss to net cash used in operating activities: |
||||||||||||
| Amortization of debt discount and debt issuance costs |
656 | 13,097 | 13,753 | |||||||||
| Loss on debt extinguishment |
— | 328 | 328 | |||||||||
| Net cash (used in) provided by operating activities |
(47,342 | ) | 45,516 | (1,826 | ) | |||||||
| Additions to oil and gas properties and leases |
(286,417 | ) | 7,756 | (278,661 | ) | |||||||
| Payments of debt issuance costs |
— | (43,441 | ) | (43,441 | ) | |||||||
| Payments of deferred closings |
6,851 | (9,831 | ) | (2,980 | ) | |||||||
| Net cash provided by financing activities |
334,580 | (53,272 | ) | 281,308 | ||||||||
| Year ended December 31, 2022 | ||||||||||||||||
| (in thousands) | As Previously Reported |
Misstatement Corrections to 2022 GAAS Financials |
Debt Issuance Costs, Capitalized Interest and Other Corrections |
As Restated | ||||||||||||
| Net income (loss) |
$ | (703 | ) | $ | 2,041 | $ | 4,336 | $ | 5,674 | |||||||
| Adjustments to reconcile net income (loss) to net cash used in operating activities: |
||||||||||||||||
| Depreciation, depletion, amortization, and accretion |
14,337 | (2,193 | ) | — | 12,144 | |||||||||||
| Amortization of right-of-use assets |
114 | (10 | ) | — | 104 | |||||||||||
| Amortization of debt discount and debt issuance costs |
1,004 | (987 | ) | 923 | 940 | |||||||||||
| Unrealized loss (gain) on derivatives |
— | (46 | ) | — | (46 | ) | ||||||||||
| Loss on debt extinguishment |
— | — | 92 | 92 | ||||||||||||
| Changes in operating assets and liabilities: |
||||||||||||||||
| Earnest payments |
— | (788 | ) | — | (788 | ) | ||||||||||
| Accounts payable |
321 | 23 | — | 344 | ||||||||||||
| Accrued and other liabilities |
1,006 | 864 | — | 1,870 | ||||||||||||
| Escrow account |
— | 701 | — | 701 | ||||||||||||
| Accrued interest |
868 | (577 | ) | — | 291 | |||||||||||
| Other |
(658 | ) | 705 | — | 47 | |||||||||||
| Net cash provided by operating activities |
13,559 | (268 | ) | 5,351 | 18,642 | |||||||||||
| Additions to oil and gas properties and leases |
(100,224 | ) | 17 | 8,944 | (91,263 | ) | ||||||||||
| Net cash used in investing activities |
(100,849 | ) | 17 | 8,944 | (91,888 | ) | ||||||||||
| Proceeds from issuances of debt, net of discount |
85,136 | (4,388 | ) | (249 | ) | 80,499 | ||||||||||
| Payments of debt issuance costs |
— | — | (5,351 | ) | (5,351 | ) | ||||||||||
| Repayments of debt |
(1,000 | ) | 3,687 | — | 2,687 | |||||||||||
| Payments of deferred closings |
7,653 | 605 | (8,695 | ) | (437 | ) | ||||||||||
| Net cash flows provided by financing activities |
91,884 | (96 | ) | (14,295 | ) | 77,493 | ||||||||||
F-21
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 4 – Oil and Gas Properties
Oil and gas properties, net consist of the following:
| December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Proved oil and natural gas properties(a) |
$ | 687,366 | $ | 371,625 | $ | 123,527 | ||||||
| Unproved oil and natural gas properties |
318,855 | 106,714 | 41,863 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total oil and gas properties |
1,006,221 | 478,339 | 165,390 | |||||||||
| Less: Accumulated depletion and impairment |
(140,376 | ) | (54,671 | ) | (20,635 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Oil and gas properties, net |
$ | 865,845 | $ | 423,668 | $ | 144,755 | ||||||
|
|
|
|
|
|
|
|||||||
| (a) | Represents proved and undeveloped (i.e., wells in progress) and proved and producing properties. |
The Company considers a property proved when geological and engineering data can demonstrate with reasonable certainty that estimated quantities of oil, natural gas, and NGLs can be recoverable from known reservoirs in future periods under the economic and operating conditions (i.e., prices and costs) that exist at the time the estimates are made.
A property is unproved when there are currently no producing wells pooling the property. For the majority of the value of the unproven properties in 2024, the Company has analyzed the wells within a 10-mile radius of the property to conclude the property is economically viable for oil extraction and has the potential to be drilled and become proved reserves.
Depletion on oil and gas properties was $84.8 million, $34.0 million, and $12.0 million for the years ended December 31, 2024, 2023, and 2022, respectively.
Depreciation expense on the Company’s equipment and other property was $0.1 million for the years ended December 31, 2024, 2023, and 2022, respectively.
Impairment
When the Company performs its annual impairment test or circumstances indicate that the proved oil and gas properties may be impaired, the Company compares expected undiscounted future cash flows to the assets’ carrying value grouped by geologic basin. If the undiscounted future cash flows, based on the Company’s estimate of significant Level 3 inputs, including futures prices, anticipated production from proved reserves and other relevant data, are lower than the assets’ carrying value, the carrying value is reduced to fair value. Impairment expense also includes write-offs associated with title defects and lease expirations of the Company’s oil and gas properties, which totaled $0.6 million for the year ended December 31, 2024. In 2023, the Company’s proved natural gas properties with a carrying value of approximately $2.0 million were written down to their fair value of approximately $1.0 million due to a decline in the Henry Hubs future price. Impairment expense of approximately $1.0 million was recognized for the year ended December 31, 2023.
Note 5 – Revenue
Revenue from contracts with customers is presented as mineral and royalty revenues and product sales on the consolidated statements of operations. The Company is paid mineral and royalty revenue monthly by the various operators and working interest owners within the pooled units that the Company owns, and PhoenixOp is paid revenue monthly for the commodities it extracts and delivers to purchasers. Mineral and royalty revenues within the mineral and non-operating segment are presented net of post-production costs charged by the operator, whereas product sales revenue within the operating segment are presented separately from post-production costs, including transportation costs, on the consolidated statements of operations. Other costs, including severance taxes and lease operating expenses are presented as cost of sales on the consolidated statements of operations for both the mineral and non-operating and operating segments.
F-22
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
In 2024, the Company began generating revenues from performing saltwater disposal services on wells in which it is the operator. Revenues are driven primarily by the volumes of produced water and flowback water the Company injects into its saltwater disposal facilities and the fees the Company charges for these services. Fees are charged on a per-barrel basis and are recognized as revenues in accordance with ASC 606.
Other revenue is comprised of redemption fees that are charged to investors, generally upon the early redemption of their investments. For the securities segment, other revenue also includes intersegment interest revenue earned from the mineral and non-operating and operating segments that is eliminated in the consolidated statements of operations.
The following table presents the Company’s revenue from contracts with customers and other revenue for the years ended December 31, 2024, 2023, and 2022 by segment:
| Year Ended December 31, 2024 | ||||||||||||||||||||
| (in thousands) | Mineral and Non-Operating |
Operating | Securities | Eliminations | Total | |||||||||||||||
| Revenue from customers |
$ | 152,999 | $ | 128,127 | $ | — | $ | — | $ | 281,126 | ||||||||||
| Other revenue |
— | — | 101 | — | 101 | |||||||||||||||
| Intersegment revenue |
136 | — | 102,030 | (102,166 | ) | — | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
$ | 153,135 | $ | 128,127 | $ | 102,131 | $ | (102,166 | ) | $ | 281,227 | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Year Ended December 31, 2023 | ||||||||||||||||||||
| (in thousands) | Mineral and Non-Operating |
Operating | Securities | Eliminations | Total | |||||||||||||||
| Revenue from customers |
$ | 116,863 | $ | 1,225 | $ | — | $ | — | $ | 118,088 | ||||||||||
| Other revenue |
— | — | 17 | — | 17 | |||||||||||||||
| Intersegment revenue |
39 | — | 40,492 | (40,531 | ) | — | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
$ | 116,902 | $ | 1,225 | $ | 40,509 | $ | (40,531 | ) | $ | 118,105 | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Year Ended December 31, 2022 | ||||||||||||||||||||
| (in thousands) | Mineral and Non-Operating |
Operating | Securities | Eliminations | Total | |||||||||||||||
| Revenue from customers |
$ | 54,554 | $ | — | $ | — | $ | — | $ | 54,554 | ||||||||||
| Intersegment revenue |
— | — | 4,991 | (4,991 | ) | — | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
$ | 54,554 | $ | — | $ | 4,991 | $ | (4,991 | ) | $ | 54,554 | |||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
The following tables present the Company’s revenue from contracts with customers disaggregated by product type for the periods presented:
| Year Ended December 31, 2024 | ||||||||||||||||||||
| (in thousands) | Mineral and Non-Operating |
Operating | Securities | Eliminations | Total | |||||||||||||||
| Crude oil |
$ | 138,640 | $ | 123,340 | $ | — | $ | — | $ | 261,980 | ||||||||||
| Natural gas sales |
5,424 | 315 | — | — | 5,739 | |||||||||||||||
| NGL |
8,935 | 1,994 | — | — | 10,929 | |||||||||||||||
| Water services |
— | 2,478 | — | — | 2,478 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
$ | 152,999 | $ | 128,127 | $ | — | $ | — | $ | 281,126 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
F-23
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
| Year Ended December 31, 2023 | ||||||||||||||||||||
| (in thousands) | Mineral and Non-Operating |
Operating | Securities | Eliminations | Total | |||||||||||||||
| Crude oil |
$ | 104,631 | $ | 1,140 | $ | — | $ | — | $ | 105,771 | ||||||||||
| Natural gas sales |
6,776 | 14 | — | — | 6,790 | |||||||||||||||
| NGL |
5,456 | 71 | — | — | 5,527 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
$ | 116,863 | $ | 1,225 | $ | — | $ | — | $ | 118,088 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Year Ended December 31, 2022 | ||||||||||||||||||||
| (in thousands) | Mineral and Non-operating |
Operating | Securities | Eliminations | Total | |||||||||||||||
| Crude oil |
$ | 47,493 | $ | — | $ | — | $ | — | $ | 47,493 | ||||||||||
| Natural gas sales |
7,061 | — | — | — | 7,061 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
$ | 54,554 | $ | — | $ | — | $ | — | $ | 54,554 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
The following table summarizes major customers that make up 10% or more of accounts receivable as of December 31, 2024, 2023, and 2022:
| December 31, | ||||||||||||
| 2024 | 2023 | 2022 | ||||||||||
| Customer A |
17 | % | — | % | 34 | % | ||||||
| Customer B |
15 | % | — | % | — | % | ||||||
| Customer C |
13 | % | — | % | — | % | ||||||
| Customer D |
— | % | 26 | % | — | % | ||||||
| Customer E |
— | % | 14 | % | — | % | ||||||
| Customer F |
— | % | — | % | 10 | % | ||||||
The following table summarizes major customers that make up 10% or more of revenue for the years ended December 31, 2024, 2023, and 2022:
| Year Ended December 31, | ||||||||||||
| 2024 | 2023 | 2022 | ||||||||||
| Customer A |
21 | % | — | % | — | % | ||||||
| Customer B |
— | % | 11 | % | 14 | % | ||||||
| Customer C |
— | % | — | % | 16 | % | ||||||
| Customer D |
— | % | — | % | 16 | % | ||||||
| Customer E |
— | % | — | % | 15 | % | ||||||
The Company periodically enters into commodity derivative contracts to manage its exposure to crude oil price risk. Additionally, the Company is required to hedge a portion of anticipated crude oil production for future periods pursuant to its debt covenants under the Fortress Credit Agreement, as further described in Note 8 – Debt. The Company does not enter into derivative contracts for speculative trading purposes.
When the Company utilizes crude oil commodity derivative contracts, it expects to enter into put/call collars, fixed swaps or put options to hedge a portion of its anticipated future production. A collar contract establishes a floor and ceiling price on contracted volumes and provides payment to the Company if the index price falls below the floor or requires payment by the Company if the index price rises above the ceiling. A fixed swap contract sets a fixed price and provides payment to the Company if the index price is below the fixed price or requires payment by the Company if the index price is above the fixed price. A put arrangement gives the Company the right to sell the underlying crude oil commodity at a strike price and provides payment to the Company if the
F-24
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
index price falls below the strike price. No payment or receipt occurs if the index price is higher than the strike price. As of December 31, 2024, the Company’s derivatives were comprised of crude oil commodity derivative contacts indexed to the U.S. New York Mercantile Exchange West Texas Intermediate (“WTI”). The Company has not designated its derivative contracts for hedge accounting and, as a result, records the net change in the mark-to-market valuation of the derivative contracts and all payments and receipts on settled derivative contracts in its consolidated statements of operations. All derivative contracts are recorded at fair market value and included in the consolidated balance sheets as assets or liabilities. Derivative assets and liabilities are presented net on the consolidated balance sheets when a legally enforceable master netting arrangement exists with the counterparty.
As of December 31, 2024, the Company’s open crude oil derivative contracts consisted of the following:
| Settlement Period | ||||||||||||
| (volumes in Bbl and prices in $/Bbl) | 2025 | 2026 | 2027 | |||||||||
| Two-Way Collars |
||||||||||||
| Notional Volumes |
624,900 | 367,700 | 259,000 | |||||||||
| Weighted Average Ceiling Price |
$ | 76.02 | $ | 71.69 | $ | 69.86 | ||||||
| Weighted Average Floor Price |
$ | 59.35 | $ | 56.01 | $ | 57.42 | ||||||
| Swaps |
||||||||||||
| Notional Volumes |
2,174,200 | 1,260,000 | 894,000 | |||||||||
| Weighted Average Contract Price |
$ | 68.86 | $ | 64.62 | $ | 63.07 | ||||||
The following table summarizes the gains and losses on derivative instruments included on the consolidated statements of operations and the net cash payments thereto for the periods presented. Cash flows associated with these non-hedge designated derivatives are reported within operating activities on the consolidated statements of cash flows.
| Year Ended December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Loss on derivative instruments |
$ | (5,986 | ) | $ | (32 | ) | $ | (2,239 | ) | |||
| Net cash receipts (payments) on derivatives |
1,532 | 100 | (1,328 | ) | ||||||||
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The fair values of the Company’s derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.
F-25
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2024, 2023 and 2022. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. Current derivative assets are presented as other current assets and current derivative liabilities are presented as a component of accrued and other liabilities on the consolidated balance sheets.
| December 31, 2024 |
||||||||||||||||||||||||||
| (in thousands) | Balance Sheet Location |
Level 1 | Level 2 | Level 3 | Total Gross Fair Value |
Gross Amounts Offset in Balance Sheet |
Net Fair Value Presented in Balance Sheet |
|||||||||||||||||||
| Assets |
||||||||||||||||||||||||||
| Commodity derivatives |
Other current assets | $ | — | $ | 2,138 | $ | — | $ | 2,138 | $ | (2,037 | ) | $ | 101 | ||||||||||||
| Commodity derivatives |
Other noncurrent assets | — | 3,000 | — | 3,000 | (3,000 | ) | — | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| $ | — | $ | 5,138 | $ | — | $ | 5,138 | $ | (5,037 | ) | $ | 101 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| Liabilities |
||||||||||||||||||||||||||
| Commodity derivatives |
Accrued and other liabilities | $ | — | $ | (4,574 | ) | $ | — | $ | (4,574 | ) | $ | 2,037 | $ | (2,537 | ) | ||||||||||
| Commodity derivatives |
Other noncurrent liabilities | — | (7,858 | ) | — | (7,858 | ) | 3,000 | (4,858 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| $ | — | $ | (12,432 | ) | $ | — | $ | (12,432 | ) | $ | 5,037 | $ | (7,395 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| December 31, 2023 |
||||||||||||||||||||||||||
| (in thousands) | Balance Sheet Location |
Level 1 | Level 2 | Level 3 | Total Gross Fair Value |
Gross Amounts Offset in Balance Sheet |
Net Fair Value Presented in Balance Sheet |
|||||||||||||||||||
| Assets |
||||||||||||||||||||||||||
| Commodity derivatives |
Other current assets | $ | — | $ | 71 | $ | — | $ | 71 | $ | — | $ | 71 | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| $ | — | $ | 71 | $ | — | $ | 71 | $ | — | $ | 71 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| Liabilities |
||||||||||||||||||||||||||
| Commodity derivatives |
Accrued and other liabilities | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| December 31, 2022 |
||||||||||||||||||||||||||
| (in thousands) | Balance Sheet Location |
Level 1 | Level 2 | Level 3 | Total Gross Fair Value |
Gross Amounts Offset in Balance Sheet |
Net Fair Value Presented in Balance Sheet |
|||||||||||||||||||
| Assets |
||||||||||||||||||||||||||
| Commodity derivatives |
Other current assets | $ | — | $ | 18 | $ | — | $ | 18 | $ | (18 | ) | $ | — | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| $ | — | $ | 18 | $ | — | $ | 18 | $ | (18 | ) | $ | — | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| Liabilities |
||||||||||||||||||||||||||
| Commodity derivatives |
Accrued and other liabilities | $ | — | $ | (20 | ) | $ | — | $ | (20 | ) | $ | 18 | $ | (2 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
| $ | — | $ | (20 | ) | $ | — | $ | (20 | ) | $ | 18 | $ | (2 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Note 7 – Asset Retirement Obligations
The Company’s asset retirement obligations relate to the future plugging and abandonment of wells and related facilities. As of December 31, 2024, 2023 and 2022, the net present value of the total ARO was estimated to
F-26
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
be $1.3 million, $0.6 million and $0.2 million, respectively, with the undiscounted value being $12.9 million, $7.7 million and $2.7 million, respectively. Total ARO shown in the table below consists of amounts for future plugging and abandonment liabilities on wellbores in which the Company has a working interest or are operated by the Company, adjusted for inflation at a rate of 2.56%, 2.50% and 2.55% per annum as of December 31, 2024, 2023 and 2022, respectively. These values are discounted to present value using a rate of 10.0% per annum for the years ended December 31, 2024, 2023 and 2022.
The following table summarizes the changes in the ARO for the periods presented:
| Year Ended December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Asset retirement obligations at beginning of period |
$ | 697 | $ | 212 | $ | 40 | ||||||
| Additions |
1,430 | 430 | 155 | |||||||||
| Derecognition |
(975 | ) | — | — | ||||||||
| Accretion |
180 | 55 | 17 | |||||||||
| Revisions in estimated cash flows |
15 | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
| Asset retirement obligations at end of period(a) |
$ | 1,347 | $ | 697 | $ | 212 | ||||||
|
|
|
|
|
|
|
|||||||
| (a) | Current ARO is classified as a component of accrued and other liabilities and noncurrent ARO is classified as asset retirement obligations on the consolidated balance sheets. As of December 31, 2024 and 2023, current ARO was approximately $0.2 million and $0.1 million, respectively, and noncurrent ARO was approximately $1.2 million and $0.6 million, respectively. |
ARO is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging costs, remediation costs, inflation rate, and well life. The inputs are calculated based on historical data as well as current estimated costs.
Short-Term Debt
Amarillo National Bank Credit Agreement
In July 2023, the Company entered into a one-year credit agreement with Amarillo National Bank (“ANB”) for a $30.0 million revolving line of credit (the “ANB Credit Agreement”). The Company fully repaid the ANB Credit Agreement in August 2024 with proceeds received from the Fortress Term Loan, as further described below. The ANB Credit Agreement bore interest at the Wall Street Journal’s prime rate plus 3.0% per annum, with a floor of 9.0% per annum. Interest expense of $2.1 million and $1.5 million was attributable to the ANB Credit Agreement for the years ended December 31, 2024 and 2023, respectively. There was no outstanding balance under the ANB Credit Agreement as of December 31, 2024. As of December 31, 2023, the outstanding balance of the ANB Credit Agreement was $19.1 million.
Merchant Cash Advances
In December 2024, Phoenix Energy fully repaid its outstanding balances under the merchant cash advance agreements it had entered into with several financial institutions. The Company sold its future receivables for cash advances under these agreements, which were short-term and required the Company to repay the advances on a weekly or bi-weekly basis. Repayment amounts incorporated factor rates, which indicate the percentage of the loan amount that is to be repaid, ranging from 1.17 to 1.23 for merchant cash advances outstanding of $6.7 million as of December 31, 2023, and 1.15 to 1.33 for merchant cash advances outstanding of $6.8 million as of December 31, 2022. Interest expense attributable to the merchant cash advances was $3.0 million, $2.5 million, and $2.9 million for the years ended December 31, 2024, 2023 and 2022, respectively.
F-27
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Long-Term Debt
The following table summarizes the Company’s long-term debt for the periods presented:
| Maturity Date | December 31, | |||||||||||||||||||||||
| (in thousands) | Earliest Date |
Latest Date | Interest Rate(a) | 2024 | 2023 | 2022 | ||||||||||||||||||
| Unsecured debt - Regulation D |
1/10/2025 | 12/10/2035 | 5.0% to 15.0% | $ | 497,823 | $ | 313,681 | $ | 46,979 | |||||||||||||||
| Unsecured debt - Regulation A |
1/10/2025 | 8/10/2027 | 9.0% | 104,884 | 85,250 | 35,868 | ||||||||||||||||||
| Adamantium Securities |
1/10/2029 | 12/10/2035 | 13.0% to 16.5% | 135,180 | 22,824 | — | ||||||||||||||||||
| Fortress Term Loan |
— | 12/18/2027 | Term SOFR + 7.10% | 250,000 | — | — | ||||||||||||||||||
| Cortland Line of Credit |
— | — | —% | — | — | 23,000 | ||||||||||||||||||
| Cortland Term Loan |
— | — | —% | — | — | 3,833 | ||||||||||||||||||
| Other |
— | 289 | 369 | |||||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||
| Total outstanding debt |
987,887 | 422,044 | 110,049 | |||||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||
| Less: Unamortized debt discount and issuance costs(b) |
(89,432 | ) | (39,839 | ) | (4,529 | ) | ||||||||||||||||||
| Less: Current portion of long-term debt |
(103,240 | ) | (87,038 | ) | (46,039 | ) | ||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||
| Total long-term debt, net of current portion |
$ | 795,215 | $ | 295,167 | $ | 59,481 | ||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||
| (a) | Represents the contractual interest rate as of December 31, 2024. |
| (b) | Amortized into interest expense using the effective interest method. Write-offs of debt issuance costs associated with the redemption of bonds issued under the Company’s unregistered debt offerings are classified as loss on debt extinguishment in the consolidated statements of operations. |
The following table summarizes the aggregate contractual annual maturities for the Company’s long-term debt outstanding as of December 31, 2024, excluding unamortized debt discount and issuance costs:
| (in thousands) |
||||
| Year Ending December 31, |
Amount | |||
| 2025 |
$ | 103,319 | ||
| 2026 |
203,279 | |||
| 2027 |
212,976 | |||
| 2028 |
14,724 | |||
| 2029 |
43,700 | |||
| Thereafter |
409,889 | |||
|
|
|
|||
| Total |
$ | 987,887 | ||
|
|
|
|||
Unsecured Debt
Phoenix Energy has several bond offerings issued under Regulation A and Rule 506(c) of Regulation D of federal securities law. Under the federal securities laws, any offer or sale of a security must be registered with the Securities Exchange Commission (“SEC”) or qualify for an exemption. Regulation A and Regulation D provide certain exemptions from the registration requirements, which allow companies to offer and sell their securities without having to register the offering with the SEC. The Company first commenced its bond offerings pursuant to Regulation D in July 2020, and subsequently Regulation A in December 2021, and have since issued a cumulative combined total of $948.5 million of debt to investors from inception through December 31, 2024. The bonds have terms ranging from one to eleven years. In instances where interest is compounded, interest is accrued monthly. Interest expense attributable to these bonds totaled $60.7 million, $29.5 million, and $4.1 million for the years ended December 31, 2024, 2023, and 2022 respectively.
In March 2024, the Company filed an amendment to the Form 1-A that was originally qualified by the SEC in December 2021 (as amended) to update the maximum offering available for sale of the Company’s 9.0% unsecured bonds. This amendment offered up to $31.7 million of the Company’s bonds, which, under Regulation A, represented the maximum that could be offered out of the $75.0 million limit on securities the Company was authorized to issue over a rolling twelve-month period. The Company issued $31.6 million of Regulation A bonds during the year ended December 31, 2024, of which $1.8 million was subsequently early redeemed.
F-28
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Adamantium Securities
In September 2023, the Company, through its wholly-owned subsidiary, Adamantium, commenced an offering of bonds exempt from registration pursuant to Rule 506(c) of Regulation D (the “Adamantium Bonds”). The Adamantium Bonds offer high net worth individuals a debt instrument that is unsecured but structurally senior to other bonds sold by the Company under Regulation A and Regulation D. The Adamantium Bonds have maturity terms that range from five to eleven years and bear interest ranging from 13.0% to 16.5% per annum. In November 2024, Adamantium issued a $7.0 million seven-year promissory note to an investor bearing interest at 16.5% per annum (the “Adamantium Secured Note,” and together with the Adamantium Bonds, “the Adamantium Securities”). The Adamantium Securities contain customary events of default and may be redeemed at the option of Adamantium at any time without premium or penalty. The holders of Adamantium Bonds also have a right to request redemption of their bonds in certain circumstances at a discount to par, subject to a limit of 10% of the then-outstanding principal amount of Adamantium Bonds in any given calendar year. The holder of the Adamantium Secured Note has the right to request redemption of its note at par, subject to a limit of $5.0 million in aggregate principal amount of the Adamantium Secured Note in any 12-month period.
Cortland Credit Line of Credit and Term Loan
In October 2021, the Company obtained a $23.0 million revolving line of credit with Cortland Credit Lending Corporation (“Cortland”) due in October 2023 (the “Cortland Line of Credit”). The Cortland Line of Credit accrued interest at a variable rate per annum equal to the greater of (a) 10.50% or (b) the TD Bank US Prime Rate plus 7.25% and was payable monthly. Subsequently, in October 2022, the Company issued a $5.0 million five-year term loan with Cortland bearing the same interest rate as the Cortland Line of Credit, plus an additional fixed fee of $83,333 per month.
In April 2023, the Company agreed to a “term out” of its existing obligations with Cortland and converted the line of credit and term loan into a $26.8 million term loan maturing in January 2024 (the “Cortland Term Loan”). The Company was required to repay the Cortland Term Loan in ten equal payments of $2.7 million per month, plus interest. There were no changes to the interest rate terms resulting from the term out conversion. In July 2023, the Company fully repaid the Cortland Term Loan with the proceeds of the ANB Credit Agreement (as defined above). Interest expense attributable to Cortland of $2.1 million and $3.3 million was recognized for the years ended December 31, 2023 and 2022, respectively. Prior to the repayment, our obligations under the credit agreements with Cortland were collateralized by the Company’s oil and gas properties.
Fortress Credit Agreement
In August 2024, the Company entered into a secured credit agreement (the “Fortress Credit Agreement”) with Fortress Credit Corp. (“Fortress”) for a $100.0 million term loan facility (the “Fortress Term Loan”), borrowed in full upon closing, and a $35.0 million delayed draw term loan facility (the “DDTL Facility”) that was subsequently drawn in October 2024. In December 2024, the Company entered into an amendment with Fortress which provided for a new tranche of term loans in an aggregate principal amount of $115.0 million (the “Fortress Tranche C Loan” and, together with the Fortress Term Loan and the DDTL Facility, the “Fortress Loans”) that was borrowed in full immediately upon closing. The proceeds from the Fortress Loans were used, in part, to pay all amounts owed under the ANB Credit Agreement. The remaining proceeds are being used for the development of the Company’s oil and gas properties in accordance with the approved plan of development provided in the Fortress Credit Agreement. Debt issuance costs of $4.3 million, together with the $7.5 million debt discount associated with the Fortress Loans, are amortized to interest expense over the term of the loan.
The Fortress Loans bear interest at a rate per annum equal to Term Secured Overnight Financing Rate (“SOFR”) plus a margin of 7.1%, which is due and payable at the last day of each fiscal quarter. As of December 31, 2024, the all-in interest rate was 11.7%. The amendment the Company entered into December 2024 extended the
F-29
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
maturity date from August 2027 to December 2027 and revised the repayment schedule such that at least $125.0 million of the outstanding principal is to be repaid by December 2026, with the remainder due upon maturity. Additionally, in connection with any payment in full of the Fortress Loans, the Company is required to pay a repayment premium in an amount that achieves a multiple on invested capital of 1.18, as defined in the Fortress Credit Agreement.
The Fortress Credit Agreement also includes an $8.5 million tranche of loans (the “Tranche B Loan”), which represents a contingent principal obligation that is only due and payable (together with accrued interest thereon) upon certain conditions occurring, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing by the Company. No value was attributed to this embedded feature as this feature was determined to be triggered by events with only a remote probability of occurrence.
Loans under the Fortress Credit Agreement are secured by substantially all of the assets of Phoenix Energy, PhoenixOp and certain of the Company’s other wholly-owned subsidiaries. The Fortress Credit Agreement also contains various customary affirmative and negative covenants, including financial covenants that require the Company to maintain (a) a maximum total secured leverage ratio as of the last day of any fiscal quarter ending on or before December 31, 2025 of less than or equal to 2.00 to 1.00 (commencing with the fiscal quarter ending December 31, 2024) and (i) as of the last day of any fiscal quarter ending on or after March 31, 2026 of less than or equal to 1.50 to 1.00, (b) a minimum current ratio as of the last day of each calendar month of (i) 0.90 to 1.00 from September 30, 2024 through October 31, 2024, (ii) 0.80 to 1.00 from November 30, 2024 through November 30, 2025, (iii) 0.90 to 1.00 from December 31, 2025 through December 31, 2026 and (iv) 1.00 to 1.00 for each calendar month ending thereafter and (c) a minimum asset coverage ratio as of the last day of any fiscal quarter of at least 2.00 to 1.00. Additionally, the Fortress Credit Agreement requires the Company to enter into and maintain through September 30, 2025, hedges covering at least 75% of the initially anticipated monthly production of crude oil from the Company’s proved developed reserves for a 36-month period. See Note 6 – Derivatives. As of December 31, 2024, we were in compliance with all covenants contained in the Fortress Credit Agreement.
Interest Expense on Debt
The following table presents the total interest expense incurred on the Company’s debt:
| Year Ended December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Stated interest |
$ | 85,409 | $ | 36,204 | $ | 10,953 | ||||||
| Amortization of debt discount and debt issuance costs |
16,621 | 13,753 | 940 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total interest cost |
102,030 | 49,957 | 11,893 | |||||||||
| Capitalized interest |
(11,820 | ) | (2,075 | ) | — | |||||||
|
|
|
|
|
|
|
|||||||
| Total interest expense, net |
$ | 90,210 | $ | 47,882 | $ | 11,893 | ||||||
|
|
|
|
|
|
|
|||||||
F-30
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 9 – Accrued and Other Liabilities
The following table summarizes the Company’s accrued and other liabilities for the periods presented:
| December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Accrued capital expenditures and lease operating expenses |
$ | 37,150 | $ | 1,373 | $ | 959 | ||||||
| Revenue payables |
4,441 | 383 | — | |||||||||
| Accrued personnel costs |
4,316 | 803 | 161 | |||||||||
| Advances from joint interest partners |
4,105 | 1,785 | — | |||||||||
| Current derivative liabilities |
2,537 | — | 2 | |||||||||
| Accrued interest |
1,746 | 1,873 | 108 | |||||||||
| Unredeemed matured bonds |
1,338 | — | — | |||||||||
| Asset retirement obligations |
165 | 112 | — | |||||||||
| Other |
1,549 | 59 | 1,006 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total |
$ | 57,346 | $ | 6,388 | $ | 2,236 | ||||||
|
|
|
|
|
|
|
|||||||
Accrued capital expenditures and lease operating expenses are primarily associated with drilling, completion and operating activities on wells operated by PhoenixOp. As of December 31, 2024, PhoenixOp had placed 32 wells into production and had an additional 39 wells in various stages of development.
In circumstances where the Company serves as the operator, the Company receives production proceeds from the purchaser and distributes the amounts to other royalty owners based on their respective ownership interests. Production proceeds that the Company has not yet distributed to these owners are reflected as revenue payables and classified as a component of accrued and other liabilities in the consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.
Note 10 – Deferred Closings
Deferred closings represent agreements entered into by the Company with mineral interest owners that provide for the acquisition price to be paid in installments. Deferred closing arrangements have terms ranging from 11 to 48 months and interest rates ranging from 8.0% to 15.0% per annum. Interest is accrued on a quarterly basis.
The following table summarizes the aggregate annual contractual settlements for the Company’s deferred closing arrangements as of December 31, 2024:
| (in thousands) | ||||
| Year Ending December 31, |
Amount | |||
| 2025 |
$ | 7,189 | ||
| 2026 |
3,260 | |||
| 2027 |
64 | |||
| 2028 |
— | |||
| 2029 |
— | |||
| Thereafter |
— | |||
|
|
|
|||
| Total |
$ | 10,513 | ||
|
|
|
|||
Note 11 – Equity-Based Compensation
In December 2024, the Company adopted the 2024 Long-Term Incentive Plan (the “2024 Incentive Plan”). Under the 2024 Incentive Plan, Phoenix Equity, the Company’s parent, may grant awards to service providers of the Company, which may be paid in units, cash, or other property, as determined by each individual award agreement. Unit awards may be granted with performance conditions and service conditions, depending on the individual award, and may be subject to vesting or other terms. Performance conditions are contingent on the specified
F-31
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
condition being met, whereby service conditions depend solely on the employee rendering service to the Company for the requisite service period as defined within each individual award agreement. The 2024 Incentive Plan provides for the issuance of Class A Units, Class B Units and Phantom Units of Phoenix Equity’s interests to service providers of the Company, including employees and independent contractors. Each of the Class A, B and Phantom Units are entitled to distributions to the extent such distributions are declared by Phoenix Equity. No distributions have been declared or paid to date. As of December 31, 2024, 0.9 million of Class A Units and 2.8 million of Class B Units were authorized and issued to employees, and 1.0 million Phantom Units were authorized but not yet issued.
The 2024 Incentive Plan superseded and replaced all prior incentive plans, and resulted in the cancellation and termination of any previously outstanding awards, wherein 2.4 million previously granted unit awards to 10 grantees were canceled and regranted. Regranted unit awards included updated terms and conditions, including updated performance and service vesting conditions. However, with respect to 289,290 Class A units and 249,460 Class B units, no new vesting conditions were added, and upon the cancellation and regrant, the Company recognized no additional equity-based compensation expense for these vested unit awards for the year ended December 31, 2024.
A summary of the activity under the 2024 Incentive Plan as of December 31, 2024, and changes during the year then ended, is presented below.
| Number of Units |
Weighted Average Per Share Grant Date Fair Value |
|||||||
| Nonvested at December 31, 2023 |
— | $ | — | |||||
| Granted - Class A Units |
610,710 | 55.74 | ||||||
| Granted - Class B Units |
2,564,440 | 55.74 | ||||||
| Vested |
— | — | ||||||
| Forfeited |
— | — | ||||||
|
|
|
|||||||
| Nonvested at December 31, 2024 |
3,175,150 | |||||||
|
|
|
|||||||
During the year ended December 31, 2024, Phoenix Equity granted 0.6 million Class A unit awards and 2.6 million Class B unit awards contingent on the achievement of a performance condition (the “performance unit awards”), all of which will only vest upon the Company undergoing a liquidity event (e.g., change in control). No compensation cost will be recognized for the performance unit awards until a liquidity event occurs. The Company has elected to account for forfeitures as they occur.
As of December 31, 2024, there was $177.0 million of total unrecognized compensation cost related to nonvested performance unit awards granted under the 2024 Incentive Plan, measured based on the fair value of the awards; that cost is expected to be recognized at the time a liquidity event occurs.
The fair value of each unit granted under the 2024 Incentive Plan was valued on the date of grant under an independent third-party valuation, which included a combination of an income approach, based on the present value of estimated future cash flows, and a market approach based on market data of comparable businesses. The weighted-average assumptions used in the valuation of performance unit awards granted for the year ended December 31, 2024, are presented in the table below:
| 2024 | ||||
| Dividend yield(a) |
— | % | ||
| Risk-free interest rate(b) |
4.38 | % | ||
| Expected volatility(c) |
57.50 | % | ||
| Expected term (in years)(d) |
5.00 | |||
| Discount for lack of marketability(e) |
30.00 | % | ||
| (a) | The Company has no history or expectation of paying cash dividends on its awards. |
| (b) | The risk-free interest rate is based on the U.S. Treasury yield for a term consistent with the expected life of the awards in effect at the time of grant. |
| (c) | Volatility was estimated based on the different interests being appraised, leveraging historical volatility for comparable publicly traded organizations within its industry. The Company lacks company-specific historical and implied volatility information. Therefore, it estimates its expected stock volatility based on the historical volatility of a publicly traded set of peer companies within the industry with characteristics similar to the Company. |
| (d) | The expected term represents the estimated period, in years, until a liquidity event occurs. |
| (e) | Discount for lack of marketability was determined using the Restricted Stock Studies, Chaffee Put Option, Finnerty’s Put Option, and Qualitative Mandelbaum Factor approaches. |
F-32
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 12 – Related Parties
Debt Offerings
Certain of the Company’s executives and their family members participate in the Company’s unregistered debt offerings. During the years ended December 31, 2024, 2023, and 2022, these officers and their family members purchased, in aggregate, 4,458, 2,847 and 924 of the combined Regulation A+ and Regulation D bonds, respectively, for a total purchase price of $4.4 million, $2.8 million and $0.9 million. Interest expense attributable to these securities was $0.5 million, $0.2 million, and less than $1.0 million for the years ended December 31, 2024, 2023, and 2022, respectively. As of December 31, 2024, 2023, and 2022, there were 2,860, 2,055, and 759 of bonds outstanding with carrying values of $2.9 million, $2.0 million, and $0.8 million, respectively.
Lion of Judah
The Company paid interest expense of less than $0.2 million to a financial institution on behalf of Lion of Judah related to a certain financing agreement between Lion of Judah and the financial institution for the year ended December 31, 2024. No such payments were made in the prior periods. Interest payments made by the Company on behalf of Lion of Judah are discretionary in nature.
The Company leases its office facilities under noncancelable multi-year operating lease agreements. The Company determines whether a contract contains a lease at inception by determining if the contract conveys the right to control the use of identified office space for a period of time in exchange for consideration. The Company’s lease agreements contain lease and non-lease components, which are generally accounted for separately with amounts allocated to the lease and non-lease components based on relative stand-alone prices.
Right of use (“ROU”) assets and lease liabilities are recognized at the commencement date based on the present value of the future minimum lease payments over the lease term. Renewal and termination clauses that are factored into the determination of the lease term if it is reasonably certain that these options would be exercised by the Company. Lease assets are amortized over the lease term unless there is a transfer of title or purchase option reasonably certain of exercise, in which case the asset life is used. The Company’s lease agreements include variable payments. Variable lease payments not dependent on an index or rate primarily consist of common area maintenance charges and are not included in the calculation of the ROU asset and lease liability and are expensed as incurred. In order to determine the present value of lease payments, the Company uses the implicit rate when it is readily determinable or the Company’s incremental borrowing rate based on the Company’s existing line of credit facilities.
The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants. As of December 31, 2024, the Company does not have leases where it is involved with the construction or design of an underlying asset, has no material obligation for leases signed but not yet commenced and does not have any material sublease activities.
F-33
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
The following table summarizes the Company’s future minimum lease payments as of December 31, 2024:
| (in thousands) | ||||
| Year Ending December 31, |
Amount | |||
| 2025 |
$ | 1,293 | ||
| 2026 |
1,328 | |||
| 2027 |
1,329 | |||
| 2028 |
1,262 | |||
| 2029 |
1,218 | |||
| Thereafter |
3,047 | |||
|
|
|
|||
| Total lease payments |
9,477 | |||
| Less: interest |
(2,961 | ) | ||
|
|
|
|||
| Present value of lease liabilities |
$ | 6,516 | ||
|
|
|
|||
The following table shows the line item classification of our right-of-use assets and lease liabilities on the Company’s consolidated balance sheets:
| December 31, | ||||||||||||||
| (in thousands) | Line item |
2024 | 2023 | 2022 | ||||||||||
| Right-of-use assets – operating |
Right of use assets, net | $ | 6,010 | $ | 4,542 | $ | 1,798 | |||||||
|
|
|
|
|
|
|
|||||||||
| Total right-of-use assets |
$ | 6,010 | $ | 4,542 | $ | 1,798 | ||||||||
|
|
|
|
|
|
|
|||||||||
| Current operating lease liabilities |
Current operating lease liabilities | $ | 656 | $ | 567 | $ | 305 | |||||||
| Noncurrent operating lease liabilities |
Operating lease liabilities | 5,860 | 4,225 | 1,597 | ||||||||||
|
|
|
|
|
|
|
|||||||||
| Total lease liabilities |
$ | 6,516 | $ | 4,792 | $ | 1,902 | ||||||||
|
|
|
|
|
|
|
|||||||||
| Weighted average remaining lease term (in years) |
7.16 | 6.29 | 5.43 | |||||||||||
| Weighted average discount rate |
10.29 | % | 9.16 | % | 9.16 | % | ||||||||
| Year Ended December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Operating leases(a) |
$ | 1,393 | $ | 1,168 | $ | 211 | ||||||
| Short-term leases(a) |
— | 138 | 232 | |||||||||
| Variable lease payments(a) |
83 | 20 | 2 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net operating lease cost |
$ | 1,476 | $ | 1,326 | $ | 445 | ||||||
|
|
|
|
|
|
|
|||||||
| (a) | Expenses are classified within selling, general and administrative expense on the consolidated statements of operations. |
Note 14 – Defined Contribution Plan
The Company has a 401(k) defined contribution plan which permits participating employees to defer up to a maximum of 100% of their compensation, subject to limitations established by the Internal Revenue Service. In January 2024, the Company began providing matching contributions of up to 3.0% of the employees’ compensation which vest ratably over a three-year period. The Company recognized compensation cost of $0.2 million related to its contributions to the plan for the year ended December 31, 2024.
F-34
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Note 15 – Commitments and Contingencies
For a summary of the Company’s lease obligations, see Note 13 – Leases.
Litigation
From time to time, the Company may become involved in other legal proceedings or be subject to claims arising in the ordinary course of business. Although the results of ordinary course litigation and claims cannot be predicted with certainty, the Company currently believes that the final outcome of these ordinary course matters will not have a material adverse effect on its business, financial condition, results of operations or cash flows. Regardless of the outcome, litigation can have an adverse impact because of defense and settlement costs, diversion of management resources and other factors.
Drilling Rig Contracts
The Company has entered into drilling rig contracts to procure drilling services for wells operated by PhoenixOp. The contracts are short-term and provide a daily operating rate as consideration for services performed by the third-party provider. As of December 31, 2024, the Company was subject to $8.4 million of commitments under these contracts.
Crude Oil Delivery Commitments
The Company, through PhoenixOp, is subject to an arrangement pursuant to which it has committed to provide a total of 3.65 million barrels of crude oil, with a yearly minimum of 730,000 barrels of crude oil, from January 2024 to December 2028. The Company is subject to a shortfall fee in the event it fails to meet this commitment. No shortfalls have occurred to date. As a part of this arrangement, PhoenixOp has dedicated to the counterparty certain rights to all oil extracted from its wells in certain properties in North Dakota. The Company delivered 2.3 million barrels of crude oil during the year ended December 31, 2024, and the remaining aggregate commitment under the contract as of December 31, 2024 is approximately 1.4 million barrels of crude oil.
Note 16 – Supplemental Information to Consolidated Statements of Cash Flows
The following table summarizes supplemental information to the consolidated statements of cash flows for the periods presented:
| Year Ended December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Supplemental disclosure of cash flow information: |
||||||||||||
| Cash interest paid, net of capitalized interest |
$ | 42,700 | $ | 23,802 | $ | 9,723 | ||||||
| Cash paid for operating leases |
927 | 569 | 188 | |||||||||
| Supplemental disclosure of non-cash transactions: |
||||||||||||
| Capital expenditures in accounts payable and accrued and other liabilities |
$ | 29,895 | $ | 25,002 | $ | 15,746 | ||||||
| Modification of right-of-use asset and lease liability |
1,608 | — | — | |||||||||
| Right-of-use asset obtained in exchange for lease liability |
503 | 3,166 | 1,902 | |||||||||
Segment operating profit is used as a performance metric by the CODM in determining how to allocate resources and assess performance as this measure provides insight into the segments’ operations and overall success of a segment for a given period. Segment operating profit is calculated as total segment revenue less operating costs attributable to the segment, which includes allocated corporate costs that are overhead in nature and not directly associated with the segments, such as certain general and administrative expenses, executive or shared-function payroll costs and certain limited marketing activities. Corporate costs are allocated to the segments based on usage
F-35
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
and headcount, as appropriate. Segment operating profit excludes other income and expense, such as interest expense, interest income, gain (loss) on derivatives, loss on debt extinguishment, even though these amounts are allocated to the segments and provided to the CODM. Transactions between segments are accounted for on an accrual basis and are eliminated upon consolidation. Interest expense is allocated to the segments based on the carrying value of the oil and gas properties owned by the respective segment at the balance sheet date, and interest income and gain (loss) on derivatives are allocated using the same basis as corporate costs.
The following table summarizes segment operating profit (loss) and reconciliation to net income (loss) for the periods presented:
| Year Ended December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Segment operating profit |
||||||||||||
| Mineral and Non-operating |
$ | 43,499 | $ | 49,018 | $ | 23,248 | ||||||
| Operating |
44,145 | (5,500 | ) | — | ||||||||
| Securities |
86,781 | 28,961 | 1,641 | |||||||||
| Eliminations |
(102,030 | ) | (40,492 | ) | (4,991 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Total segment operating profit |
72,395 | 31,987 | 19,898 | |||||||||
|
|
|
|
|
|
|
|||||||
| Interest income |
705 | 66 | — | |||||||||
| Interest expense |
(90,210 | ) | (47,882 | ) | (11,893 | ) | ||||||
| Loss on derivatives |
(5,986 | ) | (32 | ) | (2,239 | ) | ||||||
| Loss on debt extinguishment |
(1,697 | ) | (328 | ) | (92 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Net income (loss) |
$ | (24,793 | ) | $ | (16,189 | ) | $ | 5,674 | ||||
|
|
|
|
|
|
|
|||||||
F-36
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
The following tables present financial information by segment as of and for the years ended December 31, 2024, 2023, and 2022.
| Year Ended December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Significant expenses |
||||||||||||
| Mineral and Non-Operating |
||||||||||||
| Cost of sales |
$ | 30,236 | $ | 19,265 | $ | 9,573 | ||||||
| Depreciation, depletion, amortization and accretion |
50,607 | 34,193 | 12,144 | |||||||||
| Selling, general and administrative |
14,362 | 6,813 | 3,712 | |||||||||
| Payroll and payroll-related |
13,303 | 6,399 | 5,296 | |||||||||
| Other segment items(a) |
1,128 | 1,214 | 581 | |||||||||
| Operating |
||||||||||||
| Cost of sales |
$ | 33,847 | $ | 507 | $ | — | ||||||
| Depreciation, depletion, amortization and accretion |
35,370 | 35 | — | |||||||||
| Selling, general and administrative |
6,215 | 2,786 | — | |||||||||
| Payroll and payroll-related |
8,550 | 3,157 | — | |||||||||
| Other segment item(b) |
— | 240 | — | |||||||||
| Securities |
||||||||||||
| Advertising and marketing |
$ | 679 | $ | 3,656 | $ | 772 | ||||||
| Selling, general and administrative |
8,590 | 4,715 | 1,851 | |||||||||
| Payroll and payroll-related |
6,081 | 3,177 | 727 | |||||||||
| Interest expense |
||||||||||||
| Mineral and non-operating |
$ | 63,782 | $ | 40,688 | $ | 11,893 | ||||||
| Operating |
26,428 | 7,194 | — | |||||||||
| Securities |
102,030 | 40,492 | 4,991 | |||||||||
| Eliminations |
(102,030 | ) | (40,492 | ) | (4,991 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Total interest expense |
$ | 90,210 | $ | 47,882 | $ | 11,893 | ||||||
|
|
|
|
|
|
|
|||||||
| Capital expenditures |
||||||||||||
| Mineral and non-operating |
$ | 352,358 | $ | 231,285 | $ | 91,888 | ||||||
| Operating |
252,074 | 47,376 | — | |||||||||
| Eliminations |
(166,729 | ) | — | — | ||||||||
|
|
|
|
|
|
|
|||||||
| Total capital expenditures |
$ | 437,703 | $ | 278,661 | $ | 91,888 | ||||||
|
|
|
|
|
|
|
|||||||
| (a) | Other segment items include advertising and marketing expense, loss on sale of assets, and impairment expense. |
| (b) | Other segment item includes advertising and marketing expense. |
| December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Assets |
||||||||||||
| Mineral and Non-operating |
$ | 898,300 | $ | 469,185 | $ | 157,020 | ||||||
| Operating |
332,721 | 68,821 | — | |||||||||
| Securities |
6,918 | 29,448 | — | |||||||||
| Eliminations |
(208,869 | ) | (74,287 | ) | — | |||||||
|
|
|
|
|
|
|
|||||||
| Total assets |
$ | 1,029,070 | $ | 493,167 | $ | 157,020 | ||||||
|
|
|
|
|
|
|
|||||||
F-37
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
The following table summarizes the Company’s oil and natural properties by proved and unproved properties, location and by segment (before accumulated depletion):
| December 31, 2024 | ||||||||||||||||||||
| (in thousands) | Mineral and Non-Operating |
Operating | Securities | Eliminations | Consolidated Total |
|||||||||||||||
| Oil and natural gas properties, proved |
||||||||||||||||||||
| Williston Basin |
$ | 184,740 | $ | 351,864 | $ | — | $ | — | $ | 536,604 | ||||||||||
| Powder River Basin |
47,780 | — | — | — | 47,780 | |||||||||||||||
| Denver-Julesburg |
45,193 | — | — | — | 45,193 | |||||||||||||||
| Permian Basin |
20,050 | — | — | — | 20,050 | |||||||||||||||
| Marcellus |
1,306 | — | — | — | 1,306 | |||||||||||||||
| Uinta Basin |
34,731 | — | — | — | 34,731 | |||||||||||||||
| Other |
1,702 | — | — | — | 1,702 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total proved properties |
$ | 335,502 | $ | 351,864 | $ | — | $ | — | $ | 687,366 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Oil and natural gas properties, unproved |
||||||||||||||||||||
| Williston Basin |
$ | 209,437 | $ | 7,300 | $ | — | $ | — | $ | 216,737 | ||||||||||
| Powder River Basin |
29,853 | — | — | — | 29,853 | |||||||||||||||
| Denver-Julesburg |
35,619 | — | — | — | 35,619 | |||||||||||||||
| Permian Basin |
6,752 | — | — | — | 6,752 | |||||||||||||||
| Uinta Basin |
28,045 | — | — | — | 28,045 | |||||||||||||||
| Other |
1,849 | — | — | — | 1,849 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total unproved properties |
$ | 311,555 | $ | 7,300 | $ | — | $ | — | $ | 318,855 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| December 31, 2023 | ||||||||||||||||||||
| (in thousands) | Mineral and Non-Operating |
Operating | Securities | Eliminations | Consolidated Total |
|||||||||||||||
| Oil and natural gas properties, proved |
||||||||||||||||||||
| Williston Basin |
$ | 189,651 | $ | 60,372 | $ | — | $ | — | $ | 250,023 | ||||||||||
| Powder River Basin |
38,536 | — | — | — | 38,536 | |||||||||||||||
| Denver-Julesburg |
46,781 | — | — | — | 46,781 | |||||||||||||||
| Permian Basin |
25,375 | — | — | — | 25,375 | |||||||||||||||
| Uinta Basin |
7,959 | — | — | — | 7,959 | |||||||||||||||
| Other |
2,951 | — | — | — | 2,951 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total proved properties |
$ | 311,253 | $ | 60,372 | $ | — | $ | — | $ | 371,625 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Oil and natural gas properties, unproved |
||||||||||||||||||||
| Williston Basin |
$ | 40,599 | $ | 5,120 | $ | — | $ | — | $ | 45,719 | ||||||||||
| Powder River Basin |
28,922 | — | — | — | 28,922 | |||||||||||||||
| Denver-Julesburg |
22,231 | — | — | — | 22,231 | |||||||||||||||
| Permian Basin |
1,001 | — | — | — | 1,001 | |||||||||||||||
| Uinta Basin |
8,379 | — | — | — | 8,379 | |||||||||||||||
| Other |
462 | — | — | — | 462 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total unproved properties |
$ | 101,594 | $ | 5,120 | $ | — | $ | — | $ | 106,714 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
F-38
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
| December 31, 2022 | ||||||||||||||||||||
| (in thousands) | Mineral and Non-Operating |
Operating | Securities | Eliminations | Consolidated Total |
|||||||||||||||
| Oil and natural gas properties, proved |
||||||||||||||||||||
| Williston Basin |
$ | 70,794 | $ | — | $ | — | $ | — | $ | 70,794 | ||||||||||
| Powder River Basin |
27,569 | — | — | — | 27,569 | |||||||||||||||
| Denver-Julesburg |
15,536 | — | — | — | 15,536 | |||||||||||||||
| Permian Basin |
9,618 | — | — | — | 9,618 | |||||||||||||||
| Other |
10 | — | — | — | 10 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total proved properties |
$ | 123,527 | $ | — | $ | — | $ | — | $ | 123,527 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Oil and natural gas properties, unproved |
||||||||||||||||||||
| Williston Basin |
$ | 14,269 | $ | — | $ | — | $ | — | $ | 14,269 | ||||||||||
| Powder River Basin |
1,336 | — | — | — | 1,336 | |||||||||||||||
| Denver-Julesburg |
14,755 | — | — | — | 14,755 | |||||||||||||||
| Permian Basin |
8,911 | — | — | — | 8,911 | |||||||||||||||
| Other |
2,592 | — | — | — | 2,592 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total unproved properties |
$ | 41,863 | $ | — | $ | — | $ | — | $ | 41,863 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
Management has evaluated subsequent events through March 26, 2025, in connection with the preparation of these consolidated financial statements, which is the date the consolidated financial statements were available to be issued. The Company has determined that there were no material such events that warrant disclosure or recognition in the consolidated financial statements, except for the following:
In January 2025, Phoenix Capital Group Holdings, LLC changed its name to Phoenix Energy One, LLC.
The Company is continuing to raise debt capital under its exempt debt offerings. Since the balance sheet date and through March 26, 2025, the Company issued approximately $107.6 million and $33.9 million of its Regulation D and Adamantium bonds, respectively, under the same terms and conditions as the existing securities.
Note 19 – Supplemental Information on Oil and Natural Gas Operations (unaudited)
Geographic Area of Operations
All of the Company’s proved reserves are located within the continental United States, with the majority concentrated in North Dakota, Montana, Utah, Texas, Colorado and Wyoming.
Costs Incurred in Oil and Natural Gas Property Acquisitions and Development Activities
Costs incurred in oil and natural gas property acquisition and development, whether capitalized or expensed, are presented below:
| Year Ended December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Acquisition Costs of Properties |
||||||||||||
| Proved |
$ | 202,725 | $ | 100,282 | $ | 35,998 | ||||||
| Unproved |
311,555 | 83,432 | 43,359 | |||||||||
| Development Costs |
418,493 | 70,933 | 37,691 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total |
$ | 932,773 | $ | 254,647 | $ | 117,048 | ||||||
|
|
|
|
|
|
|
|||||||
F-39
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Property acquisition costs include costs incurred to purchase, lease or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat and gather natural gas.
Oil and Natural Gas Capitalized Costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization including impairments, are presented below:
| December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Proved oil and natural gas properties |
$ | 687,366 | $ | 371,625 | $ | 123,527 | ||||||
| Unproved oil and natural gas properties |
318,855 | 106,714 | 41,863 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total oil and gas properties |
1,006,221 | 478,339 | 165,390 | |||||||||
| Less: Accumulated depletion and impairment |
(140,376 | ) | (54,671 | ) | (20,635 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Oil and gas properties, net |
$ | 865,845 | $ | 423,668 | $ | 144,755 | ||||||
|
|
|
|
|
|
|
|||||||
Oil and Natural Gas Reserve Information
The following table sets forth estimated net quantities of the Company’s proved developed oil and natural gas reserves. Estimated reserves for the periods presented are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB. For estimates of oil reserves, the average WTI spot oil prices used were $76.32, $78.21, and $94.14 per barrel as of December 31, 2024, 2023 and 2022, respectively. These average prices are adjusted for quality, transportation fees, and market differentials. For estimates of natural gas reserves, the average Henry Hub prices used were $2.130, $2.637, and $6.357 per MMBtu as of December 31, 2024, 2023 and 2022, respectively. These average prices are adjusted for energy content, transportation fees, and market differentials.
Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent the Company’s net revenue interest in its properties. Although the Company believes these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
F-40
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
| Proved Developed and Undeveloped Reserves: |
Oil (Bbls) |
Natural Gas (Mcf) |
Natural Gas Liquids (Bbls) |
Total (BOE)(a) |
||||||||||||
| As of December 31, 2021 |
2,105,157 | 3,972,925 | — | 2,767,311 | ||||||||||||
| Production |
(523,416 | ) | (1,058,506 | ) | — | (699,834 | ) | |||||||||
| Divestitures |
— | — | — | — | ||||||||||||
| Purchases of reserves in place |
1,165,585 | 2,331,222 | — | 1,554,122 | ||||||||||||
| Extensions and discoveries |
58,367 | 101,435 | — | 75,273 | ||||||||||||
| Revisions of previous estimates |
886,029 | 2,277,136 | — | 1,265,552 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| As of December 31, 2022 |
3,691,722 | 7,624,212 | — | 4,962,424 | ||||||||||||
| Production |
(1,446,928 | ) | (2,152,939 | ) | (201,454 | ) | (2,007,205 | ) | ||||||||
| Divestitures |
— | — | — | — | ||||||||||||
| Purchases of reserves in place |
1,078,682 | 1,077,933 | 168,207 | 1,426,545 | ||||||||||||
| Extensions and discoveries |
28,697,688 | 25,945,687 | 7,407,103 | 40,429,072 | ||||||||||||
| Revisions of previous estimates |
28,871 | (678,800 | ) | 789,652 | 705,390 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| As of December 31, 2023 |
32,050,035 | 31,816,093 | 8,163,508 | 45,516,225 | ||||||||||||
| Production |
(3,830,461 | ) | (2,979,341 | ) | (415,363 | ) | (4,742,381 | ) | ||||||||
| Divestitures |
(66,654 | ) | (9,186 | ) | (3,702 | ) | (71,887 | ) | ||||||||
| Purchases of reserves in place |
580,118 | 1,922,022 | 147,354 | 1,047,809 | ||||||||||||
| Extensions and discoveries |
20,123,921 | 13,465,004 | 2,108,197 | 24,476,286 | ||||||||||||
| Revisions of previous estimates |
965,595 | (5,903,628 | ) | (2,398,383 | ) | (2,416,726 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| As of December 31, 2024 |
49,822,554 | 38,310,963 | 7,601,611 | 63,809,326 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Proved Developed Reserves |
||||||||||||||||
| December 31, 2021 |
2,105,157 | 3,972,925 | — | 2,767,311 | ||||||||||||
| December 31, 2022 |
3,691,722 | 7,624,212 | — | 4,962,424 | ||||||||||||
| December 31, 2023 |
7,124,194 | 12,250,285 | 1,514,761 | 10,680,669 | ||||||||||||
| December 31, 2024 |
18,624,758 | 20,819,874 | 2,848,355 | 24,943,092 | ||||||||||||
| Proved Undeveloped Reserves(b) |
||||||||||||||||
| December 31, 2021 |
— | — | — | — | ||||||||||||
| December 31, 2022 |
— | — | — | — | ||||||||||||
| December 31, 2023 |
24,925,841 | 19,565,808 | 6,648,747 | 34,835,556 | ||||||||||||
| December 31, 2024 |
31,197,795 | 17,491,089 | 4,753,257 | 38,866,233 | ||||||||||||
| (a) | Estimated proved reserves are presented on an oil-equivalent basis using a conversion of six Mcf per barrel of “oil equivalent.” This conversion is based on energy equivalence and not price or value equivalence. If a price equivalent conversion based on the twelve-month average prices for the year ended December 31, 2024 was used, the conversion factor would be approximately 35.8 Mcf per Bbl of oil. |
| (b) | In early 2023, PhoenixOp was established with the intention that certain leaseholds held by Phoenix Energy would be developed by PhoenixOp. PhoenixOp executed a contract for a drilling rig with Patterson-UTI Drilling Company in June 2023, which allowed for previously unbooked reserves to be estimated and booked as proved undeveloped in accordance with SEC guidelines for reserves categorization and estimation and in adherence to the five-year rule as set forth by the SEC. |
At December 31, 2024, total estimated proved reserves were approximately 63,809,326 Boe, a 18,293,101 Boe net increase from the previous year end’s estimate of 45,516,225 Boe. Proved developed reserves of 24,943,092 Boe increased approximately 14,262,423 Boe from December 31, 2023 as a result of proved developed reserves acquisitions of 1,047,809 Boe, extensions of 3,268,997 Boe, and total positive revisions of previous estimates of 14,759,886 Boe, offset by divestitures of 71,887 Boe and production from proved developed reserves of 4,742,381 Boe. The total positive revisions of previous estimates comprised: (i) positive price revisions of 1,263 Boe; (ii) positive transfer of 14,871,911 Boe from proved undeveloped to proved developed reserves; (iii) negative well performance revisions of (481,161) Boe; (iv) positive revisions of 715,795 Boe due to interest changes; and (v) negative revisions of (347,922) Boe due to changes in lifting cost. Proved undeveloped reserves of 38,866,233 Boe increased approximately 4,030,677 Boe from December 31, 2023 as a result of proved undeveloped reserves extensions of 21,207,289 and total negative revisions of previous estimates of 17,176,612 Boe. The total negative revisions of previous estimates comprised: (i) positive price revisions of 48,935 Boe; (ii) negative transfer of (14,871,911) Boe from proved undeveloped to proved developed reserves; and (iii) negative well performance revisions of (2,353,636) Boe due to asset development reconfiguration and type curve adjustments. During the year
F-41
Table of Contents
PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
ended December 31, 2024, approximately $450.0 million in capital expenditures went toward the acquisition and development of proved developed reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. For the year ended December 31, 2024, approximately $87.4 million in capital expenditures were related to the conversion of proved undeveloped reserves to proved developed reserves. All proved undeveloped reserves disclosed as of December 31, 2024 are scheduled to be converted to proved developed status within five years of initial disclosure.
At December 31, 2023, total estimated proved reserves were approximately 45,516,225 Boe, a 40,553,802 Boe net increase from the previous year end’s estimate of 4,962,424 Boe. Proved developed reserves of 10,680,669 Boe increased approximately 5,718,245 Boe from December 31, 2022 as a result of proved developed reserves acquisitions of 1,426,545 Boe, extensions of 5,682,894 Boe, and total positive revisions of previous estimates of 616,010 Boe, offset by production from proved developed reserves of 2,007,205 Boe. The total positive revisions of previous estimates comprised: (i) negative price revisions of (13,622) Boe, (ii) transfer of (89,378) Boe from proved developed to proved undeveloped due to previous misclassifications of reserve, (iii) positive well performance revisions of 515,938 Boe, and (iv) positive revisions of 203,072 Boe due to changes in lifting cost. Proved undeveloped reserves of 34,835,556 Boe increased approximately 34,835,556 Boe from December 31, 2022 as a result of revisions due to previous misclassification of 89,378 Boe of reserves as proved developed reserves and due to the addition of 34,746,179 Boe of operated proved undeveloped reserves stemming from the signing of a drilling rig contract in June 2023. During the year ended December 31, 2023, approximately $171.2 million in capital expenditures went toward the acquisition and development of proved developed reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. At December 31, 2022, there were no proved undeveloped reserves. Therefore, no capital expenditures for the year ended December 31, 2023 were related to the conversion of proved undeveloped reserves to proved developed reserves.
At December 31, 2022, total estimated proved reserves were approximately 4,962,424 Boe, a 2,195,112 Boe net increase from the previous year end’s estimate of 2,767,312 Boe at December 31, 2021. Proved developed reserves of 4,962,424 Boe represented an increase of approximately 2,195,112 Boe from December 31, 2021 as a result of proved developed reserves acquisitions of 1,554,122 Boe, extensions of 75,272 Boe, and total positive revisions of previous estimates of 1,265,552 Boe, offset by production of 699,834 Boe. The total positive revisions of previous estimates comprised (i) positive price revisions of 524,667 Boe and (ii) positive well performance revisions of 740,885 Boe. During the year ended December 31, 2022, approximately $117.1 million in capital expenditures went toward the acquisition and development of proved reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. At December 31, 2021, there were no proved undeveloped reserves. Therefore, no capital expenditures for the year ended December 31, 2022 were related to the conversion of proved undeveloped reserves to proved developed reserves.
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions.
| Year Ended December 31, | ||||||||||||
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Future cash inflows |
$ | 3,626,615 | $ | 2,427,554 | $ | 381,493 | ||||||
| Future development costs |
(779,533 | ) | (619,680 | ) | — | |||||||
| Future production costs |
(998,851 | ) | (681,730 | ) | (74,897 | ) | ||||||
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| Future net cash flows |
1,848,231 | 1,126,144 | 306,596 | |||||||||
| Less 10% annual discount to reflect timing of cash flows |
(779,539 | ) | (578,863 | ) | (116,711 | ) | ||||||
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| Standard measure of discounted future net cash flows |
$ | 1,068,692 | $ | 547,281 | $ | 189,885 | ||||||
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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES
Notes to the Consolidated Financial Statements
Changes in the Standardized Measure for Discounted Cash Flows
| (in thousands) | 2024 | 2023 | 2022 | |||||||||
| Beginning of the year |
$ | 547,281 | $ | 189,885 | $ | 96,636 | ||||||
| Net change in sales and transfer prices and in production (lifting) costs related to future production |
13,353 | (49,785 | ) | — | ||||||||
| Changes in the estimated future development costs |
— | — | — | |||||||||
| Sales and transfers of oil and gas produced during the period |
(289,138 | ) | (118,105 | ) | (57,563 | ) | ||||||
| Net change due to extensions, discoveries, and improved recovery |
261,832 | 416,822 | 3,134 | |||||||||
| Net change due to purchases and sales of minerals in place |
26,301 | 36,562 | 57,622 | |||||||||
| Net change due to revisions in quantity estimates |
189,962 | 2,519 | 83,101 | |||||||||
| Previously estimated development costs incurred during the period |
106,214 | — | — | |||||||||
| Accretion of discount |
212,886 | 69,383 | 6,955 | |||||||||
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| End of the year |
$ | 1,068,692 | $ | 547,281 | $ | 189,885 | ||||||
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The data presented in this note should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a significant amount of estimations and assumptions. The required projection of production and related expenditures overtime requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from historical prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.
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PHOENIX ENERGY ONE, LLC
$750,000,000 Senior Subordinated Notes
Comprising
| $140,000,000 9.0% Three-Year Cash Interest Notes | $110,000,000 9.0% Three-Year Compound Interest Notes | |
| $40,000,000 10.0% Five-Year Cash Interest Notes | $40,000,000 10.0% Five-Year Compound Interest Notes | |
| $30,000,000 11.0% Seven-Year Cash Interest Notes | $30,000,000 11.0% Seven-Year Compound Interest Notes | |
| $170,000,000 12.0% Eleven-Year Cash Interest Notes | $190,000,000 12.0% Eleven-Year Compound Interest Notes |
PROSPECTUS
Through and including , 2025 (the 90th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.
Table of Contents
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
Item 13. Other Expenses of Issuance and Distribution.
The following table sets forth the costs and expenses (other than the Broker-Dealer Fee or other fees paid to any selling group member (each as defined in the prospectus contained in this registration statement)) payable by Phoenix Energy One, LLC (the “Company”) in connection with the sale and distribution of the securities being registered pursuant to this registration statement. All amounts are estimated except the U.S. Securities and Exchange Commission (“SEC”) registration fee and Financial Industry Regulatory Authority, Inc. (“FINRA”) filing fee.
| Amount to be Paid | ||||
| SEC registration fee |
$ | 114,825 | ||
| FINRA filing fee |
113,000 | |||
| Accounting fees and expenses |
300,000 | |||
| Legal fees and expenses |
3,000,000 | |||
| Printing and engraving expenses |
640,000 | |||
| Blue sky fees and expenses |
350,000 | |||
| Trustee fees and expenses |
25,000 | |||
| Miscellaneous |
57,175 | |||
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| Total |
$ | 4,600,000 | ||
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Item 14. Indemnification of Directors and Officers.
Section 18-108 of the Delaware Limited Liability Company Act (the “DLLCA”) provides that a limited liability company may, under its limited liability company agreement, indemnify and hold harmless a member, manager, or any other person from and against any and all claims and demands whatsoever.
The Second Amended and Restated Limited Liability Company Agreement of the Company (as amended, the “Phoenix Energy LLCA”) provides that the Company shall, to the extent permitted by the DLLCA, indemnify, hold harmless, and pay all judgments and claims against any of its members or officers from any liability, loss, or damage incurred by any member or officer of the Company, or by reason of any act performed or omitted to be performed by any member or officer in connection with the Company’s business (an “Action”). This indemnification includes costs and attorneys’ fees and any amounts expended in the settlement of any claim of liability, loss, or damage. However, the Company’s obligation to indemnify a member or officer will only apply if such person (a) conducted him or herself in good faith, (b) is not guilty of gross negligence or willful misconduct, and (c) believed in good faith that such conduct was in the best interest of the Company. Such indemnification is recoverable only from the assets of the Company and not the assets of any of its members.
Pursuant to the Phoenix Energy LLCA, the Company is not obligated to indemnify or advance any expenses to any indemnified person if and to the extent that it is determined that (i) in the case of any criminal proceeding, the indemnified person had reasonable cause to believe that the act or omission was unlawful, or (ii) the indemnified person actually received an improper personal benefit. Furthermore, no payments are required to be made by the Company pursuant to the Phoenix Energy LLCA to indemnify or advance funds to any indemnified person (x) with respect to any Action that was initiated or brought voluntarily by such indemnified person (and not by way of defense) unless (1) approved or authorized by a majority in interest of the members, excluding any interest held by the indemnified person, or (2) incurred to establish or enforce such indemnified person’s right to indemnification under the Phoenix Energy LLCA, or (y) in connection with any Action or claim brought by the Company or involving such indemnified person, if such indemnified person is found liable to the Company on such Action or claim. If the indemnified person is found liable to the Company with respect to one or more, but less than all, claims, issues, or matters in a single Action, expenses will be allocated among such claims, issues, or matters on a reasonable and proportionate basis.
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The Company intends to enter into indemnification agreements with each of its managers and executive officers. These agreements will require the Company to indemnify these individuals to the fullest extent permitted under the DLLCA against expenses, losses, and liabilities that may arise in connection with actual or threatened proceedings in which they are involved by reason of their service to the Company and its subsidiaries and affiliates and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified.
The indemnification rights set forth above will not be exclusive of any other right that an indemnified person may have or hereafter acquire under any statute, the Phoenix Energy LLCA, any other agreement, any vote of members or managers, or otherwise.
The Company expects to maintain standard policies of insurance that provide coverage (1) to its managers and officers against loss rising from claims made by reason of breach of duty or other wrongful act and (2) to the Company with respect to indemnification payments that it may make to such managers and officers.
The broker-dealer agreement with the Managing Broker-Dealer (as defined in the prospectus contained in this registration statement) provides for indemnification by the Managing Broker-Dealer of the Company, its affiliates, and their respective representatives and agents for certain liabilities arising due to breach of the broker-dealer agreement by the Managing Broker-Dealer, or the bad faith, gross negligence, or willful misconduct of the Managing Broker-Dealer, and by the Company of the Managing Broker-Dealer, its affiliates, and their respective representatives and agents for certain liabilities arising due to a breach of the broker-dealer agreement by the Company or in connection with this offering.
Item 15. Recent Sales of Unregistered Securities.
Within the past three years, the Company has granted or issued the following securities of the Company that were not registered under the Securities Act:
| • | Between January 1, 2022 and July 2022, the Company issued an aggregate of $4.0 million of principal amount of unsecured bonds for a purchase price of $4.0 million pursuant to Rule 506(c) of Regulation D promulgated under the Securities Act (“Regulation D”), with maturity dates ranging from one to four years from the issue date and interest rates ranging from 6.5% to 15.0% per annum. |
| • | Between July 2022 and December 2022, the Company issued an aggregate of $38.0 million of principal amount of unsecured bonds for a purchase price of $37.9 million pursuant to Rule 506(c) of Regulation D, with maturity dates ranging from nine months to five years from the issue date and an interest rates ranging from of 8.0% to 11.0% per annum. |
| • | Between December 2022 and August 2023, the Company issued an aggregate of $215.5 million of principal amount of unsecured Series AAA through Series D-1 Bonds for a purchase price of $212.6 million pursuant to Rule 506(c) of Regulation D, with maturity dates ranging from nine months to seven years from the issue date and interest rates ranging from 8.0% to 12.0% per annum. |
| • | Between August 2023 and March 31, 2025, the Company issued an aggregate of $687.0 million of principal amount of unsecured Series U through Series JJ-1 Bonds for a purchase price of $675.9 million pursuant to Rule 506(c) of Regulation D, with maturity dates ranging from one to eleven years from the issue date and interest rates ranging from 9.0% to 14.0% per annum. |
| • | Between January 1, 2022 and August 2024, the Company issued an aggregate of $128.9 million of principal amount of unsecured bonds for a purchase price of $128.1 million pursuant to Regulation A promulgated under the Securities Act (“Regulation A”), with a maturity date of three years from the issue date and an interest rate of 9.0% per annum. |
| • | Since January 1, 2022, the Company has granted membership interests to certain employees representing 3.16% of the Company’s limited liability company interests, in part due to reallocation of membership interest percentages. On October 18, 2024, all then-existing interests in the Company were exchanged for limited liability company interests in Phoenix Equity Holdings, LLC, a Delaware limited liability company and the sole member of the Company. |
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None of the foregoing transactions involved any underwriters, underwriting discounts, or commissions, or public offering. Unless otherwise stated, the sales of the above-referenced securities were exempt from registration under the U.S. Securities Act of 1933, as amended (the “Securities Act”), in reliance upon Section 4(a)(2) of the Securities Act (or Regulation D or Regulation A promulgated thereunder) as transactions by an issuer not involving any public offering. To the extent applicable, the recipients of the securities in each of these transactions represented their intentions to acquire the securities for investment only and not with a view to or for sale in connection with any distribution thereof and appropriate legends were placed upon any certificates issued in these transactions.
Item 16. Exhibits and Financial Statement Schedules.
| (a) | Exhibits. See the Exhibit Index immediately preceding the signature pages hereto, which is incorporated by reference as if fully set forth herein. |
| (b) | Financial Statement Schedules. None. |
Item 17. Undertakings.
| (a) | The undersigned registrant hereby undertakes: |
| (1) | to file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement: |
| (i) | to include any prospectus required by Section 10(a)(3) of the Securities Act; |
| (ii) | to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement (Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the SEC pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement.); and |
| (iii) | to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement. |
| (2) | that, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof; |
| (3) | to remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering; |
| (5) | that, for the purpose of determining liability under the Securities Act to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness; provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use; and |
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| (6) | that, for the purposes of determining liability of the registrant under the Securities Act to any purchase in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser: |
| (i) | any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424; |
| (ii) | any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant; |
| (iii) | the portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and |
| (iv) | any other communication that is an offer in the offering made by the undersigned registrant to the purchaser. |
| (b) | The undersigned registrant hereby undertakes that, for purposes of determining any liability under the Securities Act, each filing of the registrant’s annual report pursuant to Section 13(a) or Section 15(d) of the U.S. Securities and Exchange Act of 1934, as amended (the “Exchange Act”), (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to Section 15(d) of the Exchange Act) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. |
| (c) | Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers, and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer, or controlling person of the registrant in the successful defense of any action, suit, or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue. |
| (i) | The undersigned registrant hereby undertakes that: |
| (1) | for purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective; and |
| (2) | for the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. |
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EXHIBIT INDEX
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| + | Capitalized terms have the meanings assigned to them in the prospectus contained in this Registration Statement. |
| ++ | Certain annexes, schedules, and exhibits to this Exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company hereby agrees to furnish supplementally a copy of any omitted annex, schedule, or exhibit to the U.S. Securities and Exchange Commission upon request. |
| * | Previously filed. |
| † | Management contract or compensatory plan or arrangement. |
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Pursuant to the requirements of the U.S. Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Irvine, State of California, on May 9, 2025.
| PHOENIX ENERGY ONE, LLC | ||
| By: | /s/ Curtis Allen | |
| Name: | Curtis Allen | |
| Title: | Chief Financial Officer | |
Pursuant to the requirements of the U.S. Securities Act of 1933, as amended, this registration statement has been signed by the following persons in the capacities indicated below on May 9, 2025.
| Signature |
Title | |||
| /s/ Adam Ferrari |
Chief Executive Officer (Principal Executive Officer) | |||
| Adam Ferrari | ||||
| /s/ Curtis Allen |
Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) | |||
| Curtis Allen | ||||
II-7
Exhibit 10.8
EMPLOYEE AGREEMENT – 2025 Calendar Year
This Employee Agreement (this “Agreement”) is made and entered into by and between Phoenix Equity Holdings, LLC (together with its affiliates and subsidiaries, the “Company”), and Adam Ferrari (“Employee”), effective as of January 1, 2025 (the “Effective Date”) and replaces the “Employee Agreement – 2024” signed May 2, 2024 and effective January 1, 2024 as well as any other prior “Employee Agreement – 2025 Calendar Year” between the parties.
| 1. | POSITION AND DUTIES |
(a) Position: Employee continues to be employed in the capacity of Chief Executive Officer. Employee agrees to serve the Company and to perform faithfully and to the best of their abilities the duties and responsibilities commensurate with such position.
(b) Duties: Employee shall perform all duties as are customary for the position of Chief Executive Officer and any additional duties now or hereafter assigned to Employee by the Company. Employee is expected to adhere to all policies of the Company and to act in the best interests of the Company at all times.
| 2. | TERM OF EMPLOYMENT The term of this Agreement shall commence on the Effective Date and continue until terminated as provided in Section 4. |
| 3. | COMPENSATION AND BENEFITS |
| (a) | Variable Compensation: Employee shall receive variable compensation tied to the gross revenue of the Company. The percentage awarded to the Employee for the 2025 calendar year is 1.10% of an assumed gross revenue amount for the Company for the 2025 calendar year set by Lion of Judah Capital, LLC. Lion of Judah Capital, LLC may revise such assumed gross revenue amount in and at its discretion during the course of the year. The Company paid $3 million of the variable compensation to Employee in January 2025. Payment of the remaining portion of such variable compensation will be made twice a month and may be trued up on December 31, 2025 using annual gross revenue estimates prepared from the books and records of the Company as of December 15, 2025 to the extent Lion of Judah Capital, LLC determines that additional variable compensation is payable to Employee. |
| (b) | Benefits: Employee shall be eligible to participate in all employee benefit plans and programs, including but not limited to health insurance, dental insurance, and retirement plans, to the extent available and in accordance with the terms and eligibility requirements of each benefit program. |
| 4. | TERMINATION Employment under this Agreement may be terminated: |
| • | By Employee, upon 60 written notice to the Company. |
| • | By the Company at any time, in accordance with the Company’s Second Amended and Restated Operating Agreement, as amended from time to time (the “Operating Agreement and any other applicable agreements predating this agreement. |
| • | By the Company and Employee upon execution of both parties of a new letter agreement specifically referencing this Agreement. |
| 5. | CONFIDENTIALITY AND NON-DISCLOSURE During the term of this Agreement and thereafter, Confidentiality and Non-Disclosure is to be referenced directly from the Operating Agreement. |
| 6. | NON-COMPETE AND NON-SOLICITATION During the term of this Agreement and thereafter, non-compete and non-solicitation is to be referenced directly from the Operating Agreement. |
| 7. | MISCELLANEOUS This Agreement, together with the Operating Agreement and the Company’s Employee Handbook, constitutes the entire agreement between the parties concerning the subject matter hereof and supersedes all prior agreements, understandings, negotiations, and discussions, whether oral or written, of the parties. This Agreement will be governed by the laws of the State of California. |
[SIGNATURE PAGE FOLLOWS]
IN WITNESS WHEREOF, the parties hereto have executed this Employee Agreement as of the date set forth below.
| Adam Ferrari | ||
| Signature: | /s/ Adam Ferrari | |
| Date: 5/8/2025 | ||
| For Phoenix Equity Holdings, LLC | ||
| Signature: | /s/ Curtis Allen | |
| By: Curtis Allen | ||
| Title: Chief Financial Officer | ||
| Date: 5/8/2025 | ||
Exhibit 10.9
EMPLOYEE AGREEMENT – 2025 Calendar Year
This Employee Agreement (this “Agreement”) is made and entered into by and between Phoenix Equity Holdings, LLC (together with its affiliates and subsidiaries, the “Company”), and Curtis Allen (“Employee”), effective as of January 1, 2025 (the “Effective Date”) and replaces the “Employee Agreement – 2024” signed May 2, 2024 and effective January 1, 2024 as well as any other prior “Employee Agreement – 2025 Calendar Year” between the parties.
| 1. | POSITION AND DUTIES |
(a) Position: Employee continues to be employed in the capacity of Chief Financial Officer. Employee agrees to serve the Company and to perform faithfully and to the best of their abilities the duties and responsibilities commensurate with such position.
(b) Duties: Employee shall perform all duties as are customary for the position of Chief Financial Officer and any additional duties now or hereafter assigned to Employee by the Company. Employee is expected to adhere to all policies of the Company and to act in the best interests of the Company at all times.
| 2. | TERM OF EMPLOYMENT The term of this Agreement shall commence on the Effective Date and continue until terminated as provided in Section 4. |
| 3. | COMPENSATION AND BENEFITS |
| (a) | Variable Compensation: Employee shall receive variable compensation tied to the gross revenue of the Company. The percentage awarded to Employee for the 2025 calendar year is 0.55% of an assumed gross revenue amount for the Company for the 2025 calendar year set by Lion of Judah Capital, LLC. Lion of Judah Capital, LLC may revise such assumed gross revenue amount in and at its discretion during the course of the year. Payments of the variable compensation will be made twice a month and may be trued up on December 31, 2025 using annual gross revenue estimates prepared from the books and records of the Company as of December 15, 2025 to the extent Lion of Judah Capital, LLC determines that additional variable compensation is payable to Employee. |
| (b) | Benefits: Employee shall be eligible to participate in all employee benefit plans and programs, including but not limited to health insurance, dental insurance, and retirement plans, to the extent available and in accordance with the terms and eligibility requirements of each benefit program. |
| 4. | TERMINATION Employment under this Agreement may be terminated: |
| • | By the Employee, upon 60 written notice to the Company. |
| • | By the Company at any time, in accordance with the Company’s Second Amended and Restated Operating Agreement, as amended from time to time (the “Operating Agreement”), and any other applicable agreements predating this Agreement. |
| • | By the Company and Employee upon execution of both parties of a new letter agreement specifically referencing this Agreement. |
| 5. | CONFIDENTIALITY AND NON-DISCLOSURE During the term of this Agreement and thereafter, Confidentiality and Non-Disclosure is to be referenced directly from the Operating Agreement. |
| 6. | NON-COMPETE AND NON-SOLICITATION During the term of this Agreement and thereafter, non-compete and non-solicitation is to be referenced directly from the Operating Agreement. |
| 7. | MISCELLANEOUS This Agreement, together with the Operating Agreement, the Company’s Employee Handbook and that certain Award Agreement between Employee and the Company dated December 4, 2024, constitutes the entire agreement between the parties concerning the subject matter hereof and supersedes all prior agreements, understandings, negotiations, and discussions, whether oral or written, of the parties. This Agreement will be governed by the laws of the State of California. |
[SIGNATURE PAGE FOLLOWS]
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date set forth below.
| Curtis Allen | ||
| Signature: | /s/ Curtis Allen | |
| Date: 5/8/2025 | ||
| For Phoenix Equity Holdings, LLC | ||
| Signature: | /s/ Adam Ferrari | |
| By: Adam Ferrari | ||
| Title: Chief Executive Officer | ||
| Date: 5/8/2025 | ||
Exhibit 10.10
EMPLOYEE AGREEMENT – 2025 Calendar Year
This Employee Agreement (this “Agreement”) is made and entered into by and between Phoenix Equity Holdings, LLC (together with its affiliates and subsidiaries, the “Company”), and Lindsey Wilson (“Employee”), effective as of January 1, 2025 (the “Effective Date”) and replaces the “Employee Agreement – 2024” signed May 3, 2024 and effective January 1, 2024 as well as any other prior “Employee Agreement – 2025 Calendar Year” between the parties..
| 1. | POSITION AND DUTIES |
(a) Position: Employee continues to be employed in the capacity of Chief Business Officer. Employee agrees to serve the Company and to perform faithfully and to the best of their abilities the duties and responsibilities commensurate with such position.
(b) Duties: Employee shall perform all duties as are customary for the position of Chief Business Officer and any additional duties now or hereafter assigned to Employee by the Company. Employee is expected to adhere to all policies of the Company and to act in the best interests of the Company at all times.
| 2. | TERM OF EMPLOYMENT The term of this Agreement shall commence on the Effective Date and continue until terminated as provided in Section 4. |
| 3. | COMPENSATION AND BENEFITS |
| (a) | Variable Compensation: Employee shall receive variable compensation tied to the gross revenue of the Company. The percentage awarded to Employee for the 2025 calendar year is 0.10% of an assumed gross revenue amount for the Company for the 2025 calendar year set by Lion of Judah Capital, LLC. Lion of Judah Capital, LLC may revise such assumed gross revenue amount in and at its discretion during the course of the year. Payments of the variable compensation will be made twice a month and may be trued up on December 31, 2025 using annual gross revenue estimates prepared from the books and records of the Company as of December 15, 2025 to the extent Lion of Judah Capital, LLC determined that additional variable compensation is payable to Employee. |
| (b) | Benefits: Employee shall be eligible to participate in all employee benefit plans and programs, including but not limited to health insurance, dental insurance, and retirement plans, to the extent available and in accordance with the terms and eligibility requirements of each benefit program. |
| 4. | TERMINATION Employment under this Agreement may be terminated: |
| • | By Employee, upon 60 written notice to the Company. |
| • | By the Company at any time, in accordance with the Company’s Second Amended and Restated Operating Agreement, as amended from time to time (the “Operating Agreement and any other applicable agreements predating this agreement. |
| • | By the Company and Employee upon execution of both parties of a new letter agreement specifically referencing this Agreement. |
| 5. | CONFIDENTIALITY AND NON-DISCLOSURE During the term of this Agreement and thereafter, Confidentiality and Non-Disclosure is to be referenced directly from the Operating Agreement. |
| 6. | NON-COMPETE AND NON-SOLICITATION During the term of this Agreement and thereafter, non-compete and non-solicitation is to be referenced directly from the Operating Agreement. |
| 7. | MISCELLANEOUS This Agreement, together with the Operating Agreement, the Company’s Employee Handbook and that certain Award Agreement between Employee and the Company dated December 4, 2024, constitutes the entire agreement between the parties concerning the subject matter hereof and supersedes all prior agreements, understandings, negotiations, and discussions, whether oral or written, of the parties. This Agreement will be governed by the laws of the State of Texas. |
[SIGNATURE PAGE FOLLOWS]
IN WITNESS WHEREOF, the parties hereto have executed this Employee Agreement as of the Effective Date.
| Lindsey Wilson | ||
| Signature: | /s/Lindsey Wilson | |
| Date: 5/8/2025 | ||
| For Phoenix Equity Holdings, LLC | ||
| Signature: | /s/Curtis Allen | |
| By: Curtis Allen | ||
| Title: Chief Financial Officer | ||
| Date: 5/8/2025 | ||
Exhibit 23.1
|
18012 Sky Park Circle, Suite 200 Irvine, California 92614 tel 949-852-1600 fax 949-852-1606 www.rjicpas.com |
Consent of Independent Registered Public Accounting Firm
We consent to the inclusion of our report dated March 26, 2025, except for Note 17, as to which the date is April 23, 2025 in Amendment No. 4 to Form S-1 of Phoenix Energy One, LLC and Subsidiaries (the “Company”), relating to the consolidated financial statements of the Company and Subsidiaries as of December 31, 2024, 2023 and 2022, and for the years then ended and to the reference to our firm as Experts.
/s/ Ramirez Jimenez International CPAs
Irvine, California
May 9, 2025
Exhibit 99.1
PHOENIX ENERGY ONE, LLC
SUBSCRIPTION AGREEMENT INSTRUCTION PAGE
Phoenix Energy One, LLC (“we,” “our,” “us,” or the “Company”) is offering on a continuous basis up to $750,000,000 in aggregate principal of its Fixed Rate Senior Subordinated Notes (the “Notes”) pursuant to a Registration Statement on Form S-1 (File No. 333-282862), including the related prospectus, dated as of [ • ], 2025 (as it may be amended and supplemented from time to time, the “Prospectus”). A copy of the Prospectus can be obtained from our filings with the U.S. Securities and Exchange Commission (the “SEC”) via the EDGAR system at https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&filenum=333-282862. Capitalized terms used but not defined herein will have the meanings assigned to them in the Prospectus.
The Notes will be sold in registered form in minimum denominations of $1,000. The initial minimum investment amount per holder will be $5,000 (the “Minimum Purchase Amount”). From time to time, we may, however, accept investments of less than the Minimum Purchase Amount or increase or decrease the Minimum Purchase Amount. There is no aggregate minimum purchase amount of Notes we are seeking to offer. We have the right to reject any investment, in whole or in part, for any reason.
The following table summarizes the maturity, interest payment method, and interest rate of the Notes we are offering:
| Maturity |
Interest Payment Method |
Interest Rate | ||||
| 3 Years |
Cash Interest | 9.00 | % | |||
| 3 Years |
Compound Interest | 9.00 | % | |||
| 5 Years |
Cash Interest | 10.00 | % | |||
| 5 Years |
Compound Interest | 10.00 | % | |||
| 7 Years |
Cash Interest | 11.00 | % | |||
| 7 Years |
Compound Interest | 11.00 | % | |||
| 11 Years |
Cash Interest | 12.00 | % | |||
| 11 Years |
Compound Interest | 12.00 | % | |||
In order to invest in Notes, you will be required to complete and execute a subscription agreement substantially in the form attached to these instructions (the “Subscription Agreement”). Upon review of the information that you provide in the Subscription Agreement, we will determine, in our sole discretion, whether to issue any Notes to you or whether you meet the criteria for investing in the Notes. If we determine that you are eligible to participate in the offering and to issue you Notes, then we will notify you of our acceptance of the Subscription Agreement and your related subscription payment. If we do not accept your request, your subscription payment will be returned to you. We caution you that the Notes may not be a suitable investment for you even if you do qualify to purchase Notes.
Once the Subscription Agreement and related subscription payment have been submitted to and accepted by us, you will not have the right to request the return of your subscription payment. We intend to hold closings on a weekly basis assuming there are funds to close. On each closing date, offering proceeds for that closing will be disbursed to us, and Notes will be issued to investors participating in that closing in registered form on the books and records of the Company. If we are dissolved or liquidated after the acceptance by us of the Subscription Agreement and your related subscription payment and prior to the next closing date, your subscription payment will be returned to you.
Instructions to Subscribers
| Section 1: | Indicate investment amount for the Notes. |
| Section 2: | Select interest payment type. |
| Section 3: | Select scheduled maturity and related interest rate. |
| Section 4: | Indicate your method of payment. Please reference the table titled “Funding Options” below. |
| Section 5: | Indicate type of ownership. |
| Section 6: | Fill in all names, addresses, dates of birth, and Social Security or Tax ID numbers for all investors/trustees. |
| Section 7: | Select payment option. |
| Section 8: | Consent to the delivery of documents. |
| Section 9: | Read each of the acknowledgements and representations. Your signature in Section 10 indicates that you have read Section 9, in its entirety, and that we may rely on your affirmation that you understand and meet the acknowledgements and representations contained therein. |
| Section 10: | Execute the Subscription Agreement. |
Non-Custodial Ownership
| • | Accounts with more than one owner must have ALL PARTIES SIGN in Section 10. |
| • | Be sure to attach copies of all requested documents for Pension Plans, Trusts, or Corporate Partnerships required in Section 5. |
Custodial Ownership
| • | For new IRA/Qualified Plan Accounts, please complete the form/application provided by your custodian of choice in addition to the Subscription Agreement and forward to the custodian for processing. |
| • | For existing IRA Accounts and other Custodial Accounts, information must be completed BY THE CUSTODIAN. |
| • | Have all documents signed by the appropriate officers as indicated in the applicable corporate resolution (which are also to be included). |
Funding Options
| Options Number |
Funding Source |
Funding Instructions | ||
| Method 1 | Check | MAIL TO: Phoenix Energy One, LLC Attn: Investor Relations 4643 S Ulster Street, Suite 1510 Denver, Colorado 80237 | ||
| Method 2 | ACH
*Preferred Method* |
Complete Information on Page 3 | ||
| Method 3 | Wire | Amarillo National Bank ABA No.: Acct No.: Acct Name: Ref: [Investor Name] Address: 18575 Jamboree Rd, Suite 830, Irvine, California 92612 | ||
Phone: (303) 376-9778 | For IRA Accounts, mail investor signed documents to the IRA Custodian for signatures.
(REMAINDER OF PAGE LEFT BLANK – SUBSCRIPTION AGREEMENT FOLLOWS)
SUBSCRIPTION AGREEMENT
1. Investment Amount (Select only one.)
| ☐ | Initial Investment (minimum initial investment of $5,000 up to any multiple of $1,000) |
| ☐ | Additional Investments (minimum of $1,000 up to any multiple of $1,000) |
Notes Investment Amount: $
If you are making your investment through a broker-dealer or registered investment advisor, please provide the following information related to such broker-dealer or registered investment advisor:
| Name of firm, CRD/Branch Number: | ||||
| Name of individual representative: | ||||
| Phone#: | ||||
| Email: | ||||
2. Interest Payment Method (Select only one.)
| ☐ | Cash Interest Note |
| ☐ | Compound Interest Note |
3. Maturity and Interest Rate of Notes (Select only one.)
| ☐ | 3 Years (Interest rate of 9.00%) |
| ☐ | 5 Years (Interest rate of 10.00%) |
| ☐ | 7 Years (Interest rate of 11.00%) |
| ☐ | 11 Years (Interest rate of 12.00%) |
4. Investment Instructions
☐ By Check – Checks should be made payable to “Phoenix Energy One, LLC”. Submit your check with your signed Subscription Agreement.
☐ By ACH (preferred method) – Complete your banking information below. By checking this box, I authorize the Company to pull the investment amount listed above on this Subscription Agreement from the account indicated below:
| Name of Financial Institution: | Your Bank’s ABA Routing #: | |
| Your Account #: | Name on Account or FBO: | |
| Mailing Address: | City, State, Zip Code: | |
| Account Type: ☐ Checking ☐ Savings | ||
Please attach a pre-printed, voided check or account statement. The withdrawal services above cannot be established without a pre-printed, voided check or account statement. For Electronic Funds Transfers, the signatures of the bank account owner(s) must appear exactly as they appear on the bank registration.
| ☐ | By Wire Transfer – Forward this Subscription Agreement to the address listed above. Wiring instructions are as set forth on in the instructions to this Subscription Agreement. |
| ☐ | Custodial Accounts – Forward this Subscription Agreement directly to the custodian. |
5. Type of Ownership (Select only one.)
| Non-Custodial Ownership |
Custodial Ownership | |
| ☐ Individual – One signature required.
☐ Joint Tenants with Rights of Survivorship – All parties must sign.
☐ Community Property – All parties must sign.
☐ Tenants in Common – All parties must sign.
☐ Uniform Gift to Minors Act – State of ________. Custodian signature required.
☐ Uniform Transfer to Minors Act – State of ________. Custodian signature required.
☐ Qualified Pension or Profit Sharing Plan – Include plan documents.
☐ Trust – Include title, signature, and “Powers of the Trustees” pages.
☐ Corporation – Include corporate resolution, articles of incorporation, and bylaws. Authorized signature(s) required.
☐ Partnership – Include partnership agreement. Authorized signature(s) required.
☐ Other (Specify) – Include title and signature pages. |
☐ Traditional IRA – Owner and custodian signatures required.
☐ Roth IRA – Owner and custodian signatures required.
☐ Simplified Employee Pension/Trust (SEP) – Owner and custodian signatures required.
☐ KEOGH – Owner and custodian signatures required.
☐ Other – __________ Owner and custodian signatures required.
Custodian Information (To be completed by custodian.)
Name of Custodian:
Mailing Address:
City, State, Zip Code:
Custodian Tax ID #:
Custodian Account #:
Custodian Phone #: |
6. Investor Information* (You must include a permanent street address even if your mailing address is a P.O. Box.)
Individual/Beneficial Owner: (Please print name(s) to whom Notes are to be registered.)
| First, Middle, Last Name: | Social Security #: | |
| Street Address: | City, State, Zip Code: | |
| Daytime Phone #: | Date of Birth: | |
| Citizenship (If Not a U.S. Citizen, Specify Country): | Email Address: | |
Joint Owner: (If applicable.)
| First, Middle, Last Name: | Social Security #: | |
| Street Address: | City, State, Zip Code: | |
| Daytime Phone #: | Date of Birth: | |
| Citizenship (If Not a U.S. Citizen, Specify Country): | Email Address: | |
Trust: (Exactly as registered with the IRS.)
| Name of Trust: | Tax ID #:
Date of Trust: | |
| Name(s) of Trustee(s)*: | Name(s) of Beneficial Owner(s)*: | |
| Beneficial Owner(s) Street Address: | City, State, Zip Code: | |
| Social Security #: | Date of Birth: | |
| Occupation: | Email Address: | |
Corporation/Partnership/Other: (Exactly as registered with the IRS.)
| Name of Entity: | Tax ID #:
Date of Entity Formation: | |
| Name(s) of Officer(s), General Partner or Authorized: | Additional Name of Authorized Person (if any): | |
| Legal Street Address: | City, State, Zip Code: | |
| * | If there is more than one trustee or beneficial owner, we will require documents for the requested information for each additional trustee and/or beneficial owner. |
7. Payment Options for Non-Qualified Accounts (Select only one.)
| ☐ | I choose to have payments of interest and principal mailed to me at the address listed in Section 6. |
| ☐ | I choose to have payments of interest and principal mailed to me at the following address: ______________________________________________________________________. |
| ☐ | I choose to have payments of interest and principal deposited in a checking, savings, or brokerage account. I authorize the Company or its agent to deposit my payment to the account indicated below. This authority will remain in force until I notify the Company to cancel it. In the event that the Company deposits funds erroneously into my account, the Company is authorized to debit my account for the amount of the erroneous deposit. |
| Name of Financial Institution: | Your Bank’s ABA Routing #: | |
| Your Account #: | Name on Account or FBO: | |
| Mailing Address: | City, State, Zip Code: | |
| Account Type: ☐ Checking ☐ Savings ☐ Brokerage |
Please attach a pre-printed, voided check. The deposit services above cannot be established without a pre-printed, voided check. For Electronic Funds Transfers, the signatures of the bank account owner(s) must appear exactly as they appear on the bank registration. If the registration at the bank differs from that on this Subscription Agreement, all parties must sign below.
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8. Delivery of Documents
You hereby acknowledge that we will not be obligated to deliver directly to you, as a holder of Notes, any quarterly reports, annual reports, or any other reports, information, or documents it is required to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act. Such reports, information, and documents filed with the SEC via the EDGAR system (or any successor system) will be deemed to be delivered to the Trustee at the time of such filing via EDGAR (or any successor system). We will not be required to notify you of any such filing. You should read all reports, information, and documents we file from time to time with the SEC.
☐ In lieu of receiving documents, notices, or other information by mail, including as required under the Indenture and the Notes, I authorize the Company to send me such documents, notices, or information electronically, including via email, and to notify me via email when such documents, notices, or information are available. Any investor who elects this option must provide an email address below. Please carefully read the following representations before consenting to receive documents electronically. If you check this box, you represent the following:
| (a) | I acknowledge that access to the Internet, email, and the World Wide Web is required in order to access documents electronically. I may receive by email notification the availability of a document in electronic format. The notification email will contain the document or provide a web address (or hyperlink) where the document can be found. If the attachment is not contained in the email itself, by entering this address into my web browser, I can view, download, and print the document from my computer. I acknowledge that there may be costs associated with the electronic access, such as usage charges from my Internet provider and telephone provider, and that these costs are my responsibility. |
| (b) | I acknowledge that documents distributed electronically may be provided in Adobe’s Portable Document Format (“PDF”). The Adobe Reader software is required to view documents in PDF. The reader software is available free of charge from Adobe’s website at www.adobe.com. The Adobe Reader software must be correctly installed on my system before I will be able to view documents in PDF. Electronic delivery also involves risks related to system or network outage that could impair my timely receipt of or access to Noteholder communications. |
| (c) | I acknowledge that I may receive at no cost from the Company a paper copy of any documents delivered electronically by contacting the Company. |
| (d) | I understand that if the email notification is returned to the Company as “undeliverable,” a letter will be mailed to me with instructions on how to update my email address to begin receiving communications via electronic delivery. I further understand that, if the Company is unable to obtain a valid email address for me, the Company will resume sending a paper copy of its filings by U.S. mail to my address of record. |
| (e) | I understand that my consent may be updated, including any updates in email address to which documents are delivered, at any time by contacting the Company. |
| Email Address: |
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9. Investor Acknowledgements and Representations
| (a) | I understand that the Company reserves the right to, in its sole discretion, accept or reject this subscription, in whole or in part, for any reason whatsoever, and, to the extent not accepted, unused funds transmitted herewith shall be returned to the undersigned in full. |
| (b) | I agree that my rights and responsibilities relative to my ownership of the Notes will be governed by the terms of (1) the Indenture and (2) the Notes issued to me. To the extent ant provision of this Subscription Agreement conflicts with the terms of the Indenture or the Notes, the terms of the Indenture or Notes, as applicable, shall apply. |
| (c) | I have received, read, and fully understand the Prospectus, including the section titled “Plan of Distribution—Financial Suitability Requirements.” I am basing my decision to invest solely on the information contained in the Prospectus. I have relied only on the information contained in the Prospectus and have not relied on any representations made by any other person. |
| (d) | I have (i) a gross income of at least $70,000 and a liquid net worth of $70,000 or (ii) a liquid net worth of at least $250,000. I am also a resident of one of the states listed in the section of the Prospectus titled “Plan of Distribution—Financial Suitability Requirements,” and I meet the criteria for investment in such state, including as described in such section. |
| (e) | I am purchasing the Notes for my own account. |
| (f) | I have such knowledge of, and experience in, financial and business matters as to be capable of (1) evaluating the merits and risks of, and bearing the economic risks entailed by, an investment in the Notes and (2) protecting my interests in connection with that investment. I acknowledge that an investment in the Notes involves a high degree of risk and have read the “Risk Factors” section of the Prospectus. |
| (g) | I understand that the Notes are, and will remain, illiquid. I have reviewed my financial condition and commitments, and discussed those matters with advisors to the extent that I consider necessary. Based on that review, I am satisfied that (1) I have adequate means of providing for my financial needs without selling, transferring, or otherwise disposing of any the Notes and (2) I am capable of bearing the economic risk of (i) investing in the Notes for an indefinite period of time and (ii) the possible loss of all or part of my investment in the Notes. |
| (h) | I represent that neither myself nor any parent entity, subsidiary, affiliate, owner, equityholder, partner, indemnitor, or guarantor of mine, or any agent or other person or entity acting on my behalf: (1) is currently the subject or the target of any sanctions administered or enforced by the U.S. government (including, without limitation, the Office of Foreign Assets Control of the U.S. Department of the Treasury or the U.S. Department of State, and including, without limitation, the designation as a “specially designated national” or “blocked person”), the United Nations Security Council, the European Union, His Majesty’s Treasury, or other relevant sanctions authorities (collectively, “Sanctions”); or (2) located, organized, or resident in a country or territory that is the subject or target of Sanctions, including, without limitation, the Crimea Region of Ukraine, the so-called Donetsk People’s Republic, the so-called Luhansk People’s Republic, Cuba, Iran, North Korea, and Syria. |
| (i) | I represent that I am conducting and have conducted, and any parent entity, subsidiary, affiliate, owner, equityholder, partner, indemnitor, or guarantor of mine, or any agent or other person or entity acting on my behalf, is conducting and has conducted our respective operations at all times in compliance with applicable financial recordkeeping and reporting requirements, including those of the Currency and Foreign Transactions Reporting Act of 1970, as amended, the applicable money laundering statutes of all jurisdictions where such person or any of its subsidiaries conducts business, the rules and regulations thereunder, and any related or similar rules, regulations, or guidelines issued, administered, or enforced by any governmental agency (collectively, the “Anti-Money Laundering Laws”), and no action, suit, or proceeding by or before any court or governmental agency, authority, or body or any arbitrator involving such person or any of its subsidiaries with respect to the Anti-Money Laundering Laws is pending or threatened. |
| (j) | I represent that either (1) I am not (i) an employee benefit plan subject to Title I of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), (ii) a plan that is subject to Section 4975 of the U.S. Internal Revenue Code of 1986, as amended (the “Code”), or provisions under other U.S. or non-U.S. federal, state, local, or other laws or regulations that are similar to the fiduciary responsibility or prohibited transaction provisions of Title I of ERISA or Section 4975 of the Code (collectively, “Similar Laws”), or (iii) an entity whose underlying assets are considered to include “plan assets” of any such plan, account, or arrangement (each of clauses (i), (ii), and (iii), a “Plan”), or using the assets of a Plan to acquire or hold the Notes, or any interest therein, or (2) my purchase and holding of the Notes, or any interest therein, does not, and will not, constitute a non-exempt prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code or a similar violation under any applicable Similar Laws. I understand that the Company and its affiliates are not acting, and will not act, as a fiduciary to any Plan with respect to the decision to purchase or hold the Notes, and are not undertaking to provide impartial investment advice or give advice in a fiduciary capacity with respect to the decision to purchase or hold the Notes. |
| (k) | I understand that the Company is relying upon the truth and accuracy of the representations, warranties, agreements, acknowledgements, and understandings set out in this Subscription Agreement in order to determine my suitability to acquire the Notes. |
By making the foregoing representations you have not waived any right of action you may have under federal or state securities law. Any such waiver would be unenforceable. The Company will assert your representations as a defense in any subsequent litigation where such assertion would be relevant.
10. Investor Signatures
Digital (“electronic”) signatures, often referred to as an “e-signature,” enable paperless contracts and expedite business transactions. The Electronic Signatures in Global and National Commerce Act was meant to ease the adoption of electronic signatures. The mechanics of this Subscription Agreement’s electronic signature include your signing this Subscription Agreement below by typing in your name, with the underlying software recording your IP address, your browser identification, the timestamp, and a securities hash within an SSL encrypted environment. This electronically signed Subscription Agreement will be available to both you and the Company, as well as any associated brokers, so they can store and access it at any time, and it will be stored and accessible on www.rocxplatform.com. You and the Company each hereby consent and agree that electronically signing this Subscription Agreement constitutes your signature, acceptance, and agreement as if actually signed by you in writing. Further, all parties agree that no certification authority or other third-party verification is necessary to validate any electronic signature, and that the lack of such certification or third-party verification will not in any way affect the enforceability of your signature or resulting contract between you and the Company. You understand and agree that your e-signature executed in conjunction with the electronic submission of this Subscription Agreement shall be legally binding and such transaction shall be considered authorized by you. You agree your electronic signature is the legal equivalent of your manual signature on this Subscription Agreement. You consent to be legally bound by this Subscription Agreement’s terms and conditions. Furthermore, you and the Company each hereby agree that all current and future notices, confirmations, and other communications regarding this Subscription Agreement specifically, and future communications in general between the parties, may be made by email, sent to the email address of record as set forth in this Subscription Agreement or as otherwise from time to time changed or updated and disclosed to the other party, without necessity of confirmation of receipt, delivery, or reading, and such form of electronic communication is sufficient for all matters regarding the relationship between the parties. If any such electronically sent communication fails to be received for any reason, including, but not limited to, such communications being diverted to the recipient’s spam filters by the recipient’s email service provider, due to a recipient’s change of address, or due to technology issues by the recipient’s service provider, the parties agree that the burden of such failure to receive is on the recipient and not the sender, and that the sender is under no obligation to resend communications via any other means, including, but not limited to, postal service or overnight courier, and that such communications shall for all purposes, including legal and regulatory, be deemed to have been delivered and received. No physical, paper documents will be sent to you and, if you desire physical documents, then you agree to be satisfied by directly and personally printing, at your own expense, the electronically sent communication(s) and maintaining such physical records in any manner or form that you desire.
Your Consent is Hereby Given: By signing this Subscription Agreement electronically, you are explicitly agreeing to receive documents electronically, including your copy of this signed Subscription Agreement, as well as ongoing disclosures, communications, and notices.
11. Miscellaneous Provisions
| (a) | The representations, warranties, and agreements of the undersigned and the Company made in this Subscription Agreement shall survive the execution and delivery of this Subscription Agreement and the delivery of the Notes. |
| (b) | This Subscription Agreement and all disputes or controversies arising out of or relating to this Subscription Agreement, or the transactions contemplated hereby, shall be governed by the internal laws of the State of New York. |
| (c) | EACH OF THE PARTIES TO THIS SUBSCRIPTION AGREEMENT HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY LEGAL PROCEEDING ARISING OUT OF OR RELATING TO THIS SUBSCRIPTION AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY. |
| (d) | This Subscription Agreement may be executed in two or more counterparts, all of which shall be considered one and the same instrument and shall become effective when one or more counterparts have been signed by each of the parties and delivered to the other parties. Delivery of an executed counterpart of a signature page to this Subscription Agreement by telecopier, facsimile, or other electronic transmission shall be effective as delivery of a manually executed counterpart thereof. The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to this Subscription Agreement or any document to be signed in connection with this Subscription Agreement shall be deemed to include electronic signatures, deliveries, or the keeping of records in electronic form, each of which shall be of the same legal effect, validity, or enforceability as a manually executed signature, physical delivery thereof, or the use of a paper based recordkeeping system, as the case may be, and the parties hereto consent to conduct the transactions contemplated hereunder by electronic means. |
| (e) | In case any provision in this Subscription Agreement shall be invalid, illegal, or unenforceable, the validity, legality, and enforceability of the remaining provisions shall not in any way be affected or impaired thereby. |
| (f) | As between the Company and you, as an investor, this Subscription Agreement, in conjunction with the Indenture and the Notes, constitutes the entire agreement of the parties with respect to the subject matter hereof and thereof, supersedes all prior or contemporaneous oral or written agreements or discussions with respect to such subject matter hereof and thereof, and shall be binding upon and inure to the benefit of the parties hereto and thereto and their respective heirs, representatives, successors, and permitted assigns. |
[Signature Pages Follow]
SIGNATURES:
THE UNDERSIGNED HAS THE AUTHORITY TO ENTER INTO THIS SUBSCRIPTION AGREEMENT ON BEHALF OF THE PERSON(S) OR ENTITY REGISTERED ABOVE.
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FIRM ACKNOWLEDGEMENT:
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SUBSCRIPTION ACCEPTED:
PHOENIX ENERGY ONE, LLC, a Delaware limited liability company
| By: |
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| Name: Lindsey Wilson | ||
| Its: Chief Business Officer | ||
| Dated: | ||