PHXE-P 10-Q Quarterly Report Sept. 30, 2025

PHXE-P 10-Q Quarter ended Sept. 30, 2025

Exhibits

Exhibits

PHOENIX ENERGY ONE, LLC

10-Qs

10-Q	Quarter ended Sept. 30, 2025
10-Q	Quarter ended June 30, 2025
10-Q	Quarter ended March 31, 2025

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM

10-Q

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2025

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number:

333-282862

PHOENIX ENERGY ONE, LLC

(Exact name of registrant as specified in its charter)


Delaware		83-4526672
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

18575 Jamboree Road , Suite 830

Irvine , California 92612

(Address of principal executive offices) (Zip Code)

( 949 )

416-5037

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Series A Cumulative Redeemable Preferred Shares	PHXE.P	NYSE American LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes

☒

☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation

S-T

(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

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.

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 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule

12b-2

of the Exchange Act). Yes ☐ No ☒

The number common shares outstanding as of November 11, 2025: 100,000,000

Table of Contents


PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)	5
	Condensed Consolidated Balance Sheets	6
	Condensed Consolidated Statements of Operations	7
	Condensed Consolidated Statements of Changes in Equity (Deficit)	8
	Condensed Consolidated Statements of Cash Flows	9
	Notes to the Condensed Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	62
Item 4.	Controls and Procedures	64

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	65
Item 1A.	Risk Factors	65
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	97
Item 3.	Defaults Upon Senior Securities	97
Item 4.	Mine Safety Disclosures	97
Item 5.	Other Information	98
Item 6.	Exhibits	106
	Signatures	107

Certain Defined Terms

As used in this Quarterly Report on Form 10-Q (this “ Quarterly Report ”), unless otherwise noted or the context otherwise requires, references to:

•

“ we ,” “ us ,” “ our ,” the “ Company ,” the “ Issuer ,” and “ Phoenix Energy ,” and similar references refer to Phoenix Energy One, LLC, formerly known as Phoenix Capital Group Holdings, LLC, and, where appropriate, its subsidiaries.

•

“ 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).

•

“ 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 Quarterly Report 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.

•

“ E&P ” means exploration and production.

•

“ Exchange Act ” means the Securities Exchange Act of 1934, as amended.

•

“ 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.

•

“ Mcf ” means one thousand cubic feet.

•

“ MMBtu ” means one million Btus.

•

“ NGL ” means natural gas liquids.

•

“ NMAs ” means net mineral acres.

•

“ Notes ” means, collectively, the Registered Notes and the Reg D/Reg A Bonds.

•

“ NRAs ” means net royalty acres.

•

“ NYSE American ” means NYSE American LLC.

•

“ Offering Statement ” means the Company’s offering statement on Form 1-A, initially filed with the SEC on June 26, 2025, and initially qualified by the SEC on August 27, 2025, relating to the Preferred Shares.

•

“ 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.

•

“ 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.

•

“ Reg D/Reg A Bonds ” means, collectively, the Reg D Bonds and the Reg A Bonds.

•

“ Registered Notes ” means unsecured notes offered and sold by the Issuer on a continuous basis pursuant to a registration statement on Form S-1 (File No. 333-282862), including the related prospectus.

•

“ SEC ” means the U.S. Securities and Exchange Commission.

•

“ Senior Debt ” means any indebtedness that the Issuer expressly determines is senior to the Registered Notes, including, as of the date of this Quarterly Report, 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.

•

“ 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.

For ease of reference, we have repeated definitions for certain of these terms in other portions of the body of this Quarterly Report. All such definitions conform to the definitions set forth above.

Certain monetary amounts, percentages, and other figures included in this Quarterly Report have been subject to rounding adjustments. Percentage amounts included in this Quarterly Report 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 Quarterly Report may vary from those obtained by performing the same calculations using the figures in our condensed consolidated financial statements included elsewhere in this Quarterly Report. Certain other amounts that appear in this Quarterly Report may not sum due to rounding.

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, which are statements regarding all matters that are not historical facts. They appear in a number of places throughout this Quarterly Report 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 Part II, Item 1A. “Risk Factors” elsewhere in this Quarterly Report. When considering forward-looking

statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report. You are cautioned that the forward-looking statements contained in this Quarterly Report 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 Quarterly Report are made only as of the date this Quarterly Report, based on information available to us as of the date of this Quarterly Report, 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 Quarterly Report 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 Part II, Item 1A. “Risk Factors” included in Part I, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended September 30, 2025.

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 Quarterly Report, whether as a result of new information, future events or developments, or otherwise.

Investors and others should note that we announce financial and other material information using our website (https://phoenixenergy.com/), SEC filings, press releases, public conference calls, and webcasts. We use these channels of distribution to communicate with our investors and members of the public about our company, our services, and other items of interest. Information contained on our website is not part of this Quarterly Report or our other filings with the SEC.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

PHOENIX ENERGY ONE, LLC

AND SUBSIDIARIES

Condensed Consolidated Financial Statements (unaudited)

As of and for the three and nine months ended September 30, 2025

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(in thousands, except share amounts)


	September 30, 2025			December 31, 2024
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	95,452		$	120,814
Accounts receivable		73,876			28,218
Earnest payments		243			154
Other current assets		9,323			7,528

Total current assets		178,894			156,714

Oil and gas properties		1,700,819			1,006,221
Accumulated depletion		( 253,654	)		( 140,376	)

Net oil and gas properties		1,447,165			865,845
Right-of-use assets, net		9,814			6,010
Other noncurrent assets		4,601			501

TOTAL ASSETS	$	1,640,474		$	1,029,070

LIABILITIES AND EQUITY (DEFICIT)
Current liabilities
Accounts payable	$	139,520		$	41,824
Accrued expenses		38,607			41,466
Current portion of long-term debt		145,348			103,240
Current portion of deferred closings		8,626			7,189
Escrow account		3,994			16,356
Current operating lease liabilities		1,149			656
Other current liabilities		63,663			15,880

Total current liabilities		400,907			226,611

Long-term debt, net of current portion		1,127,454			795,215
Accrued interest		49,669			26,079
Deferred closings		2,935			3,324
Operating lease liabilities		9,918			5,860
Asset retirement obligations		2,508			1,181
Other noncurrent liabilities		462			4,858

Total liabilities		1,593,853			1,063,128

Commitments and contingencies (Note 13)
Equity (deficit)
Series A preferred shares ( 2,704,023 and 0 shares issued and outstanding at an aggregate liquidation preference of $ 67.6 million and $ 0 at September 30, 2025 and December 31, 2024, respectively)		47,934			—
Member’s equity		434			434
Accumulated deficit		( 1,747	)		( 34,492	)

Total equity (deficit)		46,621			( 34,058	)

TOTAL LIABILITIES AND EQUITY (DEFICIT)	$	1,640,474		$	1,029,070


The accompanying notes are an integral part of these condensed consolidated financial statements.		6

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(unaudited)

(in thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024
REVENUES
Product sales	$	113,761		$	23,923		$	295,290		$	57,913
Mineral and royalty revenues		31,300			34,343			93,171			119,931
Purchased crude oil sales		40,436			—			71,236			—
Water services		3,308			728			8,508			1,632
Other revenue		216			46			397			74

Total revenues		189,021			59,040			468,602			179,550

OPERATING EXPENSES
Cost of sales		42,920			17,407			105,172			40,334
Depreciation, depletion, amortization, and accretion		45,550			15,541			113,392			53,316
Purchased crude oil expenses		39,623			—			69,975			—
Selling, general, and administrative		5,540			8,941			21,435			22,052
Payroll and payroll-related		6,437			4,930			22,459			15,662
Advertising and marketing		694			189			1,531			350
Loss on sale of assets		—			—			—			564
Impairment expense		1,987			528			2,509			528

Total operating expenses		142,751			47,536			336,473			132,806

INCOME FROM OPERATIONS		46,270			11,504			132,129			46,744

OTHER INCOME (EXPENSE)
Interest income		303			261			1,355			316
Interest expense, net		( 38,816	)		( 26,201	)		( 111,690	)		( 61,116	)
Gain on derivatives		2,065			3,716			12,907			3,630
Loss on debt extinguishment		( 1,334	)		( 567	)		( 1,916	)		( 868	)

Total other expenses		( 37,782	)		( 22,791	)		( 99,344	)		( 58,038	)

NET INCOME (LOSS)	$	8,488		$	( 11,287	)	$	32,785		$	( 11,294	)


The accompanying notes are an integral part of these condensed consolidated financial statements.		7

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Changes in Equity (Deficit)

(unaudited)

(in thousands, except share amounts)


	Series A Preferred Shares
	Shares		Amount		Member’s Equity			Accumulated Deficit			Total Equity (Deficit)
Balance, January 1, 2025		—	$	—	$	434		$	( 34,492	)	$	( 34,058	)
Net income		—		—		—			5,599			5,599

Balance, March 31, 2025		—	$	—	$	434		$	( 28,893	)	$	( 28,459	)
Net income		—		—		—			18,698			18,698

Balance, June 30, 2025		—	$	—	$	434		$	( 10,195	)	$	( 9,761	)
Net income		—		—		—			8,488			8,488
Issuances of Series A preferred shares		2,704,023		47,934		—			—			47,934
Distribution and accretion on Series A preferred shares		—		—		—			( 40	)		( 40	)

Balance, September 30, 2025		2,704,023	$	47,934	$	434		$	( 1,747	)	$	46,621

Balance, January 1, 2024		—	$	—	$	4,865		$	( 9,699	)	$	( 4,834	)
Net loss		—		—		—			( 8,405	)		( 8,405	)
Contributions		—		—		325			—			325

Balance, March 31, 2024		—	$	—	$	5,190		$	( 18,104	)	$	( 12,914	)
Net income		—		—		—			8,398			8,398

Balance, June 30, 2024		—	$	—	$	5,190		$	( 9,706	)	$	( 4,516	)
Net loss		—		—		—			( 11,287	)		( 11,287	)
Distributions		—		—		( 4,756	)		—			( 4,756	)

Balance, September 30, 2024		—	$	—	$	434		$	( 20,993	)	$	( 20,559	)


The accompanying notes are an integral part of these condensed consolidated financial statements.		8

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(unaudited)

(in thousands)


	Nine Months Ended September 30,
	2025			2024
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	32,785		$	( 11,294	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion		113,392			53,316
Amortization of right-of-use assets		848			445
Amortization of debt discount and debt issuance costs		17,934			11,703
Impairment expense		2,509			528
Unrealized gain on derivatives		( 14,113	)		( 3,545	)
Loss on debt extinguishment		1,916			868
Loss on sale of assets		—			564
Changes in operating assets and liabilities:
Accounts receivable		( 45,657	)		( 13,527	)
Earnest payments		( 13,956	)		( 16,051	)
Accounts payable		21,627			( 9,527	)
Accrued expenses		4,870			4,684
Other current liabilities		42,192			4,997
Escrow account		( 12,612	)		( 258	)
Accrued interest		33,836			19,353
Other		5,046			( 2,038	)

Net cash provided by operating activities		190,617			40,218

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties and leases		( 604,607	)		( 280,267	)
Proceeds from sale of assets		—			6,200
Additions to equipment and other property		( 1,433	)		( 83	)

Net cash used in investing activities		( 606,040	)		( 274,150	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuances of debt, net of discount		454,107			384,854
Payments of debt issuance costs		( 60,192	)		( 42,300	)
Repayments of debt		( 47,477	)		( 77,196	)
Proceeds from preferred equity offering, net of issuance costs		47,931			—
Member’s contributions		—			325
Member’s distributions		—			( 4,756	)
Payments of deferred closings		( 4,308	)		( 7,896	)

Net cash provided by financing activities		390,061			253,031

Net change in cash and cash equivalents		( 25,362	)		19,099
Cash and cash equivalents at beginning of year		120,814			5,428

Cash and cash equivalents at end of year	$	95,452		$	24,527


The accompanying notes are an integral part of these condensed consolidated financial statements.		9

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

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 acquisitions and 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 from Phoenix Capital Group Holdings, LLC to Phoenix Energy One, LLC in January 2025. As used in these condensed 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,

non-operated

working interests, and operated leaseholds for the purpose of exploration, development, production, and sale of crude oil, natural gas, natural gas liquids, and other byproducts conducted through its wholly-owned subsidiaries, Phoenix Operating LLC (“PhoenixOp”), Firebird Services, LLC (“Firebird Services”) and Firebird Marketing, LLC (“Firebird Marketing”). PhoenixOp is a Delaware limited liability company formed in January 2022 to drill, complete and operate wells in the United States. Firebird Services is a Delaware limited liability company formed in October 2023 to perform saltwater disposal services on wells operated by PhoenixOp. Firebird Marketing is a Delaware limited liability company formed in March 2025 to market and sell the Company’s operated production beginning April 2025.

Interim financial presentation

The accompanying condensed 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”) for interim financial information. Accordingly, they do not include all of the information and notes required by U.S. GAAP for annual financial statements. In the opinion of management, all adjustments, consisting only of normal recurring adjustments considered necessary for fair presentation, have been included. Interim results are not necessarily indicative of results for a full year. The accompanying unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto as of and for the year ended December 31, 2024 (the “2024 annual financial statements”).

Note 2 – Significant Accounting Policies

Basis of preparation and principles of consolidation

The condensed 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. These reclassifications had no effect on the Company’s previously reported results of operations or accumulated deficit.

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 continuing to achieve profitable operations in order to satisfy its liabilities as they come due.

As of September 30, 2025, the Company had negative working capital of approximately $ 222.0 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 or equity. Since the balance sheet date and through the date of the filing of these condensed consolidated financial statements, the Company had raised an additional $ 54.2 million of notes through its investor program (see

Note 7 – Debt

and

Note 16 – Subsequent Events

). Management believes its capital raises through its bond offerings will continue at or above this current pace.

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Use of estimates

The preparation of the condensed 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 condensed 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 condensed 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.

Revenue from contracts with customers

The Company recognizes its revenues following Accounting Standards Codification (“ASC”) Topic 606,

Revenue from Contracts with Customers

, (“ASC 606”). The Company’s revenues are predominantly derived from contracts for the sale of crude oil, natural gas and NGLs. For crude oil, natural gas and NGLs produced by PhoenixOp, each delivery order is treated as a separate performance obligation that is satisfied 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 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.

In circumstances where the Company is the

non-operator

or mineral rights owner, the Company derives revenue from its interests in the sale of oil and natural gas production and does not consider itself to have control of the product, resulting in the recognition of revenues net of post-production expenses. 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. 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.

Effective April 2025, the Company began conducting marketing activities through its newly established subsidiary, Firebird Marketing. These activities include the purchase of crude oil from working interest owners and royalty interest holders in properties operated by PhoenixOp, and the subsequent sale of the crude oil to customers. The revenues and expenses from these sales and purchases are recognized on a gross basis as the Company acts as a principal in these transactions by assuming control of the purchased crude oil before it is transferred to the customer.

The Company, through Firebird Services, 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.

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Impairment of long-lived assets

The Company follows the provisions of 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. The valuation of unproved oil and gas properties 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. The unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. 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. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. If it is determined that it is unlikely for an unproved property to be successfully developed prior to the lease expiration or extension, an impairment of the respective unproved property is recognized in the period in which that determination is made.

Preferred equity

The Company accounts for preferred equity in accordance with ASC 480, Distinguishing Liabilities from Equity (“ASC 480”). The Series A Preferred Shares (as defined in

Note 9 – Preferred Equity

)

are not subject to any mandatory redemption and, accordingly, have been classified as permanent equity on the Company’s condensed consolidated balance sheets. Distributions are accrued as contractually obligated and are paid quarterly in arrears, when, as and if declared by the Company’s Board of Directors. The discount associated with the increasing-rate distributions is amortized using the effective interest method over the period preceding the commencement of the perpetual distribution rate. The accretion is recorded as an imputed distribution, recognized through retained earnings, with a corresponding increase to the carrying amount of the preferred equity.

Recently adopted accounting standards

In October 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2023-06, Disclosure Improvements: Codification Amendments in Response to the SEC’s Disclosure Update and Simplification Initiative (“ASU 2023-06”). ASU 2023-06 is intended to clarify or improve disclosure and presentation requirements of a variety of topics, which would allow users to more easily compare entities subject to the SEC’s existing disclosures with those entities that were not previously subject to the requirements, and align the requirements in the FASB accounting standard codification with the SEC’s regulations. The amendments in this ASU will be effective for public business entities on the effective date of the SEC’s removal of the related disclosures from Regulation S-X or Regulation S-K, and should be applied prospectively. If the SEC has not removed the applicable requirements from Regulation S-X or Regulation S-K by June 30, 2027, the amendments will not become effective for any entity. The Company adopted the provisions of ASU 2023-06 on July 1, 2025, and the adoption of this standard did not have a material impact on the Company’s condensed consolidated financial statements and related disclosures.

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 its financial statements and disclosures.

Accounting pronouncements not listed above were assessed and determined to not have a material impact on the Company’s condensed consolidated financial statements.

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Note 3 – Oil and Gas Properties

Oil and gas properties, net consist of the following:


(in thousands)	September 30, 2025			December 31, 2024
Proved oil and natural gas properties (a)	$	1,198,752		$	687,366
Unproved oil and natural gas properties		502,067			318,855

Total oil and gas properties		1,700,819			1,006,221
Less: Accumulated depletion		( 253,654	)		( 140,376	)

Oil and gas properties, net	$	1,447,165		$	865,845

(a)

Represents proved and undeveloped (i.e., wells in progress) and proved and producing properties.

The Company uses the successful efforts method of accounting for its oil and gas properties. Property acquisition costs are depleted on a

units-of-production

basis over total proved reserves, while costs of wells and related equipment and facilities are depleted on a

units-of-production

basis over proved developed reserves. Depletion on oil and gas properties was $

45.5

million and $

15.5

million for the three months ended September 30, 2025 and 2024, respectively, and $

113.3

million and $

52.7

million for the nine months ended September 30, 2025 and 2024, respectively.

Depreciation expense on the Company’s equipment and other property was less than $

0.1

million for both the three months ended September 30, 2025 and 2024 and less than $

0.1

million for both the nine months ended September 30, 2025 and 2024.

Impairment expense on the Company’s oil and gas properties was $

2.0

million and $

0.5

million for the three months ended September 30, 2025 and 2024, respectively, and $

2.5

million and $

0.5

million for the nine months ended September 30, 2025 and 2024, respectively, related to lease expirations and title defects on the Company’s oil and gas properties.

Note 4 – Revenue

The following tables present the Company’s revenues disaggregated by product type and by segment for the periods presented:


	Three Months Ended September 30, 2025
(in thousands)	Mineral and Non- operating		Operating		Securities		Eliminations			Total
Product sales
Crude oil	$	—	$	110,731	$	—	$	—		$	110,731
Natural gas		—		496		—		—			496
NGL		—		2,534		—		—			2,534

Total product sales		—		113,761		—		—			113,761

Mineral and royalty revenues
Crude oil		28,915		—		—		34			28,949
Natural gas		1,079		—		—		—			1,079
NGL		1,272		—		—		—			1,272

Total mineral and royalty revenues		31,266		—		—		34			31,300

Purchased crude oil sales		—		40,470		—		( 34	)		40,436
Water services		—		3,308		—		—			3,308
Other revenue		—		—		216		—			216
Intersegment revenue		129		—		37,197		( 37,326	)		—

Total revenues	$	31,395	$	157,539	$	37,413	$	( 37,326	)	$	189,021

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)


	Three Months Ended September 30, 2024
(in thousands)	Mineral and Non- operating		Operating		Securities		Eliminations			Total
Product sales
Crude oil	$	—	$	23,060	$	—	$	—		$	23,060
Natural gas		—		112		—		—			112
NGL		—		751		—		—			751

Total product sales		—		23,923		—		—			23,923

Mineral and royalty revenues
Crude oil		29,681		—		—		—			29,681
Natural gas		1,862		—		—		—			1,862
NGL		2,800		—		—		—			2,800

Total mineral and royalty revenues		34,343		—		—		—			34,343

Water services		—		728		—		—			728
Other revenue		—		—		46		—			46
Intersegment revenue		21		—		19,661		( 19,682	)		—

Total revenues	$	34,364	$	24,651	$	19,707	$	( 19,682	)	$	59,040


	Nine Months Ended September 30, 2025
(in thousands)	Mineral and Non- operating		Operating		Securities		Eliminations			Total
Product sales
Crude oil	$	—	$	290,371	$	—	$	—		$	290,371
Natural gas		—		1,133		—		—			1,133
NGL		—		3,786		—		—			3,786

Total product sales		—		295,290		—		—			295,290

Mineral and royalty revenues
Crude oil		84,171		—		—		64			84,235
Natural gas		4,374		—		—		—			4,374
NGL		4,562		—		—		—			4,562

Total mineral and royalty revenues		93,107		—		—		64			93,171

Purchased crude oil sales		—		71,300		—		( 64	)		71,236
Water services		—		8,508		—		—			8,508
Other revenue		—		—		397		—			397
Intersegment revenue		229		—		100,335		( 100,564	)		—

Total revenues	$	93,336	$	375,098	$	100,732	$	( 100,564	)	$	468,602

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)


	Nine Months Ended September 30, 2024
(in thousands)	Mineral and Non- operating		Operating		Securities		Eliminations			Total
Product sales
Crude oil	$	—	$	56,216	$	—	$	—		$	56,216
Natural gas		—		225		—		—			225
NGL		—		1,472		—		—			1,472

Total product sales		—		57,913		—		—			57,913

Mineral and royalty revenues
Crude oil		107,712		—		—		—			107,712
Natural gas		4,634		—		—		—			4,634
NGL		7,585		—		—		—			7,585

Total mineral and royalty revenues		119,931		—		—		—			119,931

Water services		—		1,632		—		—			1,632
Other revenue		—		—		74		—			74
Intersegment revenue		84		—		51,455		( 51,539	)		—

Total revenues	$	120,015	$	59,545	$	51,529	$	( 51,539	)	$	179,550

Note 5 – Other Current Assets

The following table summarizes the Company’s other current assets for the periods presented:


(in thousands)	September 30, 2025		December 31, 2024
Derivative assets	$	4,959	$	101
Prepaid expenses		4,014		3,068
Insurance recovery receivable		—		2,096
Deferred financing costs		—		1,964
Deposits		332		150
Other		18		149

Total	$	9,323	$	7,528

Note 6 – Derivatives

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 7 – 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 index price falls below the strike price. For put arrangements, no payment or receipt occurs if the index price is higher than the strike price. As of September 30, 2025, the Company’s derivatives were comprised of crude oil commodity derivative contracts indexed to the U.S. New York Mercantile Exchange West Texas Intermediate (“NYMEX 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 condensed consolidated statements of operations. All derivative contracts are recorded at fair market value and included in the condensed consolidated balance sheets as assets or liabilities. Derivative assets and liabilities are presented net on the condensed consolidated balance sheets when a legally enforceable master netting arrangement exists with the counterparty.

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

As of September 30, 2025, the Company’s open crude oil derivative contracts consisted of the following:


	Settlement Period
(volumes in Bbl and prices in $/Bbl)	2025		2026		2027		2028
Two-Way Collars
Notional Volumes		119,000		367,000		259,000		—
Weighted Average Ceiling Price	$	74.39	$	71.69	$	69.86	$	—
Weighted Average Floor Price	$	57.82	$	56.01	$	54.76	$	—
Swaps
Notional Volumes		1,495,098		3,852,672		2,278,448		667,398
Weighted Average Contract Price	$	62.58	$	62.18	$	61.85	$	60.70

The following table summarizes the gains and losses on derivative instruments included on the condensed consolidated statements of operations and the net cash payments related thereto for the periods presented. Cash flows associated with these

non-hedge

designated derivatives are reported within operating activities in the condensed consolidated statements of cash flows.


	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands)	2025		2024		2025		2024
Gain on derivative instruments	$	2,065	$	3,716	$	12,907	$	3,630
Net cash receipts on derivatives		943		88		1,317		32

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.

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

The following tables provide (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 condensed consolidated balance sheets as of September 30, 2025 and December 31, 2024. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.


	September 30, 2025
(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	$	—	$	8,617		$	—	$	8,617		$	( 3,658	)	$	4,959
Commodity derivatives	Other noncurrent assets		—		5,022			—		5,022			( 2,818	)		2,204

Total assets		$	—	$	13,639		$	—	$	13,639		$	( 6,476	)	$	7,163

Liabilities
Commodity derivatives	Other current liabilities	$	—	$	( 6,164	)	$	—	$	( 6,164	)	$	3,658		$	( 2,506	)
Commodity derivatives	Other noncurrent liabilities		—		( 3,280	)		—		( 3,280	)		2,818			( 462	)

Total liabilities		$	—	$	( 9,444	)	$	—	$	( 9,444	)	$	6,476		$	( 2,968	)


	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	)		—

Total assets		$	—	$	5,138		$	—	$	5,138		$	( 5,037	)	$	101

Liabilities
Commodity derivatives	Other current liabilities	$	—	$	( 4,574	)	$	—	$	( 4,574	)	$	2,037		$	( 2,537	)
Commodity derivatives	Other noncurrent liabilities		—		( 7,858	)		—		( 7,858	)		3,000			( 4,858	)

Total liabilities		$	—	$	( 12,432	)	$	—	$	( 12,432	)	$	5,037		$	( 7,395	)

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Note 7 – Debt

The following table summarizes the Company’s debt for the periods presented:


	Maturity Date
(in thousands)	Earliest Date		Latest Date		Interest Rate (a)	September 30, 2025			December 31, 2024
Fortress Term Loans		—		12/18/2027	Term SOFR + 7.1 %	$	400,000		$	250,000
Unregistered Debt Offerings
Regulation D Bonds		10/10/2025		9/10/2036	5.0 % to 14.0 %		683,641			497,823
Adamantium Securities		1/10/2029		9/10/2036	13.0 % to 16.5 %		218,155			135,180
Regulation A Bonds		10/10/2025		12/10/2027	9.0 %		59,679			104,884
Exchange Notes		5/10/2028		9/10/2036	9.0 % to 12.0 %		25,912			—

Total unregistered debt offerings							987,387			737,887
Registered Notes		5/10/2028		9/10/2036	9.0 % to 12.0 %		18,415			—

Total outstanding debt							1,405,802			987,887

Less: Unamortized debt discount and issuance costs (b)							( 133,000	)		( 89,432	)
Less: Current portion of long-term debt							( 145,348	)		( 103,240	)

Total long-term debt, net of current portion						$	1,127,454		$	795,215

(a)	Represents the contractual interest rates as of September 30, 2025.

(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 condensed consolidated statements of operations.

Fortress Credit Agreement

In April 2025, the Company amended the secured credit agreement with Fortress Credit Corp. (the “Fortress Credit Agreement”) and established a new tranche of term loans in an aggregate principal amount of $ 50.0 million (the “April Fortress Amendment”). The April Fortress Amendment was accounted for as a debt modification, with $ 25.0 million borrowed upon closing in April 2025 and $ 25.0 million borrowed in May 2025. In August 2025, the Fortress Credit Agreement was syndicated to include an additional institutional lender and further amended to establish a new tranche of term loans in an aggregate principal amount of $ 100.0 million (the “August Fortress Amendment”) that was borrowed in full upon closing. Additionally, the August Fortress Amendment established a $ 6.5 million tranche of loans which represents a contingent principal obligation that is only due and payable (together with accrued interest) upon certain conditions occurring, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing. The August Fortress

Amendment

also revised

the

mandatory repayment schedule such that $ 200.0

million of the outstanding principal amount of the term loans under the Fortress Credit Agreement is due by

August 2027 ,

with the remainder due upon maturity in December 2027. The term loans under the Fortress Credit Agreement bear interest at a rate per annum equal to Term Secured Overnight Financing Rate (“SOFR”) plus a margin of

7.10 %. Proceeds are to be used to finance the development of the Company’s oil and gas properties in accordance with the approved plan of development provided in the Fortress Credit Agreement.

The Company had an aggregate principal amount outstanding of $ 400.0 million and $ 250.0

million under the Fortress Credit Agreement as of September 30, 2025 and December 31, 2024, respectively. The

all-in

interest rate for the term loans under the Fortress Credit Agreement was

11.4

and 11.7

% at September 30, 2025 and December 31, 2024, respectively. The Fortress Credit Agreement contains various customary covenants, including financial covenants that require the Company to maintain ratios around its maximum total secured leverage, minimum asset coverage, and working capital as of the last day of each calendar month or fiscal quarter, as the case may be. On October 27, 2025, subsequent to the balance sheet date, the Company executed an amendment of the Fortress Credit Agreement, which provided a waiver of default on its current ratio as of September 30, 2025. The Company has also entered into hedges covering at least

75.0

% of the initially anticipated monthly production of crude oil from the Company’s proved developed reserves for a

36-month

period, pursuant to the terms of the Fortress Credit Agreement. See

Note 6 – Derivatives

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Registered Notes

In October 2024, the Company filed a registration statement on Form

S-1

(the “Registration Statement”) with the SEC, which was declared effective in May 2025, with respect to the continuous offering of up to $ 750.0 million aggregate principal amount of the Company’s senior subordinated notes (the “Registered Notes”) with maturity dates ranging from three to eleven years from the issue date and interest rates ranging from 9.0 % to 12.0 % per annum.

The Registered Notes are contractually senior to bonds sold pursuant to offerings under Rule 506(c) of Regulation D under the Securities Act (the “Regulation D Bonds”) that commenced in December 2022 (the “December 2022 506(c) Bonds”) and August 2023 (the “August 2023 506(c) Bonds”), and subordinated to the term loans under the Fortress Credit Agreement, the Adamantium Securities and Regulation D Bonds whose offerings commenced in October 2020 and July 2022. The Registered Notes contain customary events of default and may be redeemed at the option of the Company at any time without premium or penalty. The holders of Registered Notes also have a right to request redemption of their notes 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. As of September 30, 2025, the Company had $ 18.4 million of aggregate principal amount outstanding of the Registered Notes.

Unregistered Debt Offerings

Regulation D Bonds

In May 2025, the Company approved an increase to the maximum offering amount of the August 2023 506(c) Bonds from $ 750.0 million to $ 1,500.0 million. The August 2023 506(c) Bonds are unsecured bonds offered and sold 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. As of September 30, 2025

and December 31, 2024

, the Company had $ 683.6 million

and $ 497.8 million

of aggregate principal amount outstanding of the Regulation D Bonds

, respectively

Regulation A Bonds and Exchange Notes

In May 2025, the Company entered into an indenture to issue to holders of its unsecured three-year 9.0 % bonds offered and sold pursuant to an offering under Regulation A promulgated under the Securities Act that commenced in December 2021 and terminated in December 2024 (the “Regulation A Bonds”), unsecured senior subordinated obligations in an offering exempt from registration under Section 3(a)(9) and/or 4(a)(2) of the Securities Act (the “Exchange Notes”). The Exchange Notes have maturities of three, five, seven, and/or eleven years and interest rates ranging from 9.0 % to 12.0 % per annum. As of September 30, 2025, $ 25.9 million aggregate principal amount of the Regulation A Bonds were exchanged to Exchange Notes

and $ 59.7 million of the Regulation A Bonds remained outstanding.

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 16.0 % 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. As of September 30, 2025

and December 31, 2024

, the Company had $ 218.2 million

and $ 135.2 million

of aggregate principal amount outstanding of the Adamantium Securities

, respectively

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Interest Expense on Debt

The following table summarizes the total interest costs incurred on the Company’s debt:


	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2025			2024			2025			2024
Stated interest	$	43,165		$	26,172		$	113,005		$	57,571
Amortization of debt discount and debt issuance costs		6,530			4,051			17,934			11,703

Total interest cost		49,695			30,223			130,939			69,274
Capitalized interest		( 10,879	)		( 4,022	)		( 19,249	)		( 8,158	)

Total interest expense, net	$	38,816		$	26,201		$	111,690		$	61,116

Note 8 – Other Current Liabilities

The following table summarizes the Company’s other current liabilities for the periods presented:


(in thousands)	September 30, 2025		December 31, 2024
Revenue payable	$	38,133	$	4,441
Production taxes payable		8,725		—
Advances from joint interest partners		5,577		4,105
Accrued interest		4,219		1,746
Unredeemed matured bonds		2,570		1,338
Derivative liabilities		2,506		2,537
Asset retirement obligations		483		165
Other		1,450		1,548

Total	$	63,663	$	15,880

In circumstances where the Company serves as the operator, the Company receives production proceeds from purchasers and distributes revenue to royalty owners and working interest owners based on their ownership interests. Production proceeds that the Company has not yet distributed are reflected as revenue payable and classified as a component of other current liabilities in the condensed consolidated balance sheets. Production taxes payable represents production taxes assessed on the Company’s operated volumes that have been incurred but not yet remitted as of the balance sheet date. Additionally, working interest owners who participate in our wells may elect to prepay a portion of the estimated drilling and completion costs. For such advances, a liability is recorded and subsequently reduced as the associated work is performed and billed to the working interest owners.

Note 9 – Preferred Equity

In September 2025, the Company completed its offering of the Series A Cumulative Redeemable Preferred Shares (the “Series A Preferred Shares”) pursuant to Regulation A promulgated under the Securities Act of 1933

as amended

which shares were listed on the NYSE American under the ticker symbol PHXE.P and commenced trading on September 30, 2025.

The Company sold an aggregate of 2,704,023 Series A Preferred Shares at closing, which represented $ 67.6 million in initial liquidation preference at a public offering price of $ 20.00 per share for gross proceeds of $ 54.1 million. Offering costs of $ 6.2 million were recorded as a reduction of the gross proceeds.

Voting Rights

Holders of the Series A Preferred Shares generally have no voting rights. However, if the Company does not pay distributions on the Series A Preferred Shares for six or more quarterly distribution periods (whether or not consecutive), the holders of the Series A Preferred Shares will be entitled to vote for the election of two additional directors to serve on the Board of Directors until the Company pays, or declares and sets aside funds for the payment of, all distributions that the Company owes on the Series A Preferred Shares.

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Dividend Rights

The Series A Preferred Shares rank senior to all classes of equity securities issued by the Company (including common equity) and are junior to all existing and future indebtedness of the Company. Holders of the Series A Preferred Shares are entitled to receive cumulative cash distributions based on the initial liquidation preference of $ 25.00 per share, accruing from the initial issuance date and, when, as and if declared by the Company’s Board of Directors, payable quarterly in arrears on January 15, April 15, July 15, and October 15 of each year, beginning on October 15, 2025. The annual distribution rate is 10.0 % for the first three year-period, 10.5 % in the fourth year, and 11.0 % in the fifth year and thereon. As of September 30, 2025, $ 0.3 million of Series

A Preferred distributions equal to $ 0.11111 per share had been declared and scheduled to be paid on October 15, 2025 to the holders on record as of October 1, 2025.

Liquidation Rights

In the event of the Company’s voluntary or involuntary liquidation, dissolution, or winding up, the holders of the Series A Preferred Shares will generally have the right to receive the initial liquidation preference of $ 25.00 per Series A Preferred Share, plus any accumulated and unpaid distributions.

Redemption Rights

The Series A Preferred Shares are not redeemable at the option of the holders. The Series A Preferred Shares, are, however, redeemable at the Company’s option, in whole or in part, at a cash redemption price of $ 27.50 per share, plus any accumulated and unpaid distributions.

Conversion

The Series A Preferred Shares are not convertible or exchangeable for any securities or property of the Company.

Note 10 – Equity-Based Compensation

The Company’s parent, Phoenix Equity Holdings, LLC (“Phoenix Equity”), has granted equity awards to employees of the Company under the 2024 Long-Term Incentive Plan (the “2024 Incentive Plan”). The 2024 Incentive Plan provides for the issuance of 900,000 Class A Units, 2,813,900 Class B Units and 1,000,000 Phantom Units. As of September 30, 2025, Phoenix Equity had issued all authorized Class A Units and Class B Units and 30,500 Phantom Units under the 2024 Incentive Plan.

A summary of the activity under the 2024 Incentive Plan for the nine months ended September 30, 2025 is presented below.


	Number of Units		Weighted Average Per Share Grant Date Fair Value
Nonvested at December 31, 2024		3,175,150	$	55.74
Granted - Phantom Units		30,500		55.81
Vested		—		—
Forfeited		—		—

Nonvested at September 30, 2025		3,205,650	$	55.74

During the nine months ended September 30, 2025, Phoenix Equity granted 30,500 Phantom Unit awards contingent on the achievement of a performance condition, all of which will vest only upon the Company undergoing a liquidity event (e.g., change in control). No compensation cost will be recognized for the Phantom Unit awards until a liquidity event occurs. The Company has elected to account for forfeitures as they occur.

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

As of September 30, 2025, there was $ 178.7 million of total unrecognized compensation cost related to nonvested equity 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 nine months ended September 30, 2025, are presented in the table below:


	2025
Dividend yield (a)		—	%
Risk-free interest rate (b)		4.4	%
Expected volatility (c)		57.5	%
Expected term (in years) (d)		5.0
Discount for lack of marketability (e)		30.0	%

(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.

Note 11 – Related Parties

Debt Offerings

Certain of the Company’s officers and their family members participate in the Company’s unregistered debt offerings. During the nine months ended September 30, 2025 and 2024, these officers and their family members purchased, in aggregate, 1,104 and 4,208 of the combined Regulation A Bonds and Regulation D Bonds for a total purchase price of $ 1.1 million and $ 4.2 million, respectively. As of September 30, 2025 and December 31, 2024, there were 3,951 and 2,860 of bonds outstanding with carrying values of $ 4.0 million and $ 2.9 million, respectively. Interest expense attributable to these securities was $ 0.1 million for both the three months ended September 30, 2025 and 2024, and $ 0.4 million for both the nine months ended September 30, 2025 and 2024.

Lion of Judah

The Company paid interest expense to a financial institution on behalf of Lion of Judah related to a certain financing agreement between Lion of Judah and the financial institution of less than $ 0.1 million for both the three months ended September 30, 2025 and 2024, and less than $ 0.1

million and less than $

0.2

million for the nine months ended September 30, 2025 and 2024, respectively. Interest payments made by the Company on behalf of Lion of Judah are discretionary in nature.

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Note 12 – Leases

The Company leases its office facilities primarily under noncancelable multi-year operating lease agreements.

The following table shows the line item classification of the Company’s

right-of-use

assets and lease liabilities on the Company’s condensed consolidated balance sheets:


(in thousands)	Line item	September 30, 2025		December 31, 2024
Right-of-use assets – operating	Right of use assets, net	$	9,814	$	6,010

Total right-of-use assets		$	9,814	$	6,010

Current operating lease liabilities	Current operating lease liabilities	$	1,149	$	656
Noncurrent operating lease liabilities	Operating lease liabilities		9,918		5,860

Total lease liabilities		$	11,067	$	6,516

Operating lease cost of $ 1.1 million and $ 0.6 million for the three months ended September 30, 2025 and 2024, respectively, and $ 2.3 million and $ 1.2 million for the nine months ended September 30, 2025 and 2024, respectively, was classified as a component of selling, general, and administrative expense on the condensed consolidated statements of operations.

Note 13 – Commitments and Contingencies

For a summary of the Company’s lease obligations, see

Note 12 – 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 may enter into drilling rig contracts in the ordinary course of business 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. The contracts provide for termination at the election of the Company but may include an early termination payment if the contract is terminated prior to the expiration of the fixed term.

Natural Gas Processing Contracts

The Company has entered into contracts for mobile cryogenic gas processing units to process raw gas, produce and store NGLs, and compress residue natural gas at wells operated by PhoenixOp. The contracts range from 6 months to 36 months and provide monthly facility and service fees as consideration for services performed by the third-party provider. As of September 30, 2025, the Company was subject to $ 7.2 million of commitments under these contracts.

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Note 14 – Supplemental Cash Flow Information

The following table summarizes supplemental information to the condensed consolidated statements of cash flows for the periods presented:


	Nine Months Ended September 30,
(in thousands)	2025		2024
Supplemental disclosure of cash flow information:
Cash interest paid, net of capitalized interest	$	66,987	$	28,546
Cash paid for operating leases		940		676
Supplemental disclosure of non-cash transactions:
Capital expenditures in accounts payable and accrued and other liabilities	$	132,903	$	33,994
Modification of right-of-use asset and lease liability		1,985		451
Right-of-use asset obtained in exchange for lease liability		2,667		—
Unpaid property acquisition costs in deferred closings		4,651		1,149
Series A Preferred Shares distributions declared but unpaid		37		—
Series A Preferred Shares discount accretion		3		—

Note 15 – Segments

Segment operating profit is used as a performance metric by the Chief Operating Decision Maker (“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 and headcount, as appropriate. Segment operating profit excludes other income and expense, such as interest expense, interest income, gain 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 on derivatives are allocated using the same basis as corporate costs.

The following table summarizes segment operating profit and reconciliation to net income (loss) for the periods presented:


	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2025			2024			2025			2024
Segment operating profit
Mineral and Non-operating	$	5,126		$	12,078		$	22,291		$	41,873
Operating		44,258			2,961			120,424			13,208
Securities		34,083			16,126			89,749			43,118
Eliminations		( 37,197	)		( 19,661	)		( 100,335	)		( 51,455	)

Total segment operating profit		46,270			11,504			132,129			46,744

Interest income		303			261			1,355			316
Interest expense, net		( 38,816	)		( 26,201	)		( 111,690	)		( 61,116	)
Gain on derivatives		2,065			3,716			12,907			3,630
Loss on debt extinguishment		( 1,334	)		( 567	)		( 1,916	)		( 868	)

Net income (loss)	$	8,488		$	( 11,287	)	$	32,785		$	( 11,294	)

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

The following tables present financial information by segment for the three and nine months ended September 30, 2025 and 2024 and as of September 30, 2025 and December 31, 2024.


	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands)	2025			2024			2025			2024
Significant expenses
Mineral and Non-operating
Cost of sales	$	6,929		$	7,017		$	18,239		$	22,273
Depreciation, depletion, amortization, and accretion		10,286			8,552			25,640			36,518
Selling, general, and administrative		4,742			4,029			14,476			10,072
Payroll and payroll-related		2,325			2,166			10,181			8,135
Other segment items (a)		1,987			522			2,509			1,144
Operating
Cost of sales	$	36,120		$	10,411		$	87,162		$	18,145
Depreciation, depletion, amortization, and accretion		35,264			6,989			87,752			16,798
Purchased crude oil expenses		39,623			—			69,975			—
Selling, general, and administrative		24			2,781			3,118			7,059
Payroll and payroll-related		2,250			1,515			6,667			4,283
Other segment item (b)		—			( 6	)		—			52
Securities
Advertising and marketing	$	694		$	201		$	1,531		$	246
Selling, general, and administrative		774			2,131			3,841			4,921
Payroll and payroll-related		1,862			1,249			5,611			3,244
Interest expense
Mineral and Non-operating	$	25,842		$	15,296		$	71,816		$	41,467
Operating		12,974			10,905			39,874			19,649
Securities		37,197			19,661			100,335			51,455
Eliminations		( 37,197	)		( 19,661	)		( 100,335	)		( 51,455	)

Total interest expense, net	$	38,816		$	26,201		$	111,690		$	61,116

Capital expenditures
Mineral and Non-operating	$	81,533		$	45,761		$	218,334		$	144,205
Operating		186,252			48,862			408,973			141,423
Eliminations		( 10,813	)		( 228	)		( 21,267	)		( 5,278	)

Total capital expenditures	$	256,972		$	94,395		$	606,040		$	280,350

(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.

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)


(in thousands)	September 30, 2025			December 31, 2024
Assets
Mineral and Non-operating	$	1,244,829		$	898,300
Operating		755,453			332,721
Securities		3,619			6,918
Eliminations		( 363,427	)		( 208,869	)

Total assets	$	1,640,474		$	1,029,070

The following tables summarize the Company’s oil and natural properties by proved and unproved properties, location and by segment (before accumulated depletion):


	September 30, 2025
(in thousands)	Mineral and Non-operating		Operating		Securities		Eliminations		Consolidated Total
Oil and natural gas properties, proved
Williston Basin	$	222,580	$	812,219	$	—	$	—	$	1,034,799
Powder River Basin		52,095		—		—		—		52,095
Denver-Julesburg		47,491		—		—		—		47,491
Permian Basin		20,182		—		—		—		20,182
Marcellus		1,306		—		—		—		1,306
Uinta Basin		41,187		—		—		—		41,187
Other		1,692		—		—		—		1,692

Total proved properties	$	386,533	$	812,219	$	—	$	—	$	1,198,752

Oil and natural gas properties, unproved
Williston Basin	$	372,273	$	7,681	$	—	$	—	$	379,954
Powder River Basin		36,084		—		—		—		36,084
Denver-Julesburg		35,161		—		—		—		35,161
Permian Basin		6,680		—		—		—		6,680
Uinta Basin		42,352		—		—		—		42,352
Other		1,836		—		—		—		1,836

Total unproved properties	$	494,386	$	7,681	$	—	$	—	$	502,067

Table of Contents

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)


	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

Note 16 – Subsequent Events

In October 2025, the Company paid cash distributions totaling $ 0.3 million to holders of its Series A Preferred Shares, pursuant to distributions declared by the Company’s Board of Directors in September 2025.

In October 2025, the Company amended the Fortress Credit Agreement (the “Amendment”) and established a new tranche of term loans in an aggregate principal amount of $ 350.0 million, with $ 50.0 million borrowed upon closing

of the Amendment

and up to $ 300.0 million available to be funded on a discretionary basis

on a delayed draw term loan during a specific availability period as set forth in the Amendment. The Amendment changed the maturity date to October 27, 2028 and revised the mandatory repayment schedule such that $ 225.0 million plus 50% of the aggregate principal amount of the new $ 300.0 million delayed draw term loan borrowed is due October 31, 2027

. The Amendment also revised certain covenants contained in the Fortress Credit Agreement and added a $ 5.0

million quarterly limit on the amount of Series A Preferred Shares that the Company may redeem, which may be reduced by the amount of cash payments made during such quarter to the extent related to refinancing transactions on the Company’s outstanding bonds as described in the Amendment. Proceeds will be used to finance the development of the Company’s oil and gas properties in accordance with the approved plan of development provided in the Fortress Credit Agreement.

In October and November 2025, the Company entered into additional fixed swap contracts for a total notional volume of 3.0 million Bbls at a weighted average contract price of $ 59.86 with settlement dates through September 2028. The notional volumes are scheduled to settle as follows: 0.3 million Bbls in 2025, 1.0 million Bbls in 2026, 0.6 million Bbls in 2027 and 1.1 million Bbls in 2028. These commodity derivative contracts were executed pursuant to the Company’s debt covenant requirements under the amended Fortress Credit Agreement.

The Company is continuing to raise debt capital under its exempt and registered debt offerings. Since the balance sheet date and through the date of filing of these condensed consolidated financial statements, the Company issued approximately $ 54.2 million of debt securities under these offerings.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this Quarterly Report as well as our audited financial statements and the related notes thereto and related management’s discussion and analysis in each case, included in our prospectus for our offering of Registered Notes (as defined below), dated May 14, 2025 and filed with the SEC pursuant to Rule 424(b)(4) on May 14, 2025. 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” and “Cautionary Statement Regarding Forward-Looking Statements” and elsewhere in this Quarterly Report. 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. 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, Uinta, and Denver-Julesburg Basins. We are agnostic as to geography and prioritize operational and asset potential when executing on our strategy.

As of September 30, 2025, we have completed 4,998 acquisitions from landowners and other mineral interest owners since 2019, and currently retain approximately 556,323 NRAs in mineral holdings and 612,009 NMAs in leasehold assets. Additionally, we commenced direct drilling operations and spudded our first wells in the third quarter of 2023 and, as of September 30, 2025, we had drilled a total of 93.0 gross and 84.7 net producing development and injection wells. 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.

Following the acquisition of an asset, we typically share in the proceeds of the natural resources extracted and sold by a third-party exploration and production (“E&P”) operator. For certain assets, we operate our own direct drilling operations through PhoenixOp.

For the three months ended September 30, 2025 and 2024, we had revenue of $189.0 million and $59.0 million, respectively, net income of $8.5 million and net loss of $11.3 million, respectively, and EBITDA of $92.6 million and $30.2 million, respectively. For the nine months ended September 30, 2025 and 2024, we had revenue of $468.6 million and $179.6 million, respectively, net income of $32.8 million and net loss of $11.3 million, respectively, and EBITDA of $256.5 million and $102.8 million, respectively. As of September 30, 2025 and December 31, 2024, we had total assets of $1,640.5 million and $1,029.1 million, respectively, total liabilities of $1,593.9 million and $1,063.1 million, respectively (inclusive of total indebtedness of $1,405.8 million and $987.9 million, respectively), and accumulated deficit of $1.7 million and $34.5 million, respectively. Through 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 2024. During the nine months ended September 30, 2025, we continued to incur additional debt. Furthermore, as of December 31, 2024, we estimated that we would 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 would 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 Registered Notes, 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,” and “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 Registered Notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.”

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 60.2% and 63.0% of our total revenues for the three and nine months ended September 30, 2025, respectively, and we expect to derive a greater portion of our total revenues from product sales of crude oil, natural gas, and NGL 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 non-operated working interest owner, we may incur lease operating expenses and for both royalty and non-operated working interest ownership, our proportionate share of production, severance, and ad valorem taxes. In these 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.

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 typically 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 continue 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 and 2025 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 we continue to invest in capital assets and 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.

Selling, 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, Net

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 U.S. New York Mercantile Exchange West Texas Intermediate (“NYMEX 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. 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 NYMEX 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.

Natural Gas. The NYMEX WTI 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 WTI 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

There is typically a lag (e.g., six to eighteen months or longer) between when acquisitions are made and when those investments generate meaningful revenue. As a result, many of the investments we made in 2024 began generating revenue in 2025, and we anticipate the same delayed effect will occur from 2025 to 2026 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 Registered 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 a significant factor impacting our revenues, profitability, operating cash flows, the amount of capital we invest in our business, and redemption of our debt. During the period from January 1, 2021 through September 30, 2025, prices for crude oil reached a high of $123.64 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 nine months ended September 30, 2025, the average NYMEX WTI crude oil and natural gas prices were $67.31 per Bbl and $3.45 per MMBtu, respectively, representing a decrease of 14.3% and an increase of 63.7%, respectively, from the average NYMEX WTI prices during the nine months ended September 30, 2024.

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 also continue to monitor 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

We expect to incur incremental non-recurring costs related to our transition to being a public company, including 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

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 in 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.

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 September 30, 2025, PhoenixOp placed an additional 68 wells in production, and had 42 wells in various stages of development. In PhoenixOp’s first full year of production, product sales revenue was $125.6 million. For the nine months ended September 30, 2025, PhoenixOp’s operations increased, and its product sales revenue was $295.3 million. As more wells continue to commence production, and more properties are contributed to PhoenixOp for potential future drilling activities, 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 through the remainder of 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.

Results of Operations

Third Quarter 2025 Financial and Operational Highlights

•

In August 2025, the Fortress Credit Agreement was amended to syndicate the facility to include an additional institutional lender and to increase the borrowing capacity by $100.0 million, which was borrowed in full upon closing.

•

We closed our initial public offering of the Series A Cumulative Redeemable Preferred Shares and sold an aggregate of 2,704,023 shares, representing $67.6 million in initial liquidation preference at a public offering price of $20.00 per share for gross proceeds of $54.1 million.

•

Our wholly-owned subsidiary, PhoenixOp, became the first operator in the Williston Basin to drill five four-mile lateral wells from a single pad. One of these wells, the Nystuen 20-17-8-5-1H, achieved a total lateral length of 20,797.5 feet, representing the longest drilled lateral in the Williston Basin as of such date. The Nystuen wells were completed in September 2025.

•

In August 2025, PhoenixOp commenced drilling activities on our Willow Gray pad, consisting of six four-mile lateral wells. Once completed, we will be the first operator in the Williston Basin to drill six four-mile laterals from a single pad location. Two of these six wells were drilled in fewer than 10 days, with the fastest well drilled in only 9.29 days, representing the fastest four-mile well drilled in the Williston Basin as of such date.

•

In August 2025, PhoenixOp commissioned both the Daniel Ferrari and Willer pads. The Daniel Ferrari wells were the longest laterals drilled by us to date, with two wells extending approximately 3.75 miles. Between the Daniel Ferrari and Willer pads, we achieved our highest initial production rates to date, with peak daily oil production of 1,153 and 1,100 barrels of oil, respectively.

•

The Willer pad wells represent the lowest cost per well in our portfolio to date, with an average cost of approximately $6.3 million per well, or $1.4 million below budget, resulting in total project savings of approximately $8.6 million.

Three Months Ended September 30, 2025 Compared to the Three Months Ended September 30, 2024

The following table summarizes our consolidated results of operations for the periods indicated:


	Three Months Ended September 30,						Change
(in thousands)	2025			2024			$			%
Revenues
Product sales	$	113,761		$	23,923		$	89,838			375.5	%
Mineral and royalty revenues		31,300			34,343			(3,043	)		(8.9	)%
Purchased crude oil sales		40,436			—			40,436			NM
Water services		3,308			728			2,580			354.4	%
Other revenue		216			46			170			369.6	%

Total revenues		189,021			59,040			129,981			220.2	%

Operating expenses
Cost of sales		42,920			17,407			25,513			146.6	%
Depreciation, depletion, amortization, and accretion		45,550			15,541			30,009			193.1	%
Purchased crude oil expenses		39,623			—			39,623			NM
Selling, general, and administrative		5,540			8,941			(3,401	)		(38.0	)%
Payroll and payroll-related		6,437			4,930			1,507			30.6	%
Advertising and marketing		694			189			505			267.2	%
Impairment expense		1,987			528			1,459			276.3	%

Total operating expenses		142,751			47,536			95,215			200.3	%

Income from operations		46,270			11,504			34,766			302.2	%

Other income (expense)
Interest income		303			261			42			16.1	%
Interest expense, net		(38,816	)		(26,201	)		(12,615	)		(48.1	)%
Gain on derivatives		2,065			3,716			(1,651	)		(44.4	)%
Loss on debt extinguishment		(1,334	)		(567	)		(767	)		(135.3	)%

Total other expenses		(37,782	)		(22,791	)		(14,991	)		(65.8	)%

Net income (loss)	$	8,488		$	(11,287	)	$	19,775			175.2	%

NM – not meaningful.

The following tables summarize our segment operating profit for the periods indicated:


	Three Months Ended September 30, 2025
(in thousands)	Mineral and Non-operating			Operating			Securities			Eliminations			Total
Total revenues	$	31,395		$	157,539		$	37,413		$	(37,326	)	$	189,021
Total operating expenses		(26,269	)		(113,281	)		(3,330	)		129			(142,751	)

Segment operating profit	$	5,126		$	44,258		$	34,083		$	(37,197	)	$	46,270


	Three Months Ended September 30, 2024
(in thousands)	Mineral and Non-operating			Operating			Securities			Eliminations			Total
Total revenues	$	34,364		$	24,651		$	19,707		$	(19,682	)	$	59,040
Total operating expenses		(22,286	)		(21,690	)		(3,581	)		21			(47,536	)

Segment operating profit	$	12,078		$	2,961		$	16,126		$	(19,661	)	$	11,504

The following table summarizes our production data and average realized prices for the periods indicated:


	Three Months Ended September 30,				Change
	2025		2024		$			%
Production Data:
Crude oil (Bbls)		2,217,933		736,495		1,481,438			201.1	%
Natural gas (Mcf)		807,489		1,212,187		(404,698	)		(33.4	)%
NGL (Bbls)		197,696		115,125		82,571			71.7	%

Total (BOE)(6:1)		2,550,211		1,053,651		1,496,559			142.0	%
Average daily production (BOE/d) (6:1)		27,720		11,453		16,267			142.0	%
Average Realized Prices ^(a) :
Crude oil (Bbl)	$	62.97	$	72.01	$	(9.04	)		(12.6	)%
Natural gas (Mcf)	$	1.95	$	1.53	$	0.42			27.5	%
NGL (Bbl)	$	19.25	$	29.30	$	(10.05	)		(34.3	)%

(a)	Average realized prices are net of certain post-production costs that are deducted from our royalties.

Revenues

The following table shows the components of our revenue for the periods presented:

	$		$		$			$
	Three Months Ended September 30,				Change
(in thousands)	2025		2024		$			%
Product sales
Crude oil	$	110,731	$	23,060	$	87,671			380.2	%
Natural gas		496		112		384			342.9	%
NGL		2,534		751		1,783			237.4	%

Total product sales		113,761		23,923		89,838			375.5	%

Mineral and royalty revenues
Crude oil		28,949		29,681		(732	)		(2.5	)%
Natural gas		1,079		1,862		(783	)		(42.1	)%
NGL		1,272		2,800		(1,528	)		(54.6	)%

Total mineral and royalty revenues		31,300		34,343		(3,043	)		(8.9	)%

Purchased crude oil sales		40,436		—		40,436			NM
Water services		3,308		728		2,580			354.4	%
Other revenue		216		46		170			369.6	%

Total revenues	$	189,021	$	59,040	$	129,981			220.2	%

NM – not meaningful.

Revenue was $189.0 million for the three months ended September 30, 2025, as compared to $59.0 million for the same period in 2024, an increase of $130.0 million, or 220.2%. The increase was primarily attributable to an $89.8 million increase in product sales generated from our direct drilling, extraction, and related oil and gas operating activities, $40.4 million of purchased crude oil sales derived from the sale of crude oil purchased from working interest owners and royalty interest holders in wells operated by PhoenixOp that did not exist in the prior period, and a $2.6 million increase in revenue from water disposal services, partially offset by a $3.0 million decrease 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 $31.4 million for the three months ended September 30, 2025, as compared to $34.4 million for the same period in 2024, a decrease of $3.0 million, or 8.6%. The decrease in segment revenue was driven by a $1.5 million decrease in revenues from NGLs primarily due to a decrease in the average realized price for NGLs from $29.30/Bbl to $19.25/Bbl in 2025 as compared to the same period in 2024, a $0.8 million decrease in revenues from natural gas due to decreased production volumes, and a $0.7 million decrease in revenues from crude oil primarily due to a decrease in the average realized price for crude oil from $72.01/Bbl to $62.97/Bbl.

Operating Segment

Operating segment revenue was $157.5 million for the three months ended September 30, 2025, as compared to $24.7 million for the same period in 2024, an increase of $132.9 million, or 539.1%. The increase was primarily attributable to an $89.8 million increase in product sales generated from our direct drilling, extraction, and related operating activities driven by additional wells placed into service, of which there were 78 producing wells in service as of September 30, 2025, as compared to 10 producing wells in service as of September 30, 2024, $40.4 million of purchased crude oil sales derived from the sale of crude oil purchased from working interest owners and royalty interest holders in wells operated by PhoenixOp beginning in April 2025, and a $2.6 million increase in water service revenue driven by higher disposal volumes, with 6.8 million barrels of saltwater disposed by Firebird Services, LLC (“Firebird Services”) during the three months ended September 30, 2025, as compared to 1.4 million barrels during the same period in 2024.

Operating Expenses

Cost of Sales

The following table shows the components of our cost of sales for the periods presented:


	Three Months Ended September 30,				Change
(in thousands)	2025		2024		$		%
Cost of sales
Production taxes	$	11,648	$	7,050	$	4,598		65.2	%
Lease operating expenses		19,217		5,641		13,576		240.7	%
Production costs		12,055		4,716		7,339		155.6	%

Total	$	42,920	$	17,407	$	25,513		146.6	%

Cost of sales was $42.9 million for the three months ended September 30, 2025, as compared to $17.4 million for the same period in 2024, an increase of $25.5 million, or 146.6%. The increase was primarily driven by increased drilling, extraction and related oil and gas operating activities associated with wells operated by PhoenixOp during the three months ended September 30, 2025 as compared to the same period in 2024.

Mineral and Non-operating Segment

Mineral and non-operating segment cost of sales was $6.9 million for the three months ended September 30, 2025, as compared to $7.0 million for the same period in 2024. The decrease was not material to the mineral and non-operating segment for the periods presented.

Operating Segment

Operating segment cost of sales was $36.1 million for the three months ended September 30, 2025, as compared to $10.4 million for the same period in 2024, an increase of $25.7 million, or 246.9%. The increase in segment cost of sales was driven by increased production from PhoenixOp, which commenced operated production in the first quarter of 2024. PhoenixOp had placed into service 78 producing wells as of September 30, 2025, as compared to 10 producing wells as of September 30, 2024, resulting in increased lease operating expenses, production and ad valorem taxes, and production costs during the three months ended September 30, 2025 as compared to the same period in 2024.

Depreciation, Depletion, Amortization, and Accretion Expense

The following table shows the components of our depletion, depreciation, amortization, and accretion expense for the periods presented:


	Three Months Ended September				Change
(in thousands)	2025		2024		$			%
Depreciation, depletion, amortization, and accretion
Depletion	$	45,463	$	15,456	$	30,007			194.1	%
Depreciation		12		4		8			200.0	%
Accretion on asset retirement obligations		75		81		(6	)		(7.4	)%

Total	$	45,550	$	15,541	$	30,009			193.1	%

Depreciation, depletion, amortization, and accretion expense was $45.6 million for the three months ended September 30, 2025, as compared to $15.5 million for the same period in 2024, an increase of $30.0 million, or 193.1%, primarily due to a $28.3 million increase in depletion expense within the operating segment, driven by increases in our depletable cost bases and a $1.7 million increase in depletion expense within the mineral and non-operating segment, primarily due to a higher depletion rate driven by increases in our depletable cost bases for capital expenditures.

Mineral and Non-operating Segment

Depletion for the mineral and non-operating segment was $10.3 million for the three months ended September 30, 2025, as compared to $8.6 million for the same period in 2024, an increase of $1.7 million, or 20.3%. On a per unit basis, depletion expense was $15.62 per Boe and $11.75 per Boe for the three months ended September 30, 2025 and 2024, respectively, an increase of $3.87 per Boe, driven by a higher depletion rate primarily due to an increase in our depletable cost bases for capital expenditures.

Operating Segment

Depletion for the operating segment was $35.3 million for the three months ended September 30, 2025, as compared to $7.0 million for the same period in 2024, an increase of $28.3 million, or 404.6%, primarily due to increases in the depletable cost bases, partially offset by a lower depletion rate during the three months ended September 30, 2025 as compared to the same period in 2024. The lower depletion rate is primarily attributable to significant growth in proved reserves due to drilling activity by PhoenixOp.

Purchased Crude Oil Expense

Purchased crude oil expense was $39.6 million for the three months ended September 30, 2025, with no comparable activity for the same period in 2024. This change is attributable to the commencement of marketing activities in April 2025 through our wholly-owned subsidiary, Firebird Marketing, LLC (“Firebird Marketing”), within the operating segment. Purchased crude oil expense represents the purchase of crude oil from working interest owners and royalty interest holders in properties operated by PhoenixOp.

Selling, General, and Administrative Expense

Selling, general, and administrative expense was $5.5 million for the three months ended September 30, 2025, as compared to $8.9 million for the same period in 2024, a decrease of $3.4 million, or 38.0%. The decrease was primarily due to a $3.4 million decrease in professional legal service fees and a $2.8 million increase in the overhead charged to wells operated by us, which reduced selling, general, and administrative expense. The decrease was partially offset by a $1.1 million increase in financing-related costs, including administrative costs associated with our securities offerings, a $0.8 million increase in fees associated with land acquisition and title work, a $0.4 million increase in office rent expense and a $0.3 million increase in fees charged by purchasers for early revenue payments in the operating segment.

Mineral and Non-operating Segment

Selling, general, and administrative expense for the mineral and non-operating segment was $4.7 million for three months ended September 30, 2025, as compared to $4.0 million for the same period in 2024, an increase of $0.7 million, or 17.7%. The increase was primarily due to increased fees associated with land acquisition and title work of $0.8 million.

Operating Segment

Selling, general, and administrative expense for the operating segment was less than $0.1 million for the three months ended September 30, 2025 as compared to $2.8 million for the same period in 2024, a decrease of $2.8 million, or 99.1%, primarily due to a $2.8 million increase in the overhead charged to wells operated by us, which reduced selling, general, and administrative expense recognized in the operating segment.

Securities Segment

Selling, general, and administrative expense for the securities segment was $0.8 million for the three months ended September 30, 2025, as compared to $2.1 million for the same period in 2024, a decrease of $1.4 million, or 63.7%. The decrease was primarily due to decreased professional legal service fees of $1.7 million associated with our securities offerings.

Payroll and Payroll-Related Expense

Payroll and payroll-related expense was $6.4 million for the three months ended September 30, 2025, as compared to $4.9 million for the same period in 2024, an increase of $1.5 million, or 30.6%, primarily as a result of increased employee headcount and compensation. Employee headcount increased from 127 employees at September 30, 2024 to 182 employees at September 30, 2025.

Mineral and Non-operating Segment

Payroll and payroll-related expense for the mineral and non-operating segment was $2.3 million for the three months ended September 30, 2025, as compared to $2.2 million for the same period in 2024. The increase was not material to the mineral and non-operating segment for the periods presented.

Operating Segment

Payroll and payroll-related expense for the operating segment was $2.3 million for the three months ended September 30, 2025, as compared to $1.5 million for the same period in 2024, an increase of $0.7 million, or 48.5%, primarily due to the increased number of personnel engaged in our oil and gas operating activities.

Securities Segment

Payroll and payroll-related expense for the securities segment was $1.9 million for the three months ended September 30, 2025, as compared to $1.2 million for the same period in 2024, an increase of $0.6 million, or 49.1%, 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 three months ended September 30, 2025, as compared to $0.2 million for the same period in 2024, which was not material for the periods presented.

Impairment Expense

Impairment expense was $2.0 million for the three months ended September 30, 2025, as compared to $0.5 million for the same period in 2024, an increase of $1.5 million, or 276.3%, primarily as a result of lease expirations within the mineral and non-operating segment.

Other Expenses

Interest Expense, Net

Interest expense, net, was $38.8 million for the three months ended September 30, 2025, as compared to $26.2 million for the same period in 2024, an increase of $12.6 million, or 48.1%. The increase was primarily due to a $10.1 million increase in interest costs associated with the Fortress Credit Agreement for the three months ended September 30, 2025 and a $9.3 million increase in interest costs associated with sales of our unregistered debt securities and Registered Notes, which increased from $657.1 million outstanding at September 30, 2024 to $1,005.8 million outstanding at September 30, 2025, with no significant changes in interest rates between the periods. The increase was partially offset by a $6.9 million increase in capitalized interest primarily due to increased qualifying asset expenditures.

Gain on Derivatives

Gain on derivatives was $2.1 million for the three months ended September 30, 2025, as compared to $3.7 million for the same period in 2024, a decrease of $1.7 million, or 44.4%. The decrease was primarily due to a $1.8 million reduction in realized gain on derivatives, reflecting higher net payments made under our crude oil commodity derivative contracts during the three months ended September 30, 2025, as compared to the same period in 2024.

Loss on Debt Extinguishment

Loss on debt extinguishment was $1.3 million for the three months ended September 30, 2025, as compared to $0.6 million for the same period in 2024, an increase of $0.8 million, or 135.3%. The increase was primarily due to increased write-offs of debt issuance costs associated with the redemption of bonds issued pursuant to our unregistered debt offerings, of which $7.1 million of bonds were redeemed during the three months ended September 30, 2025, as compared to $6.0 million of bonds redeemed for the same period in 2024.

The following table summarizes the par value of bonds redeemed for the periods indicated:


	Three Months Ended September 30,				Change
	2025		2024		$			%
(in thousands)
Regulation D Bonds
August 2023 506(c) Bonds	$	4,270	$	4,077	$	193			4.7	%
July 2022 506(c) Bonds		100		—		100			NM
December 2022 506(c) Bonds		429		50		379			758.0	%

Total Regulation D Bonds		4,799		4,127		672			16.3	%

Regulation A Bonds		721		841		(120	)		(14.3	)%
Adamantium Bonds		1,563		1,000		563			56.3	%
Registered Notes		15		—		15			NM

Total	$	7,098	$	5,968	$	1,130			18.9	%

NM – not meaningful.

Nine Months Ended September 30, 2025 Compared to the Nine Months Ended September 30, 2024

The following table summarizes our consolidated results of operations for the periods indicated:


	Nine Months Ended September 30,						Change
(in thousands)	2025			2024			$			%
Revenues
Product sales	$	295,290		$	57,913		$	237,377			409.9	%
Mineral and royalty revenues		93,171			119,931			(26,760	)		(22.3	)%
Purchased crude oil sales		71,236			—			71,236			NM
Water services		8,508			1,632			6,876			421.3	%
Other revenue		397			74			323			436.5	%

Total revenues		468,602			179,550			289,052			161.0	%

Operating expenses
Cost of sales		105,172			40,334			64,838			160.8	%
Depreciation, depletion, amortization, and accretion		113,392			53,316			60,076			112.7	%
Purchased crude oil expenses		69,975			—			69,975			NM
Selling, general, and administrative		21,435			22,052			(617	)		(2.8	)%
Payroll and payroll-related		22,459			15,662			6,797			43.4	%
Advertising and marketing		1,531			350			1,181			337.4	%
Loss on sale of assets		—			564			(564	)		(100.0	)%
Impairment expense		2,509			528			1,981			375.2	%

Total operating expenses		336,473			132,806			203,667			153.4	%

Income from operations		132,129			46,744			85,385			182.7	%

Other income (expense)
Interest income		1,355			316			1,039			328.8	%
Interest expense, net		(111,690	)		(61,116	)		(50,574	)		(82.8	)%
Gain on derivatives		12,907			3,630			9,277			255.6	%
Loss on debt extinguishment		(1,916	)		(868	)		(1,048	)		(120.7	)%

Total other expenses		(99,344	)		(58,038	)		(41,306	)		(71.2	)%

Net income (loss)	$	32,785		$	(11,294	)	$	44,079			390.3	%

NM – not meaningful.

The following tables summarize our segment operating profit for the periods indicated:


	Nine Months Ended September 30, 2025
(in thousands)	Mineral and Non-operating			Operating			Securities			Eliminations			Total
Total revenues	$	93,336		$	375,098		$	100,732		$	(100,564	)	$	468,602
Total operating expenses		(71,045	)		(254,674	)		(10,983	)		229			(336,473	)

Segment operating profit	$	22,291		$	120,424		$	89,749		$	(100,335	)	$	132,129


	Nine Months Ended September 30, 2024
(in thousands)	Mineral and Non-operating			Operating			Securities			Eliminations			Total
Total revenues	$	120,015		$	59,545		$	51,529		$	(51,539	)	$	179,550
Total operating expenses		(78,142	)		(46,337	)		(8,411	)		84			(132,806	)

Segment operating profit	$	41,873		$	13,208		$	43,118		$	(51,455	)	$	46,744

The following table summarizes our production data and average realized prices for the periods indicated:


	Nine Months Ended September 30,				Change
	2025		2024		$			%
Production Data:
Crude oil (Bbls)		5,731,412		2,307,011		3,424,401			148.4	%
Natural gas (Mcf)		2,146,843		2,712,407		(565,564	)		(20.9	)%
NGL (Bbls)		388,083		332,732		55,351			16.6	%

Total (BOE)(6:1)		6,477,302		3,091,811		3,385,491			109.5	%
Average daily production (BOE/d) (6:1)		23,726		11,284		12,442			110.3	%
Average Realized Prices ^(a) :
Crude oil (Bbl)	$	65.36	$	71.18	$	(5.82	)		(8.2	)%
Natural gas (Mcf)	$	2.57	$	1.75	$	0.82			46.9	%
NGL (Bbl)	$	21.51	$	26.66	$	(5.15	)		(19.3	)%

(a)	Average realized prices are net of certain post-production costs that are deducted from our royalties.

Revenues

The following table shows the components of our revenue for the periods presented:

	$		$		$			$
	Nine Months Ended September 30,				Change
(in thousands)	2025		2024		$			%
Product sales
Crude oil	$	290,371	$	56,216	$	234,155			416.5	%
Natural gas		1,133		225		908			403.6	%
NGL		3,786		1,472		2,314			157.2	%

Total product sales		295,290		57,913		237,377			409.9	%

Mineral and royalty revenues
Crude oil		84,235		107,712		(23,477	)		(21.8	)%
Natural gas		4,374		4,634		(260	)		(5.6	)%
NGL		4,562		7,585		(3,023	)		(39.9	)%

Total mineral and royalty revenues		93,171		119,931		(26,760	)		(22.3	)%

Purchased crude oil sales		71,236		—		71,236			NM
Water services		8,508		1,632		6,876			421.3	%
Other revenue		397		74		323			436.5	%

Total revenues	$	468,602	$	179,550	$	289,052			161.0	%

NM – not meaningful.

Revenue was $468.6 million for the nine months ended September 30, 2025, as compared to $179.6 million for the same period in 2024, an increase of $289.1 million, or 161.0%. The increase was primarily attributable to a $237.4 million increase in product sales generated from our direct drilling, extraction, and related oil and gas operating activities, $71.2 million of purchased crude oil sales derived from the sale of crude oil purchased from working interest owners and royalty interest holders in wells operated by PhoenixOp that did not exist in the prior period, and a $6.9 million increase in revenue from water disposal services, partially offset by a $26.8 million decrease 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 $93.3 million for the nine months ended September 30, 2025, as compared to $120.0 million for the same period in 2024, a decrease of $26.7 million, or 22.2%. The decrease in segment revenue was primarily driven by decreased revenues from crude oil due to a 14.6% decrease in production volumes primarily due to the Company’s increased focus on acquiring assets with higher long-term anticipated rates of return and an 8.2% decrease in the average realized price from $71.18/Bbl to $65.36/Bbl for crude oil within the mineral and non-operating segment in 2025 as compared to the same period in 2024.

Operating Segment

Operating segment revenue was $375.1 million for the nine months ended September 30, 2025, as compared to $59.5 million for the same period in 2024, an increase of $315.6 million, or 529.9%. The increase was primarily attributable to a $237.4 million increase in product sales generated from our direct drilling, extraction, and related operating activities driven by additional wells placed into service, of which there were 78 producing wells placed into service as of September 30, 2025, as compared to 10 producing wells in service as of September 30, 2024, $71.2 million of purchased crude oil sales derived from the sale of crude oil purchased from working interest owners and royalty interest holders in wells operated by PhoenixOp beginning in April 2025, and a $6.9 million increase in water service revenue driven by higher disposal volumes, with 15.8 million barrels of saltwater disposed by Firebird Services during the nine months ended September 30, 2025, as compared to 3.4 million barrels during the same period in 2024.

Operating Expenses

Cost of Sales

The following table shows the components of our cost of sales for the periods presented:


	Nine Months Ended September 30,				Change
(in thousands)	2025		2024		$		%
Cost of sales
Production taxes	$	32,383	$	16,416	$	15,967		97.3	%
Lease operating expenses		40,810		17,278		23,532		136.2	%
Production costs		31,979		6,640		25,339		381.6	%

Total	$	105,172	$	40,334	$	64,838		160.8	%

Cost of sales was $105.2 million for the nine months ended September 30, 2025, as compared to $40.3 million for the same period in 2024, an increase of $64.8 million, or 160.8%. The increase was primarily driven by increased drilling, extraction and related oil and gas operating activities associated with wells operated by PhoenixOp, partially offset by a decrease in cost of sales due to lower lease operating expense and severance taxes resulting from decreased crude oil production volumes from our acquisitions of mineral and non-operated working interests during the nine months ended September 30, 2025 as compared to the same period in 2024.

Mineral and Non-operating Segment

Mineral and non-operating segment cost of sales was $18.2 million for the nine months ended September 30, 2025, as compared to $22.3 million for the same period in 2024, a decrease of $4.0 million, or 18.1%. The decrease in segment cost of sales was primarily attributable to lower lease operating expense and severance taxes resulting from a 14.6% decrease in crude oil production volumes from our acquisitions of mineral and non-operated working interests during the nine months ended September 30, 2025 as compared to the same period in 2024.

Operating Segment

Operating segment cost of sales was $87.2 million for the nine months ended September 30, 2025, as compared to $18.1 million for the same period in 2024, an increase of $69.0 million, or 380.4%. The increase in segment cost of sales was driven by increased production from PhoenixOp, which commenced operated production in the first quarter of 2024. As of September 30, 2025, PhoenixOp had placed into service an additional 68 producing wells since September 30, 2024, resulting in increased lease operating expenses, production and ad valorem taxes, and production costs during the nine months ended September 30, 2025 as compared to the same period in 2024.

Depreciation, Depletion, Amortization, and Accretion Expense

The following table shows the components of our depletion, depreciation, amortization, and accretion expense for the periods presented:


	Nine Months Ended September 30,				Change
(in thousands)	2025		2024		$			%
Depreciation, depletion, amortization, and accretion
Depletion	$	113,278	$	52,994	$	60,284			113.8	%
Depreciation		26		87		(61	)		(70.1	)%
Accretion on asset retirement obligations		88		235		(147	)		(62.6	)%

Total	$	113,392	$	53,316	$	60,076			112.7	%

Depreciation, depletion, amortization, and accretion expense was $113.4 million for the nine months ended September 30, 2025, as compared to $53.3 million for the same period in 2024, an increase of $60.1 million, or 112.7%, primarily due to a $71.0 million increase in depletion expense within the operating segment driven by increases in our depletable cost bases, partially offset by a $10.9 million decrease within the mineral and non-operating segment primarily due to a lower depletion rate driven by reduced realized production volumes.

Mineral and Non-operating Segment

Depletion for the mineral and non-operating segment was $25.6 million for the nine months ended September 30, 2025, as compared to $36.5 million for the same period in 2024, a decrease of $10.9 million, or 29.8%. On a per unit basis, depletion expense was $14.01 per Boe and $15.90 per Boe for the nine months ended September 30, 2025 and 2024, respectively, a decrease of $1.89 per Boe, driven by a lower depletion rate, primarily due to reduced realized production volumes.

Operating Segment

Depletion for the operating segment was $87.8 million for the nine months ended September 30, 2025, as compared to $16.8 million for the same period in 2024, an increase of $71.0 million, or 422.4%, primarily due to increases in the depletable cost bases, partially offset by a lower depletion rate during the nine months ended September 30, 2025 as compared to the same period in 2024. The lower depletion rate is primarily attributable to significant growth in proved reserves due to drilling activity by PhoenixOp.

Purchased Crude Oil Expense

Purchased crude oil expense was $70.0 million for the nine months ended September 30, 2025, with no comparable activity for the same period in 2024. This change is attributable to the commencement of marketing activities in April 2025 through Firebird Marketing within the operating segment. Purchased crude oil expense represents the purchase of crude oil from working interest owners and royalty interest holders in properties operated by PhoenixOp.

Selling, General, and Administrative Expense

Selling, general, and administrative expense was $21.4 million for the nine months ended September 30, 2025, as compared to $22.1 million for the same period in 2024, a decrease of $0.6 million, or 2.8%. The decrease was primarily due to a $6.5 million decrease in fees associated with professional legal services and a $3.6 million increase in the overhead charged to wells operated by us, which reduced selling, general, and administrative expense. The decrease was partially offset by a $3.5 million increase in fees associated with land acquisition and title work, a $3.1 million increase in allocated corporate overhead, a $2.2 million increase in financing-related costs, including administrative costs associated with our securities offerings, and a $0.6 million increase in contract labor costs.

Mineral and Non-operating Segment

Selling, general, and administrative expense for the mineral and non-operating segment was $14.5 million for nine months ended September 30, 2025, as compared to $10.1 million for the same period in 2024, an increase of $4.4 million, or 43.7%. The increase was primarily due to increased fees associated with land acquisition and title work of $3.5 million and increased allocated corporate overhead of $1.1 million.

Operating Segment

Selling, general, and administrative expense for the operating segment was $3.1 million for the nine months ended September 30, 2025 as compared to $7.1 million for the same period in 2024, a decrease of $3.9 million, or 55.8%, primarily due to a $3.6 million increase in the overhead charged to wells operated by us, which reduced selling, general, and administrative expense, and decreased allocated professional legal fees of $2.2 million, partially offset by increased allocated corporate overhead of $1.7 million.

Securities Segment

Selling, general, and administrative expense for the securities segment was $3.8 million for the nine months ended September 30, 2025, as compared to $4.9 million for the same period in 2024, a decrease of $1.1 million, or 21.9%, primarily due to decreased professional legal service fees of $2.1 million, partially offset by increased administrative costs associated with our securities offerings of $1.1 million.

Payroll and Payroll-Related Expense

Payroll and payroll-related expense was $22.5 million for the nine months ended September 30, 2025, as compared to $15.7 million for the same period in 2024, an increase of $6.8 million, or 43.4%, primarily as a result of increased employee headcount and compensation. Employee headcount increased from 127 employees at September 30, 2024 to 182 employees at September 30, 2025.

Mineral and Non-operating Segment

Payroll and payroll-related expense for the mineral and non-operating segment was $10.2 million for the nine months ended September 30, 2025, as compared to $8.1 million for the same period in 2024, an increase of $2.0 million, or 25.2%, due to increased activity in acquiring leasehold and mineral assets.

Operating Segment

Payroll and payroll-related expense for the operating segment was $6.7 million for the nine months ended September 30, 2025, as compared to $4.3 million for the same period in 2024, an increase of $2.4 million, or 55.7%, primarily due to the increased number of personnel engaged in our oil and gas operating activities.

Securities Segment

Payroll and payroll-related expense for the securities segment was $5.6 million for the nine months ended September 30, 2025, as compared to $3.2 million for the same period in 2024, an increase of $2.4 million, or 73.0%, 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 $1.5 million for the nine months ended September 30, 2025, as compared to $0.4 million for the same period in 2024, an increase of $1.2 million, or 337.4%, primarily due to increased marketing expenses related to our debt securities offerings and offering of Series A Preferred Shares.

Loss on Sale of Assets

Loss on sale of assets was $0.6 million for the nine months ended September 30, 2024, as 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 current-year period.

Impairment Expense

Impairment expense was $2.5 million for the nine months ended September 30, 2025 as compared to $0.5 million for the same period in 2024, an increase of $2.0 million, or 375.2%, primarily as a result of lease expirations within the mineral and non-operating segment.

Other Expenses

Interest Expense, Net

Interest expense, net, was $111.7 million for the nine months ended September 30, 2025, as compared to $61.1 million for the same period in 2024, an increase of $50.6 million, or 82.8%. The increase was primarily due to a $36.0 million increase in interest costs associated with sales of our unregistered debt securities and Registered Notes, which increased from $657.1 million outstanding at September 30, 2024 to $1,005.8 million outstanding at September 30, 2025, with no significant changes in interest rates between the periods, a $27.7 million increase in interest costs associated with the Fortress Credit Agreement, and a $2.6 million increase in interest costs associated with Securities debt issuance costs for the nine months ended September 30, 2025. The increase was partially offset by decreased interest costs of $4.4 million associated with merchant cash advances and a line of credit, which were previously outstanding as of September 30, 2024 but were repaid in full prior to 2025, $0.2 million of decreased interest costs associated with deferred closings associated with our mineral acquisitions, and a $11.1 million increase in capitalized interest primarily due to higher qualifying asset expenditures.

Gain on Derivatives

Gain on derivatives was $12.9 million for the nine months ended September 30, 2025, as compared to a gain on derivatives of $3.6 million for the same period in 2024, an increase of $9.3 million, or 255.6%, primarily as a result of favorable changes in the mark-to-market value of commodity derivatives entered into during the nine months ended September 30, 2025, with limited comparable activity for the same period in 2024.

Loss on Debt Extinguishment

Loss on debt extinguishment was $1.9 million for the nine months ended September 30, 2025, as compared to $0.9 million for the same period in 2024, an increase of $1.0 million, or 120.7%. The increase was primarily due to increased write-offs of debt issuance costs associated with the redemption of bonds issued pursuant to our unregistered debt offerings, of which $12.4 million of bonds were redeemed during the nine months ended September 30, 2025, as compared to $9.9 million of bonds redeemed for the same period in 2024.

The following table summarizes the par value of bonds redeemed for the periods indicated:


	Nine Months Ended September 30,				Change
	2025		2024		$			%
(in thousands)
Regulation D Bonds
August 2023 506(c) Bonds	$	7,391	$	5,417	$	1,974			36.4	%
July 2022 506(c) Bonds		500		—		500			NM
December 2022 506(c) Bonds		489		1,427		(938	)		(65.7	)%

Total Regulation D Bonds		8,380		6,844		1,536			22.4	%

Regulation A Bonds		1,575		1,800		(225	)		(12.5	)%
Adamantium Bonds		2,405		1,300		1,105			85.0	%
Registered Notes		15		—		15			NM

Total	$	12,375	$	9,944	$	2,431			24.4	%

NM – not meaningful.

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 condensed consolidated financial statements and the related notes included elsewhere in this Quarterly Report.

The following tables show a reconciliation of EBITDA to net income (loss), the most comparable GAAP measure, as presented in the condensed consolidated statements of operations for the periods presented:


	Three Months Ended September						Change
(in thousands)	2025			2024			$			%
Net income (loss)	$	8,488		$	(11,287	)	$	19,775			175.2	%
Interest income		(303	)		(261	)		(42	)		(16.1	)%
Interest expense, net		38,816			26,201			12,615			48.1	%
Depreciation, depletion, amortization, and accretion		45,550			15,541			30,009			193.1	%

EBITDA	$	92,551		$	30,194		$	62,357			206.5	%


	Nine Months Ended September 30,						Change
(in thousands)	2025			2024			$			%
Net income (loss)	$	32,785		$	(11,294	)	$	44,079			390.3	%
Interest income		(1,355	)		(316	)		(1,039	)		(328.8	)%
Interest expense, net		111,690			61,116			50,574			82.8	%
Depreciation, depletion, amortization, and accretion		113,392			53,316			60,076			112.7	%

EBITDA	$	256,512		$	102,822		$	153,690			149.5	%

EBITDA was $92.6 million for the three months ended September 30, 2025, as compared to $30.2 million for the same period in 2024, an increase of $62.4 million, or 206.5%. The increase in EBITDA was primarily driven by a $130.0 million increase in consolidated revenues, partially offset by a $65.2 million increase in operating expense (excluding depreciation, depletion, amortization, and accretion expense), primarily driven by increased purchased crude oil expenses and increased cost of sales, and a $1.7 million reduction in gain on derivatives, primarily due to a reduction in realized gain on derivatives, reflecting higher net payments made under our crude oil commodity derivative contracts during the three months ended September 30, 2025.

EBITDA was $256.5 million for the nine months ended September 30, 2025, as compared to $102.8 million for the same period in 2024, an increase of $153.7 million, or 149.5%. The increase in EBITDA was primarily driven by a $289.1 million increase in consolidated revenues and a $9.3 million increase in gain on derivatives, primarily as a result of favorable changes in the mark-to-market value of commodity derivatives entered into during the nine months ended September 30, 2025, with limited comparable activity for the same period in 2024, partially offset by a $143.6 million increase in operating expense (excluding depreciation, depletion, amortization, and accretion expense), primarily driven by increased cost of sales, increased purchased crude oil expenses, increased payroll and payroll-related expenses and increased impairment expense.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity to date have been cash flows from operations, borrowings under credit facilities, issuances of debt securities pursuant to registered debt offerings and unregistered debt offerings under Regulation D and A of the Securities Act, including the Registered Notes, Adamantium Securities and the Regulation D/Regulation A Bonds (the “Reg D/Reg A Bonds”), and issuances of preferred equity in September 2025. Future sources of liquidity may also include other credit facilities, continued issuances of debt or equity securities, and capital contributions. Our primary uses of cash are on the development and operation of PhoenixOp’s properties, 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, and general overhead and other corporate expenses. As we continue to engage in increased drilling and direct production activities through PhoenixOp, we expect the development and operation of PhoenixOp’s properties to become an increasingly significant use of our cash. As of September 30, 2025, we had cash and cash equivalents of $95.5 million and outstanding indebtedness of $1,405.8 million.

As of September 30, 2025, we had $145.3 million of debt coming due and $119.5 million of interest payable within the next 12 months. Over the next 12 months, we expect to drill between 90 to 110 gross and 62.0 to 76.0 net wells across our operated leasehold acreage in the Bakken/Williston Basin in North Dakota and Montana, and expect to participate in the drilling of approximately between 210 to 250 gross and 12.1 to 14.5 net wells across our non-operated leasehold. We estimate that these direct drilling operations and non-operated activity will require between $730.0 million and $830.0 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 anticipated at the beginning of the year that we would need to raise approximately $400 million in capital in 2025. We have raised $454.1 million in debt proceeds from the issuance of debt securities and increased borrowing under our credit facility and $47.9 million, net of offering costs, from the Series A Preferred Shares offering during the nine months ended September 30, 2025. 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 recent months, oil prices have decreased, going from $71.20 per barrel as of April 1, 2025 to $60.98 per barrel as of October 31, 2025, 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 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 our 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.

Preferred Equity

In September 2025, we completed our offering of the Series A Cumulative Redeemable Preferred Shares (the “Series A Preferred Shares”) pursuant to Regulation A promulgated under the Securities Act, which shares were listed on the NYSE American under the ticker symbol PHXE.P and commenced trading on September 30, 2025. We sold an aggregate of 2,704,023 Series A Preferred Shares at closing, which represented $67.6 million in initial liquidation preference at a public offering price of $20.00 per share for gross proceeds of $54.1 million. Offering costs of $6.2 million were recorded as a reduction of the gross proceeds.

Holders of the Series A Preferred Shares generally have no voting rights. However, if we do not pay distributions on the Series A Preferred Shares for six or more quarterly distribution periods (whether or not consecutive), the holders of the Series A Preferred Shares will be entitled to vote for the election of two additional directors to serve on the Board of Directors until we pay, or declare and set aside funds for the payment of all distributions that we owe on the Series A Preferred Shares.

The Series A Preferred Shares rank senior to all classes of equity securities issued by us (including common equity) and are junior to all of our existing and future indebtedness. Holders of the Series A Preferred Shares are entitled to receive cumulative cash distributions based on the initial liquidation preference of $25.00 per share, accruing from the initial issuance date and, when, as and if declared by our Board of Directors, payable quarterly in arrears on January 15, April 15, July 15, and October 15 of each year, beginning on October 15, 2025. The annual distribution rate is 10.0% for the first three year-period, 10.5% in the fourth year, and 11.0% in the fifth year and thereon. As of September 30, 2025, $0.3 million of Series A Preferred distributions equal to $0.11111 per share had been declared and scheduled to be paid on October 15, 2025 to the holders on record as of October 1, 2025. On October 15, 2025, we paid cash distributions totaling $0.3 million to holders of our Series A Preferred Shares, pursuant to distributions declared by our Board of Directors in September 2025.

In the event of our voluntary or involuntary liquidation, dissolution, or winding up, the holders of the Series A Preferred Shares will generally have the right to receive the initial liquidation preference of $25.00 per Series A Preferred Share, plus any accumulated and unpaid distributions. The Series A Preferred Shares are not redeemable at the option of the holders. The Series A Preferred Shares, are, however, redeemable at our option, in whole or in part, at a cash redemption price of $27.50 per share, plus any accumulated and unpaid distributions. The Series A Preferred Shares are not convertible or exchangeable for any of our securities or property.

Cash Flows

The following table summarizes our cash flows for the periods indicated:


	Nine Months Ended September 30,						Change
(in thousands)	2025			2024			$			%
Net cash provided by (used in):
Operating activities	$	190,617		$	40,218		$	150,399			374.0	%
Investing activities		(606,040	)		(274,150	)		(331,890	)		(121.1	)%
Financing activities		390,061			253,031			137,030			54.2	%

Net increase (decrease) in cash and cash equivalents	$	(25,362	)	$	19,099		$	(44,461	)		(232.8	)%

Operating Activities

Net cash provided by operating activities for the nine months ended September 30, 2025 was $190.6 million, as compared to $40.2 million for the same period in 2024, an increase of $150.4 million in net cash provided by operating activities. The increase was primarily due to a $102.7 million increase in net income, adjusted for non-cash charges of $58.6 million, and net favorable fluctuations of $47.7 million from changes in operating assets and liabilities. The $47.7 million cash inflow from changes in operating assets and liabilities was primarily due to increased accounts payable, accrued and other liabilities and noncurrent accrued interest totaling $83.0 million, partially offset by increased accounts receivable of $32.1 million and decreased escrow account liability of $12.4 million primarily due to the timing of cash receipts and payments during the nine months ended September 30, 2025 as compared to the same period in 2024.

Investing Activities

Net cash used in investing activities for the nine months ended September 30, 2025 was $606.0 million, as compared to $274.2 million for the same period in 2024, an increase of $331.9 million in net cash used in investing activities. The increase was primarily driven by a $324.3 million increase in additions to oil and gas properties, primarily due to increased drilling and completion activities in our operating segment during the nine months ended September 30, 2025, as compared to the same period in 2024, and $6.2 million of proceeds received in connection with the disposition of mineral interests during the nine months ended September 30, 2024 that did not recur in the current year period.

Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2025 was $390.1 million, as compared to $253.0 million for the same period in 2024, an increase of $137.0 million in net cash provided by financing activities. The increase was primarily driven by increased proceeds from issuances of debt, net of debt discount, of $69.3 million, proceeds from the preferred equity offering that closed in September 2025 totaling $47.9 million, net of offering costs, a $29.7 million decrease in repayments of debt primarily due to the repayment of merchant cash advances and a line of credit in 2024 that were not applicable in 2025, and a $3.6 million decrease in payments of deferred closings associated with mineral interest acquisitions, partially offset by a $17.9 million increase in payments of debt issuance costs and a $0.3 million decrease in member’s contributions.

Indebtedness

Set forth below is a chart of our outstanding third-party indebtedness as of September 30, 2025 (dollars in thousands):

Indebtedness

Offering
Commencement

Principal
Amount
Outstanding

Term

Earliest
Maturity

Latest
Maturity

Interest Rate

Secured

Fortress Credit Agreement ⁽¹⁾

N/A

400,000

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

59,679

3 years

10/10/2025

12/10/2027

9.0

2020 506(c) Bonds ⁽⁴⁾

10/22/2020

748

4 years

—

12/15/2025

13.0

July 2022 506(c) Bonds ⁽⁴⁾

7/20/2022

8,522

5 years

7/31/2027

12/31/2027

11.0

December 2022 506(c) Bonds ⁽⁵⁾ :

Series B

12/22/2022

14,617

3 years

12/10/2025

10/10/2026

10.0

Series C

12/22/2022

9,060

5 years

12/10/2027

9/10/2028

11.0

Series D

12/22/2022

37,582

7 years

12/10/2029

10/10/2030

12.0

August 2023 506(c) Bonds ⁽⁵⁾ :

Series U, AA, and FF

8/29/2023

94,608

1 year

10/10/2025

9/10/2026

9.0% - 10.0

Series V, BB, and GG

8/29/2023

97,131

3 years

8/10/2026

9/10/2028

10.0% - 11.0

Series W, CC, and HH

8/29/2023

64,735

5 years

8/10/2028

9/10/2030

11.0% - 12.0

Series X, DD, and II

8/29/2023

78,972

7 years

9/10/2030

9/10/2032

12.0% - 13.0

Series Y

8/29/2023

3,887

9 years

9/10/2032

9/10/2033

12.5

Series Z, EE, and JJ

8/29/2023

273,779

11 years

9/10/2034

9/10/2036

13.0% - 14.0

Total Regulation D/Regulation A Bonds

743,320

Exchange Notes ⁽³⁾ :

Three-Year Exchange Notes

5/15/2025

3,081

3 years

5/10/2028

9/10/2028

9.0

Five-Year Exchange Notes

5/15/2025

6,461

5 years

5/10/2030

9/10/2030

10.0

Seven-Year Exchange Notes

5/15/2025

3,085

7 years

5/10/2032

9/10/2032

11.0

Eleven-Year Exchange Notes

5/15/2025

13,285

11 years

5/10/2036

9/10/2036

12.0

Total Exchange Notes

25,912

Registered Notes ⁽⁶⁾ :

Three-Year Registered Notes

5/14/2025

5,689

3 years

5/10/2028

9/10/2028

9.0

Five-Year Registered Notes

5/14/2025

3,128

5 years

5/10/2030

9/10/2030

10.0

Seven-Year Registered Notes

5/14/2025

1,804

7 years

5/10/2032

9/10/2032

11.0

Eleven-Year Registered Notes

5/14/2025

7,794

11 years

5/10/2036

9/10/2036

12.0

Total Registered Notes

18,415

Adamantium Bonds ⁽⁷⁾

9/29/2023

211,155

5-11 years

1/10/2029

9/10/2036

13.0% - 16.0

Total Unsecured Debt

998,802

Total Debt

1,405,802

(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, a $50.0 million term loan facility, of which $25.0 million was borrowed on April 16, 2025 and $25.0 million was borrowed on May 9, 2025, and a $100.0 million term loan facility, borrowed in full on August 1, 2025. Amount displayed does not include amounts drawn after September 30, 2025. On October 27, 2025, the Fortress Credit Agreement was amended to provide for an additional $350.0 million term loan facility available on a discretionary basis, $50.0 million of which was borrowed on October 27, 2025. The Fortress Credit Agreement also provides for an $8.5 million tranche of loans and a $6.5 million tranche of loans that represent 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 the Registered Notes, and structurally senior to the Reg D/Reg A Bonds and the Registered Notes to the extent of the value of Adamantium’s assets, including the collateral securing the Adamantium Loan Agreement.

(3)	The Reg A Bonds and the Exchange Notes are pari passu obligations with the Senior Reg D Bonds, and are contractually senior to obligations under the Subordinated Reg D Bonds and the Registered Notes.

(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, and are contractually senior to obligations under the Subordinated Reg D Bonds and the Registered Notes.

(5)	The Subordinated Reg D Bonds are contractually subordinated to obligations under the Fortress Credit Agreement, the Reg A Bonds, the Senior Reg D Bonds, and the Registered Notes.

(6)	The Registered Notes are contractually subordinated to amounts under the Fortress Credit Agreement, the Adamantium Bonds, the Adamantium Secured Note, the Reg A Bonds and the Senior Reg D Bonds, and are contractually senior to the Subordinated Reg D Bonds.

(7)

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 to the extent of the value of Adamantium’s assets, including the collateral securing the Adamantium Loan Agreement, and are contractually senior to the obligations under the Registered Notes.

ANB Credit Agreement

We were borrowers under that certain Commercial Credit Agreement (the “ANB Credit Agreement”), which we 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

We entered into the Fortress Credit Agreement with Fortress Credit Corp. (“Fortress”) on August 12, 2024, which provides for a $100.0 million term loan facility (the “Fortress Term Loan”) that was borrowed in full on August 12, 2024, and a $35.0 million delayed draw term loan facility that 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 borrowed on May 9, 2025. Then, on August 1, 2025, the Fortress Credit Agreement was amended further to provide for a new tranche of term loans (the “Fortress Tranche E Loan”) in an aggregate principal amount of $100.0 million that was borrowed in full on August 1, 2025. On October 29. 2025, the Fortress Credit Agreement was further amended to, among other things, provide for a new tranche of term loans available on a discretionary basis (the “Fortress Tranche G Loans”, and, together with the Fortress Tranche A Loans, the Fortress Tranche C Loan, the Fortress Tranche D Loans, and the Fortress Tranche E Loans, the “Fortress Loans”) in an aggregate principal amount of $350.0 million, with $50.0 million aggregate principal amount borrowed on October 29, 2025. The Fortress Credit Agreement also provides for (a) a rebate of approximately $8.5 million in original issue discount (the “Fortress Tranche B Loan”) and (b) a rebate of approximately $6.5 million in original issue discount (the “Fortress Tranche F Loan” and, together with the Fortress Tranche B Loan, the “Fortress Rebate Loans”), each of which are payable by setoff against final payment in full of the Fortress Credit Agreement, if (a) all outstanding principal and accrued interest on the loans under the Fortress Credit Agreement are paid in full in cash on or before December 18, 2027, and (b) no event of default resulting from the failure to pay principal or interest when due under the terms and conditions of the Fortress Credit Agreement has occurred prior to such date, subject to certain other conditions.

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. Furthermore, pursuant to that certain Assignment of Loans and Liens, dated as of August 12, 2024, among Phoenix Energy (formerly Phoenix Capital Group Holdings, LLC), 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 us 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 Loans are subject to a 3.00% original issue discount (“OID”). The $8.5 million and $6.5 million OID issued in connection with the Fortress Tranche B Loan and Fortress Tranche F Loan are to be rebated if certain conditions are met, and therefore represent contingent principal obligations that are only due and payable (together with accrued interest) upon the occurrence of those conditions, including payment defaults under the Fortress Credit Agreement or a bankruptcy filing. We expect the OIDs associated with the Fortress Rebate Loans will be rebated in full.

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 0.1% plus 7.0%. Interest on the Fortress Loans is payable quarterly in arrears. The outstanding principal amount of the Fortress Loans (including, if applicable, the Fortress Tranche B Loan and the Fortress Tranche F Loan) must be repaid as follows: (i) on August 31, 2027, $200.0 million of the outstanding principal amount of the Fortress Loans less the aggregate amount of all voluntary prepayments and mandatory prepayments made as of August 31, 2027; 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 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. The Fortress Credit Agreement also places certain limits on our ability to incur additional indebtedness, including the issuance of unsecured notes or bonds and accounts receivable factoring arrangements, as well as limits on our ability to redeem the Preferred Shares. Under the terms of the Fortress Credit Agreement, we may only expend an aggregate amount of $5,000,000 to redeem Preferred Shares in any fiscal quarter, which quarterly limit may be reduced by the amount of certain cash payments made during such quarter to the extent related to certain debt refinancing transactions. On October 27, 2025, subsequent to the balance sheet date, we executed an amendment of the Fortress Credit Agreement, which provided a waiver of default on its current ratio as of September 30, 2025.

The Fortress Credit Agreement contains customary events of default, including, but not limited to, nonpayment of the Fortress Loans 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. We 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 our wholly owned financing subsidiary for the purpose of undertaking financing efforts under Regulation D and subsequently loaning amounts to us and/or our subsidiaries, as needed. Adamantium offers high net worth individuals 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, we, as borrower, entered into the Adamantium Loan Agreement with Adamantium, as lender. On October 30, 2023, Phoenix Energy (formerly Phoenix Capital Group Holdings, LLC), 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 $400.0 million in aggregate principal amount of Adamantium Bonds to fund advances to us 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 September 30, 2025, $211.2 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.

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 10.0% 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 100.0% 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.

At the option of Adamantium, an advance may be made on either (i) a current basis, whereby we make 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 we 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, we 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 Registered 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 our wholly owned financing subsidiary 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.

Registered Notes

In October 2024, we filed a registration statement on Form S-1 (the “Registration Statement”) with the SEC which was declared effective in May 2025 with respect to the continuous offering of up to $750.0 million aggregate principal amount of our senior subordinated notes (the “Registered Notes”) with maturity dates ranging from three to eleven years from the issue date and interest rates ranging from 9.0% to 12.0% per annum.

The Registered Notes are contractually senior to the Subordinated Regulation D Bonds and contractually subordinated to the Fortress Credit Agreement, the Adamantium Debt, and the Senior Regulation D/Regulation A Bonds. The Registered Notes contain customary events of default and may be redeemed at our option at any time without premium or penalty. The holders of Registered Notes also have a right to request redemption of their notes 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. As of September 30, 2025, we have issued $18.4 million of Registered Notes.

Regulation D/Regulation A Bonds and Exchange Notes

In May 2025, we approved an increase to the maximum offering amount of the August 2023 506(c) Bonds from $750.0 million to $1,500.0 million. The August 2023 506(c) Bonds are unsecured bonds offered and sold 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.

In May 2025, we entered into an indenture with UMB Bank, N.A., as trustee, pursuant to which we may, from time to time, issue debt securities to holders of our Regulation A Bonds in exchange for their Regulation A Bonds, in offerings exempt from registration under Section 3(a)(9) and/or 4(a)(2) of the Securities Act (the “Exchange Notes”). The Exchange Notes have maturities of three, five, seven, or eleven years and interest rates ranging from 9.0% to 12.0% per annum. As of September 30, 2025, $25.9 million aggregate principal amount of the Regulation A Bonds were exchanged for Exchange Notes.

As of September 30, 2025, we had $743.3 million aggregate principal amount outstanding of unsecured bonds issued pursuant to Regulation D or Regulation A, consisting of:

(a) $9.3 million aggregate principal amount outstanding of Senior Regulation D Bonds, which rank pari passu with the Regulation A Bonds, are contractually subordinated to amounts under the Fortress Credit Agreement, are contractually senior to obligations under the Subordinated Regulation D Bonds and the Registered Notes, comprising:

(i) $0.8 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 a maturity date of four years from the issue date and an interest rate of 13.0% per annum; and

(ii) $8.5 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) $674.4 million aggregate principal amount outstanding of Subordinated Regulation D Bonds, which are contractually subordinated to obligations under the Fortress Credit Agreement, the Regulation A Bonds, the Senior Regulation D Bonds, and the Registered Notes, comprising:

(i) $61.3 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 three to seven years from the issue date and interest rates ranging from 10.0% to 12.0% per annum; and

(ii) $613.1 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) $59.7 million aggregate principal amount outstanding of Regulation 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 Regulation A Bonds rank pari passu with the Senior Regulation D Bonds, are contractually senior to obligations under the Subordinated Regulation D Bonds, and will be contractually senior to obligations under the Registered Notes.

The Regulation D/Regulation A Bonds contain customary events of default. The Regulation D/Regulation A Bonds may be redeemed at the option of the Issuer at any time without premium or penalty. We will also be obligated to offer to holders of Regulation A Bonds the right to have their Regulation A Bonds repurchased upon a change of control (as described in the indenture governing the Regulation A Bonds). The holders of Regulation D/Regulation 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 10.0% of the then-outstanding principal amount of the applicable series in any given calendar year.

Critical Accounting Estimates

Our critical accounting policies are described under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Use of Estimates” in the prospectus for our offering of Registered Notes, dated as of May 14, 2025, and filed with the SEC pursuant to Rule 424(b)(4) on May 14, 2025 and the notes to the unaudited condensed consolidated financial statements appearing elsewhere in this Quarterly Report. During the nine months ended September 30, 2025, there have been changes in our critical accounting policies from those discussed in such prospectus.

Revenue from contracts with customers

We recognize our revenues following Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers , (“ASC 606”). Our revenues are predominantly derived from contracts for the sale of crude oil, natural gas and NGLs. For crude oil, natural gas and NGLs produced by PhoenixOp, each delivery order is treated as a separate performance obligation that is satisfied at the point in time control of the product transfers to the customer. 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.

In circumstances where we are the non-operator or mineral rights owner, we derive revenue from our interests in the sale of oil and natural gas production and do not consider ourself to have control of the product, resulting in the recognition of revenues net of post-production expenses. 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. 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 our revenue may represent accrued revenue based on estimated net sales volumes and estimated selling prices of the commodities.

Effective April 2025, we began conducting marketing activities through our newly established subsidiary, Firebird Marketing. These activities include the purchase of crude oil from working interest owners and royalty interest holders in properties operated by PhoenixOp, and the subsequent sale of the crude oil to customers. The revenues and expenses from these sales and purchases are recognized on a gross basis as we act as a principal in these transactions by assuming control of the purchased crude oil before it is transferred to the customer.

We, through Firebird Services, provide water disposal services to PhoenixOp and third parties with respect to oil and gas production from wells in which we our 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 we will collect the consideration we are entitled to in exchange for the services transferred to the customer.

Impairment of long-lived assets

We follow the provisions of 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.

Preferred equity

We account for preferred equity in accordance with ASC 480, Distinguishing Liabilities from Equity (“ASC 480”). The Series A Preferred Shares are not subject to any mandatory redemption and, accordingly, have been classified as permanent equity on our condensed consolidated balance sheets. Distributions are accrued as contractually obligated and are paid quarterly in arrears, when, as and if declared by our Board of Directors. The discount associated with the increasing-rate distributions is amortized using the effective interest method over the period preceding the commencement of the perpetual distribution rate. The accretion is recorded as an imputed distribution, recognized through retained earnings, with a corresponding increase to the carrying amount of the preferred equity.

Recent Accounting Pronouncements

See “ Part I. Item 1. Financial Statements— Note 2 – Significant Accounting Policies ” of the notes to the condensed consolidated financial statements included elsewhere in this Quarterly Report, for recently adopted accounting pronouncements and recent accounting pronouncements not yet adopted, if any.

Item 3. 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 and 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 September 30, 2025, over the next three years, we had nearly 9.0 million Bbl hedged at a weighted average strike price of $61.54 per Bbl, which would generate revenues of approximately $556.2 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 net cash provided by operating activities. Future transactions may include additional price swaps, whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, or collars, whereby we would 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 reduce the impact of commodity price volatility on our net cash provided by operating activities.

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.

The fair market value of our commodity derivative contracts was a net asset of $4.2 million as of September 30, 2025. Based upon our open commodity derivative positions at September 30, 2025, a hypothetical 10.0% increase in the NYMEX WTI price would decrease our net derivative asset position by $60.7 million, while a 10.0% decrease in the NYMEX WTI price would increase our net derivative asset position by $59.9 million.

A $1.00 per Bbl change in our realized oil price would have resulted in a $5.7 million and a $3.2 million change in our oil revenues for the nine months ended September 30, 2025 and 2024, respectively. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.2 million and $0.3 million change in our natural gas revenues for the nine months ended September 30, 2025 and 2024, respectively. A $1.00 per Bbl change in NGL prices would have resulted in a $0.4 million and $0.5 million change in our NGL revenues for the nine months ended September 30, 2025 and 2024, respectively. Revenues from oil sales contributed 95.1% and 89.8%, revenues from natural gas sales contributed 1.2% and 3.9%, and revenues from NGL sales contributed 1.8% and 6.3% of our consolidated revenues for the nine months ended September 30, 2025 and 2024, respectively.

Interest Rate Ris k

Our primary exposure to interest rate risk results from outstanding borrowings under our credit facilities, which bear interest at a floating rate. The average interest rate incurred when such facility was outstanding on our borrowings under the Fortress Credit Agreement during the nine months ended September 30, 2025 was 11.4%. 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 $4.0 million. See “ Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement .”

Counterparty and Customer Credit Risk

We often maintain cash balances in excess of the federally insured limits, which may subject us to concentrations of credit risk. We manage this risk by maintaining deposits with a financial institution that we believe to be creditworthy and by monitoring their financial condition on an ongoing basis.

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 product sales from the delivery of commodities that we extract and deliver to purchasers and the production activities of our operators. For the three months ended September 30, 2025, three purchasers of our commodities and thirteen third-party E&P operators made up 49.0% and 14.0% of our consolidated revenue, respectively, as compared to one purchaser of our commodities and four third-party E&P operators that made up 38.0% and 60.0% of our consolidated revenue, respectively, for the three months ended September 30, 2024. For the nine months ended September 30, 2025, three purchasers of our commodities and twelve third-party E&P operators made up 54.0% and 16.0% of our consolidated revenue, respectively, as compared to one purchaser of our commodities and six third-party E&P operators that made up 30.0% and 33.0% of our consolidated revenue, respectively, for the nine months ended September 30, 2024.

Similarly, as of September 30, 2025, we had concentrations in accounts receivable of 19.0%, 12.0% and 11.0% with three purchasers of our commodities and 12.0% with one third-party E&P operator, as compared to 17.0%, 15.0%, and 13.0% with three third-party E&P operators as of December 31, 2024. Although we are exposed to a concentration of credit risk due to our reliance on operators and purchasers of our commodities, we do not believe the loss of any single counterparty would materially impact our operating results as crude oil and natural gas are fungible products with well-established markets and numerous participants. 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 or purchasers 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.

Item 4. Controls and Procedures

Limitations on Effectiveness of Controls and Procedures

In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, evaluated, as of the end of the period covered by this Quarterly Report, the effectiveness of our disclosure controls and procedures (as that term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of September 30, 2025 as a result of the material weaknesses described below.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or detected on a timely basis. In connection with the audits of our consolidated financial statements as of and for the year ended December 31, 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 and absence of a board of directors or an audit committee. As a result of these material weaknesses, we have relied, in part, on the assistance of outside advisors with expertise in these matters to assist us in the preparation of our condensed consolidated financial statements and in our compliance with SEC reporting obligations and expect to continue to do so while we remediate these material weaknesses.

Management’s Remediation Efforts

Our management is committed to implementing changes to our internal control over financial reporting to ensure that the deficiencies that contributed to the material weaknesses are remediated. To that end, we are now in the process of enacting measures designed to improve our internal control over financial reporting and remediate the deficiencies that led to the material weaknesses. These measures include hiring additional accounting personnel to ensure the effectiveness of our controls and enforcement of proper segregation of duties, engaging with external consulting firms to assist with technical accounting matters and to improve the design and operating effectiveness of our internal control over financial reporting, and formalizing and documenting preparation and review procedures within significant accounts and cycles.

Changes in Internal Control over Financial Reporting

We are taking actions to remediate the material weaknesses relating to our internal control over financial reporting, as described above. Except as discussed above, there were no changes in our internal control over financial reporting (as that term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) during the quarter ended September 30, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We have been, are and/or may in the future 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 matters, disputes, or claims we are involved in, if decided adversely, will have a material adverse effect on our financial condition, cash flows, or results of operations. See “ Part I. Item 1. Financial Statements—Note 13 – Commitments and Contingencies ” of the notes to the condensed consolidated financial statements included elsewhere in this Quarterly Report.

Item 1A. Risk Factors

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:

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declines in oil and natural gas prices;

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acquisition of commercially viable mineral deposits offered for sale by other companies;

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access to capital for financing and operational purposes;

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hiring and retention of personnel to successfully operate drilling and extraction activities, and qualified third-party operators to assist in production activities;

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purchasing, leasing, hiring, chartering, or other procuring of equipment by us and our third-party operators; and

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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:

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declines in oil and natural gas prices;

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infrastructure limitations, such as gas gathering and processing constraints;

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the high cost, shortages, or delays in procurement of equipment, materials, and/or services;

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unexpected operational events, adverse weather conditions and natural disasters, facility or equipment malfunctions, and equipment failures or accidents;

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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;

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lost or damaged oilfield development and service tools;

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compliance with environmental, health, safety, and other governmental requirements;

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increases in severance taxes;

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regulations, restrictions, moratoria, and bans on hydraulic fracturing;

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unusual or unexpected geological formations, and pressure or irregularities in formations;

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loss of drilling fluid circulation;

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environmental hazards, such as oil, natural gas, or well fluids spills or releases, pipeline or tank ruptures, and discharges of toxic gases;

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fires, blowouts, craterings, and explosions;

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uncontrollable flows of oil, natural gas, or well fluids;

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pipeline capacity curtailments; and

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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:

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failing to place a well bore in the desired target producing zone;

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not staying in the desired drilling zone while drilling horizontally through the formation;

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failing to run casing the entire length of the well bore; and

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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:

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not being able to fracture stimulate the planned number of stages;

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failing to run tools the entire length of the well bore during completion operations;

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not successfully cleaning out the well bore after completion of the final fracture stimulation stage;

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increased seismicity in areas near our completion activities;

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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

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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:

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abnormal pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment or qualified personnel;

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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;

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mechanical difficulties, fires, explosions, equipment failures, or accidents, including ruptures of pipelines or storage facilities, or train derailments;

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restrictions on the use of underground injection wells for disposing of wastewater from oil and gas activities;

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political events, public protests, civil disturbances, terrorist acts, or cyber-attacks;

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decreases in, or extended periods of low, crude oil and natural gas prices;

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title problems;

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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;

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adverse climatic conditions and natural disasters;

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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;

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limitations in infrastructure, including transportation, processing, refining, and exportation capacity, or markets for crude oil and natural gas; and

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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.

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. During the period from January 1, 2021 through September 30, 2025, prices for crude oil reached a high of $123.64 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. 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 and distribution payments on the Preferred Shares.

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:

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changes in global supply and demand for oil and natural gas;

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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;

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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;

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the level of global and domestic oil and natural gas inventories;

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the level of consumer product demand;

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inclement or hazardous weather conditions and natural disasters;

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the availability of storage for hydrocarbons and technological advances affecting energy consumption and energy supply;

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speculative trading in commodity markets, including expectations about future commodity prices;

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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;

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domestic, local, and foreign governmental regulation and taxes;

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fuel and energy conservation measures and technological advances affecting energy consumption;

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armed conflict, political instability, or civil unrest in oil and gas producing regions, including instability and conflicts in the Middle East, including conflicts involving Israel and Iran and the conflict between Russia and Ukraine, and the related potential effects on laws and regulations or the imposition of economic or trade sanctions;

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changes in regulatory and trade policy, such as tariffs, as well as the potential for general market volatility and political uncertainty;

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the occurrence or threat of epidemic or pandemic diseases, or any government response to such occurrence or threat; and

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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, which are significantly higher than recent lows of $58.29 per barrel of for crude oil, as of October 16, 2025 and $2.65 per MMBtu for natural gas, as of October 17, 2025. Although prices have recovered since then, there can no be assurance that prices will not experience another significant decrease. 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 and distribution payments on the Preferred Shares. 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.

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. Future sources of liquidity may also include other credit facilities, additional capital contributions, asset-backed securitizations, and continued issuances of debt or equity securities. For example, as part of our general financing and operational strategy, we may in the future undertake securitizations of certain assets or interests in assets through special purpose vehicles.

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 or equity 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 or other 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 third-party 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.

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 oil and gas we produce, our profits may decline, and we may not be able to purchase other assets, or expand our operations.

A limited number of purchasers and operators currently generate a significant portion of our revenue and/or accounts receivable, and we may not have contracts or agreements directly with all such operators.

A significant portion of our consolidated revenue is generated from product sales for the delivery of commodities that we extract and deliver to purchasers, and we currently deliver to a limited number of purchasers. For example, for the nine months ended September 30, 2025, three purchasers of our commodities made up 54.0% of our consolidated revenue, as compared to one purchaser of our commodities that made up 30.0% of our consolidated revenue for the nine months ended September 30, 2024 and one purchaser of our commodities that made up 21.0% of our consolidated revenue for the year ended December 31, 2024. While we do not believe that the loss of any one purchaser would have a material impact on our revenue, to the extent there is a delay in transferring our commodity sales or entering into purchase contracts with another, new or replacement purchaser, there could be a delay in product sales or an adverse impact on our revenue during the respective period. 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 nine months ended September 30, 2025, twelve third-party E&P operators made up 16.0% of our consolidated revenue, as compared to six third-party E&P operators that made up 33.0% of our consolidated revenue for the nine months ended September 30, 2024. For the year ended December 31, 2024, one third-party E&P operator made up 21.0% of our consolidated revenue, as compared to one third-party E&P operator that made up 11.0% of our consolidated revenue for the year ended December 31, 2023, and four third-party E&P operators that made up 16.0%, 16.0%, 15.0%, and 14.0% of our consolidated revenue for the year ended December 31, 2022. Similarly, as of September 30, 2025, we had concentrations in accounts receivable of 19.0%, 12.0% and 11.0% with three purchasers of our commodities and 12.0% with one third-party E&P operator, as compared to 17.0%, 15.0%, and 13.0% with three third-party E&P operators as of December 31, 2024, 26.0% and 14.0% with two third-party E&P operators as of December 31, 2023, and 34.0% and 10.0% with two third-party E&P operators as of December 31, 2022. A significant portion of 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. 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 third-party 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 third-party 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.

Furthermore, our E&P operators, including PhoenixOp, 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 third-party 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 third-party 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.

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.

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 September 30, 2025, approximately 55.8% of our total estimated proved reserves and 100% of our total estimated probable reserves were undeveloped. Furthermore, as of September 30, 2025, we had 155.2 million Boe in total estimated probable undeveloped reserves, which is approximately 1.6 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 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 third-party E&P operators on those leases declare bankruptcy.

We may experience delays in receiving royalty payments from our third-party E&P operators, including as a result of delayed division orders received by our third-party E&P operators. A failure on the part of our third-party 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 third-party 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 third-party 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 third-party E&P operators historically have undergone restructurings under the Bankruptcy Code and any future restructurings of our third-party E&P operators may impact their future operations and ability to make royalty payments to us. If the third-party 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 third-party 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:

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actual prices we receive for natural gas and oil;

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actual cost of development and production expenditures;

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the amount and timing of actual production;

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transportation and processing; and

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changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of our 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 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 Report, 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:

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recoverable reserves;

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future oil and natural gas prices and their appropriate differentials;

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availability and cost of transportation of production to markets;

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availability and cost of drilling equipment and of skilled personnel for our third-party operators;

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development and operating costs of PhoenixOp and our third-party E&P operators, including potential environmental and other liabilities; and

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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.

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 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 third-party 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 third-party 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 third-party E&P operators may have reached different conclusions about the potential drilling locations on our properties, and our third-party 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 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 third-party 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:

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the impact of regional supply and demand factors;

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delays or interruptions of production from wells in such areas caused by governmental regulation, including changes to field wide rules;

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processing or transportation capacity constraints;

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market limitations;

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availability of equipment and personnel;

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water shortages or other drought-related conditions; or

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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 third-party 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 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 third-party 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 third-party 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 third-party 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 third-party E&P operator may suspend payment of the related royalty. If a third-party E&P operator of our properties is not satisfied with the documentation we provide to validate our ownership, such third-party 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 a third-party 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.

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 operations of our E&P operators 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:

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production is less than expected;

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the counterparty to the derivative contract defaults on its contract obligation; or

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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:

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laws and regulations governing mineral concession acquisition, prospecting, development, mining, production, transportation, marketing, and sales;

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laws and regulations related to exports, taxes, and fees;

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labor standards and regulations related to occupational health and mine safety;

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environmental laws and regulations related to air emissions, waste disposal, remediation of contaminated sites, water and wastewater discharges, management and exposure to hazardous substances, land use, and protection of natural resources; and

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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 our operations, including the mineral industry and the 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, adversely affect the operations and costs of the companies engaged in the energy industry. Laws, regulations and existing policies related to climate change and to GHG emissions have been rapidly evolving and are increasingly difficult to predict, particularly in light of recent announcements and actions by the U.S. government to reconsider air-related regulations and policies.

For instance, in response to the U.S. Environmental Protection Agency (the “EPA”) endangerment finding on GHGs, 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. However, on June 11, 2025, the EPA proposed a rule to repeal all GHG emissions standards for the power sector under the CAA and to repeal amendments to the 2024 Mercury and Air Toxics Standards.

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. On March 14, 2025, the Trump Administration signed legislation disapproving this rule, and therefore, the future of this rule remains unclear.

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 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.

New or existing laws and regulations relating to climate change, including, state cap-and-trade programs, may affect our business operations through 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.

Our business and results of operations are subject to physical risks associated with climate change.

Changes in climate have caused, and are expected to continue to cause, among other things, increasing mean annual temperatures, rising sea levels and changes to meteorological and hydrological patterns, as well as impacts to the frequency and intensity of wildfires, freezes, floods, drought, hurricanes, other storms and severe weather-related events and natural disasters. These changes have and could continue to significantly impact our future results of operations and may have a material adverse effect on our business, financial condition and results of operations. Accordingly, a natural disaster has the potential to disrupt our and our third-party E&P operators’ businesses and may cause us to experience work stoppages, project delays, financial losses and additional costs to resume operations, including increased insurance costs or loss of coverage, legal liability and reputational losses, and we expect that increasing physical climate-related impacts may result in further changes to the cost or availability of insurance in the future.

Our and our third-party E&P operators are subject to complex federal, state and other environmental, health and safety laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us and our third-party E&P operators to significant liabilities.

Our operations, through PhoenixOp and our third-party E&P operators, are subject to a complex and rapidly evolving set of federal, state, local and international environmental, health and safety laws and regulations. These laws govern the generation, use, storage, release, management and disposal of, or exposure to, hazardous materials and wastes, the remediation of contaminated sites, fuel storage, wastewater and stormwater discharges, air emissions, the protection of natural resources (such as protected wetlands or threatened and endangered species and their habitat) and occupational health and safety. These laws, rules and regulations may require us to obtain and maintain regulatory licenses, permits and other approvals, comply with the requirements of such licenses, permits and other approvals and perform environmental impact studies prior to commencing new projects or making changes to existing projects.

We, through PhoenixOp and our third-party E&P operators, perform work involving 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 third-party 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 our third-party E&P operators 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. New environmental legislation may impose stricter standards and enforcement, increased fines and penalties for non-compliance, more stringent environmental regulatory scrutiny, and a heightened degree of responsibility for companies and their officers, directors, and employees. Potential changes in environmental regulations, if any, may adversely affect our operations and the operations of the third-party 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.

Unknown environmental hazards, potentially caused by previous or existing owners or operators, may exist on properties in which we hold an interest. Our properties could be located on or near an ongoing environmental cleanup site, 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 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 costs 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 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.

We or our third-party E&P operators could be subject to environmental lawsuits.

The oil and natural gas industry involves various operational 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 threats. These hazards could result in substantial losses 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 held liable for environmental damages caused by previous owners or operators of property we have acquired. Environmental hazards and damages may extend beyond our land, prompting neighboring landowners and other third parties to file claims under environmental statutes and common law for personal injury and property damage allegedly resulting from the release of hazardous substances or other waste material into the environment on or near our properties. There can be no guarantee 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 Report, 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 and the Preferred Shares.

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 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 U.S. Internal Revenue Service (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 conflicts in the Middle East, including with Iran and 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 third-party E&P operators’ operations, affect our ability and the ability of our third-party 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.

Any 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 are uncertain and hard to predict. An extended period of global supply chain and economic disruption, as well as significantly decreased demand for oil and gas, due to 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 and distribution payments on the Preferred Shares.

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, and higher rates have generally persisted through the first half 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 United States Federal Reserve (“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 us 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.

Risks Related to Our Indebtedness

Our substantial indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the Notes, the Preferred Shares 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, to pay distributions on the Preferred Shares, or to fund our other liquidity needs. As of September 30, 2025, after giving effect to the borrowing of additional $50.0 million in aggregate under the Fortress Credit Agreement in October 2025, we had approximately $1,455.8 million of indebtedness outstanding, which comprised $450.0 million outstanding under the Fortress Credit Agreement, $218.2 million outstanding under the Adamantium Loan Agreement (and corresponding amount of Adamantium Securities), $683.6 million of Reg D Bonds outstanding, $59.7 million of Reg A Bonds outstanding, $25.9 million of the Exchange Notes outstanding, and $18.4 million of the Registered Notes outstanding. Furthermore, the Fortress Credit Agreement provides for a rebate of approximately $15.0 million in original issue discount, payable by setoff against final payment in full of the Fortress Credit Agreement, if (a) all outstanding principal and accrued interest on the loans under the Fortress Credit Agreement are paid in full in cash on or before December 18, 2027, and (b) no event of default resulting from the failure to pay principal or interest when due under the terms and conditions of the Fortress Credit Agreement has occurred prior to such date, subject to certain other conditions. See “ 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, including:

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making it more difficult for us to satisfy our obligations with respect to the Notes, the Preferred Shares and our other indebtedness, and if we fail to comply with these requirements, an event of default could result under the Notes or other indebtedness and we may be unable to make distributions or conduct redemptions with respect to the Preferred Shares;

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limiting our ability to obtain additional financing to fund future working capital, capital expenditures, investments, acquisitions, or other general corporate requirements;

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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;

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increasing our vulnerability to general adverse economic and industry conditions;

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exposing us to the risk of increased interest rates, as borrowings under the Fortress Credit Agreement are at variable rates of interest;

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limiting our flexibility in planning for and reacting to changes in the industry in which we compete and to changing business and economic conditions;

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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

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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 indentures that govern our Notes do 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 us prior to any payment to holders of Notes. If we incur any additional indebtedness that ranks equally with the Registered 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. If we incur any additional 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 us prior to any payment to holders of Preferred Shares. In each 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 Registered 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 or to make distribution payments on the Preferred Shares, depends 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, distributions on the Preferred Shares, or to service our other obligations.

We recorded net income of $32.8 million and net loss of $11.3 million for the nine months ended September 30, 2025 and 2024, respectively, and net income (loss) of $(24.8) million, $(16.2) million, and $5.7 million for the years ended December 31, 2024, 2023, and 2022, respectively. Through 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. During the nine months ended September 30, 2025, we continued to incur a significant amount of debt. 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 or securities offerings 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,” and “Part I. Item 2. 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 Registered Notes or Preferred Shares, as applicable.

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. Failure to do so could have a material adverse effect on our business, results of operations, and financial condition.

As of September 30, 2025, after giving effect to the borrowing of additional $50.0 million in aggregate under the Fortress Credit Agreement in October 2025, we had approximately $743.9 million of indebtedness maturing within three years, including all amounts under the Fortress Credit Agreement, $886.3 million of indebtedness maturing within five years, including all amounts under the Fortress Credit Agreement, $1,010.7 million of indebtedness maturing within seven years, and $1,455.8 million of indebtedness maturing within eleven years. Furthermore, the Fortress Credit Agreement provides for a rebate of approximately $15.0 million in original issue discount, payable by setoff against final payment in full of the Fortress Credit Agreement, if (a) all outstanding principal and accrued interest on the loans under the Fortress Credit Agreement are paid in full in cash on or before December 18, 2027, and (b) no event of default resulting from the failure to pay principal or interest when due under the terms and conditions of the Fortress Credit Agreement has occurred prior to such date, subject to certain other conditions. The terms of the Registered Notes, 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 Registered Notes, 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, 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. All of these events could result in your losing all or a part of your investment in the Registered Notes or Preferred Shares, as applicable.

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:

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incur additional indebtedness and guarantee indebtedness;

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issue equity securities;

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pay distributions or make other distributions in respect of, or repurchase or redeem, any of our securities;

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prepay, redeem, or repurchase certain indebtedness;

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make loans and investments;

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sell or otherwise dispose of assets;

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incur liens;

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enter into transactions with affiliates;

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designate any of our subsidiaries as unrestricted subsidiaries;

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enter into agreements restricting our subsidiaries’ ability to pay distributions;

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consolidate, merge, sell, or otherwise dispose of all or substantially all of our assets; and

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prepay subordinated or junior lien indebtedness.

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:

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limited in how we conduct our business;

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unable to raise additional indebtedness or equity financing to operate during general economic or business downturns; or

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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. All of these events could result in your losing all or a part of your investment in the Registered Notes or Preferred Shares, as applicable.

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 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 and paying distributions on the Preferred Shares 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 Relating to the Preferred Shares

The Preferred Shares represent perpetual equity interests in us, and holders of Preferred Shares should not expect us to redeem any Preferred Shares on any particular date.

The Preferred Shares represent perpetual equity interests in us, and they have no maturity or mandatory redemption date and are not redeemable at the option of holders of Preferred Shares under any circumstances. As a result, unlike our indebtedness, none of the Preferred Shares will give rise to a claim for payment of a principal amount at a particular date. Instead, the Preferred Shares may be redeemed by us at our option at any time or from time to time, out of funds legally available for such redemption, at a redemption price payable in cash of $27.50 per Preferred Share plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption, whether or not declared. Any decision we may make at any time to redeem the Preferred Shares will depend upon, among other things, our evaluation of our capital position and general market conditions at that time. In addition, the instruments governing our outstanding indebtedness currently do and may in the future limit our ability to redeem the Preferred Shares. For example, under the terms of the Fortress Credit Agreement we may only redeem the Preferred Shares so long as, among others, (i) no default or event of default has occurred and is continuing or would occur as a result of such redemption and (ii) immediately after giving effect to such redemption we remain in compliance with the financial covenants to maintain (a) a maximum total secured leverage ratio, (b) a minimum current ratio, and (c) a minimum asset coverage ratio on a pro forma basis. Further, under the terms of the Fortress Credit Agreement, we may only expend an aggregate amount of $5,000,000 to redeem Preferred Shares in any fiscal quarter, which quarterly limit may be reduced by the amount of certain cash payments made during such quarter to the extent related to certain debt refinancing transactions. For a description of the terms of the Fortress Credit Agreement, including these ratios and limits on our ability to redeem the Preferred Shares, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement.” As a result, the holders of the Preferred Shares should expect to bear the financial risks of an investment in the Preferred Shares for an indefinite period of time. Moreover, as further described below, the Preferred Shares will rank junior to all of our existing and future indebtedness and other liabilities with respect to assets available to satisfy claims against us.

The Preferred Shares are junior and subordinated to our existing and future indebtedness, and your interests could be diluted by the issuance of additional equity interests, including additional Preferred Shares, and by other transactions.

The Preferred Shares will rank, with respect to rights to the payment of distributions and the distribution of assets upon our liquidation, dissolution or winding up, (a) senior to all classes or series of equity securities issued by us other than equity securities referred to in clauses (b) and (c) (“Junior Securities”); (b) on a parity with all equity securities issued by us with terms specifically providing that those equity securities rank on a parity with the Preferred Shares with respect to rights to the payment of distributions and the distribution of assets upon our liquidation, dissolution or winding up (“Parity Securities”); (c) junior to all equity securities issued by us with terms specifically providing that those equity securities rank senior to the Preferred Shares with respect to rights to the payment of distributions and the distribution of assets upon our liquidation, dissolution or winding up (“Senior Securities”); and (d) junior to all of our existing and future indebtedness and to the indebtedness of our existing subsidiaries and any future subsidiaries.

The Preferred Shares are junior and subordinated to all our existing and future indebtedness and to the indebtedness of our existing subsidiaries and any future subsidiaries. We and our subsidiaries have incurred and may in the future incur substantial amounts of debt and other obligations that will rank senior to the Preferred Shares. As of September 30, 2025, after giving effect to the borrowing of an additional $50.0 million in aggregate under the Fortress Credit Agreement in October 2025, we would have had approximately $1,455.8 million of indebtedness outstanding. We have historically conducted, and from time to time may conduct, offerings of debt securities pursuant to Regulation D or Regulation A, or pursuant to our registration statement on Form S-1 (File No. 333-282862) and, as of September 30, 2025, we and our subsidiaries are authorized to issue up to approximately $2.7 billion in additional debt securities through such offerings. The payment of principal and interest on our existing and future debt reduces cash available for distribution, including the holders of the Preferred Shares. If we are forced to liquidate our assets to pay our creditors, we may not have sufficient assets to pay amounts due on any or all of the Preferred Shares then outstanding and any Parity Securities that we have issued or may issue in the future, in which case, holders of the Preferred Shares will share ratably with holders of such Parity Securities. The issuance of any Senior Securities or additional Parity Securities (and including additional Preferred Shares) would dilute the interests of the holders of the Preferred Shares and could affect our ability to pay distributions on, redeem, or pay the liquidation preference on the Preferred Shares. Certain of our existing or future debt instruments may restrict the authorization, payment or setting apart of distributions for the Preferred Shares. If we decide to issue additional debt or Senior Securities in the future, it is possible that these securities will be governed by an indenture or other instrument containing covenants restricting our operating flexibility. Future issuances and sales of Senior Securities, Parity Securities or Junior Securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Preferred Shares to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.

The Preferred Shares have only limited voting rights.

The holders of the Preferred Shares will have only limited voting rights. Except as set forth in our governing documents or as otherwise required by Delaware law, holders of the Preferred Shares generally will not have voting rights. Although the holders of the Preferred Shares are entitled to limited protective voting rights with respect to certain matters and additional voting rights contingent upon the occurrence of certain events, each as described in the Share Designation with respect to such matters, the Preferred Shares will generally vote separately as a class along with all other series of Parity Securities that we may issue upon which like voting rights have been conferred and are exercisable. As a result, the voting rights of holders of Preferred Shares are limited and may be significantly diluted, and the holders of any such other series of Parity Securities that we may issue may be able to control or significantly influence the outcome of any vote.

Market interest rates and other factors may affect the value of the Preferred Shares.

The price of the Preferred Shares are and will be impacted by the distribution yield on the Preferred Shares relative to market interest rates. An increase in market interest rates may lead prospective purchasers of the Preferred Shares to expect a higher yield, and higher interest rates would likely increase our borrowing costs and potentially decrease funds available for distribution, including to the holders of the Preferred Shares. Accordingly, higher market interest rates could cause the market price of the Preferred Shares to decrease.

The trading prices of the Preferred Shares of the Preferred Shares will also depend on many other factors, which may change from time to time, including but not limited to:

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the market for similar securities;

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government action or regulation;

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general economic conditions or conditions in the financial or energy markets;

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our financial condition, performance and prospects; and

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the financial condition, performance and prospects of similarly situated companies;

In addition, over the last several years, prices of equity securities, including equity securities issued by companies in our industry, in the U.S. trading markets have been experiencing extreme price fluctuations. As a result of these and other factors, investors who purchase the Preferred Shares in this offering may experience significant volatility, including a substantial and rapid decrease, in the market price of the Preferred Shares. This volatility and any decrease may be driven by factors unrelated to our operating performance or prospects.

Your ability to transfer the Preferred Shares at a time or price you desire may be limited by the absence of an active trading market, which may not develop or if developed might not stay sustainbly active.

The Preferred Shares are securities issued recently with no prior established trading market. An active trading market on the NYSE American for the Preferred Shares may not develop or, even if it develops, may not last, in which case the trading price of the Preferred Shares could be adversely affected and your ability to transfer your Preferred Shares will be limited.

Our obligations to make distributions on the Preferred Shares, together with the terms of our existing indebtedness, could adversely affect our business, results of operation, and financial condition, and our ability to service or otherwise repay our indebtedness may be adversely affected.

On September 29, 2025, we completed our initial public offering of Preferred Shares (the “Offering”) pursuant to Tier 2 of Regulation A+ promulgated under the U.S. Securities Act of 1933, as amended. Upon completion of the Offering, we sold an aggregate of 2,704,023 Preferred Shares representing $67,600,575.00 in initial liquidation preference at a public offering price of $20.00 per share. In connection with the Offering, we amended and restated our Second Amended and Restated Limited Liability Company Agreement, dated as of January 23, 2025, and entered into a Third Amended and Restated Limited Liability Company Agreement and a Share Designation with respect to the Preferred Shares (together, the “New LLC Agreement”) to, among other things, (i) establish an authorized share capital consisting of common shares and preferred shares, each representing limited liability company interests, (ii) create a new class of Preferred Shares with the designations, preferences and other rights as set forth in the New LLC Agreement, and (iii) establish a board of directors to manage our business and affairs. Following the completion of the Offering, we became obligated to make certain distributions to the holders of the Preferred Shares, which will reduce any amounts available for the service or repayment of our indebtedness and may otherwise impact our available resources to invest in the growth of our business. We cannot assure you that our businesses will generate sufficient cash flow from operations or that future borrowings will be available to us in an amount sufficient to enable us to make distributions on the Preferred Shares, pay our indebtedness or to fund our other liquidity needs. Following the completion of the Offering, the Preferred Shares also expose us to a number of additional costs and risks, including as a result of such shares being listed on the NYSE American, our tax status as a partnership, and broader expansion of our equity owners. These and other risks may otherwise increase the risks described elsewhere herein.

We may fail to comply with the continued listing standards of the NYSE American, which may result in a delisting of our Preferred Shares.

On September 30, 2025, the Preferred Shares commenced trading on the NYSE American under the symbol “PHXE.P.” Although we expect to meet the minimum continued listing standards set forth in NYSE American listing standards, we cannot assure you that the Preferred Shares will continue to be listed on NYSE American in the future. In order to continue listing the Preferred Shares on NYSE American we must maintain certain financial, distribution and stock price levels and must maintain a minimum number of holders of Preferred Shares.

If NYSE American determines to delist the Preferred Shares and we are not able to list the Preferred Shares on another national securities exchange, a reduction in some or all of the following may occur, each of which could have a material adverse effect on the holders of Preferred Shares, as well as our business, financial condition and results of operations:

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the liquidity of the Preferred Shares;

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the market of the Preferred Shares;

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our ability to obtain financing for the continuation of our operations;

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the number of investors that will consider investing in the Preferred Shares;

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the number of market makers in the Preferred Shares;

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the availability of information concerning the trading prices and volume of the Preferred Shares; and

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the number of broker-dealers willing to execute trades in the Preferred Shares.

In addition, the National Securities Markets Improvement Act of 1996 (“NSMIA”) provides for the federal preemption of state securities laws of “covered securities” under certain circumstances. Under NSMIA, covered securities include, among others, securities that are listed or approved on certain national securities exchanges (including NYSE American) and securities of an issuer that has securities listed or approved for listing on certain national securities exchanges where those securities are senior to the listed securities (for example, bonds issued by companies that have equity listed on a national securities exchange) or equal in rank to the listed securities. As a result, for so long as the Preferred Shares are listed on the NYSE American, we will not be required to register or qualify in any state the offer, transfer or sale of our Preferred Shares and any of our other securities that are senior or equal in rank to the Preferred Shares, including our Notes. If the Preferred Shares are delisted from the NYSE American and are not listed on another national securities exchange, the sale or transfer of the Preferred Shares and any of our other securities that are senior or equal in rank to the Preferred Shares, including our Notes, may not be exempt from state securities laws. In such event, we may need to register or otherwise qualify such securities for any offer, transfer or sale in certain states or determine that any such offer, transfer or sale is exempt under applicable state securities laws. To the extent that we do not register or otherwise qualify such securities, or determine that such securities are not exempt under applicable state securities laws, we and the holders of such securities may be limited in the ability to offer, transfer or sell such securities, which could have a material adverse effect on the value of such securities, on our ability to raise capital, and on our liquidity, business, financial condition, results of operations and prospects.

Our ability to issue Parity Securities in the future could adversely affect the rights of holders of our Preferred Shares.

We may in the future issue Parity Securities, which could have the effect of reducing the amounts available to the holders of the Preferred Shares issued in this offering upon our liquidation, dissolution or winding up if we do not have sufficient funds to pay all liquidation preferences of the Preferred Shares and any such Parity Securities in full. It also would reduce amounts available to make distributions on the Preferred Shares issued in this offering if we do not have sufficient funds to pay distributions on all outstanding Preferred Shares and any such Parity Securities. In addition, future issuances and sales of Parity Securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for the Preferred Shares to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.

We are not required to accumulate cash for the purpose of meeting our obligations to holders of the Preferred Shares, which, along with the agreements governing our indebtedness, may limit the cash available to make distributions on the Preferred Shares.

Pursuant to the terms of the Preferred Shares, distributions on the Preferred Shares will accrue whether or not we have earnings, whether there are assets legally available for the payment of such distributions and whether such distributions are authorized or declared. However, future distributions on our common shares and preferred shares, including the Preferred Shares, will be at the discretion of our board of directors and will depend on, among other things, our results of operations, cash flow from operations, financial condition and capital requirements, any debt service requirements and any other factors our board of directors deems relevant. Our ability to pay cash distributions on the Preferred Shares is dependent on our ability to operate profitably and to generate cash from our operations. In addition, the instruments governing our outstanding indebtedness currently do and may in the future limit our ability to make distributions with respect to the Preferred Shares. For example, under the terms of the Fortress Credit Agreement we may only declare or make a distribution with respect to the Preferred Shares so long as, among others, (i) no default or event of default has occurred and is continuing or would occur as a result of such distribution and (ii) immediately after giving effect to such distribution we remain in compliance with the financial covenants to maintain (a) a maximum total secured leverage ratio, (b) a minimum current ratio, and (c) a minimum asset coverage ratio on a pro forma basis. 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. We cannot guarantee that we will be able to make cash distributions or what the actual distributions will be for any future period. Further, we are not required to accumulate cash for the purpose of meeting our obligations to holders of the Preferred Shares and the Preferred Shares are not subject to any sinking fund, which may reduce the extent of any cash available for distributions on the Preferred Shares.

Whenever distributions on the Preferred Shares are in arrears for six or more quarterly distribution periods (whether or not consecutive), the number of directors constituting our board of directors will be automatically increased by two and the holders of the Preferred Shares will be entitled to vote for the election of those two additional directors at a special meeting called by us at the request of the holders of record of at least 25% of the outstanding Preferred Shares, and at each subsequent annual meeting until all distributions accumulated on the Preferred Shares for all past distribution periods and the then current distribution period shall have been fully paid or declared and a sum sufficient for the payment thereof set aside for payment. Such remedies could have a material adverse effect on the Company’s financial condition.

Our ability to make distributions is limited by the requirements of Delaware law.

Our ability to make distributions may be adversely affected by a number of factors, including the risk factors described herein. Any reduction of our distributions would not only reduce the amount of distributions you would receive as a holder of our Preferred Shares, but could also have the effect of reducing the market price of our Preferred Shares and our ability to raise funds in new securities offerings.

In addition, the rate at which holders of our Preferred Shares are taxed on distributions we pay and the characterization of our distribution — be it ordinary income, capital gains, or a return of capital — could have an impact on the market price of our Preferred Shares and, in turn, our ability to raise funds in new securities offerings. After we announce the expected characterization of dividend distributions we have paid, the actual characterization (and, therefore, the rate at which holders of our Preferred Shares are taxed on the dividend distributions they have received) could vary from our expectation, including due to errors, changes made in the course of preparing our corporate tax returns, or changes made in response to an IRS audit, with the result that holders of our Preferred Shares could incur greater income tax liabilities than expected.

Holders of Preferred Shares may have liability to repay distributions.

Under certain circumstances, the holders of the Preferred Shares may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Limited Liability Company Act (the “DLLCA”), we generally may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to members on account of their equity interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that, unless otherwise agreed, for a period of three years from the date of an impermissible distribution, members who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited liability company for the distribution amount.

Risks Related to the Phoenix Equity’s Ownership of Our Common Shares and Certain LLCA Provisions.

The interests of holders of Preferred Shares may conflict with the interests of our controlling shareholder.

We are wholly owned and controlled by Phoenix Equity. LJC controls Phoenix Equity and, therefore, indirectly has control over our management. In connection with the Offering, we became a manager-managed limited liability company and our business and affairs are managed under the direction of a board of directors. Phoenix Equity holds all of our common shares, representing limited liability company interests, and, as a result, other than under the limited circumstances described in the Share Designation in which holders of the Preferred Shares have voting rights, we will continue to be controlled by Phoenix Equity. As a result of this concentrated control, Phoenix Equity has the ability to determine corporate matters for the foreseeable future, including the power to, among other things:

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elect or remove any of our directors, at any time, with or without cause;

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approve changes to the Third Amended and Restated Limited Liability Company Agreement of Phoenix Energy One, LLC, effective as of September 29, 2025 (“Third ARLLCA”) that require shareholder approval (subject to the limited voting rights of the Preferred Shares), as described in the Offering Statement; and;

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ratify the appointment of our auditors;

Phoenix Equity may also be able to prevent or cause (either by way of a sale of their own stake or by approving our merger or sale of as a whole) a change of control of Phoenix Energy One, LLC. Phoenix Equity’s control over us, and the Phoenix Equity’s ability to prevent or cause a change of control of Phoenix Energy One, LLC, may delay or prevent a change of control, or cause a change of control to occur at a time when it is not favored by other shareholders. As a result, the trading price of the Preferred Shares could be adversely affected.

Our Third ARLLCA eliminates members of our board of directors’ fiduciary duties to us. If conflicts of interest arise among members of our board of directors and us, members of our board of directors may make decisions in their sole and absolute discretion, and shall be entitled to consider only such interests and factors as they desire, including their own interests.

Our Third ARLLCA contains provisions that eliminate the standards to which members of our board of directors’ would otherwise be held by state law, other than an implied contractual duty of good faith and fair dealing. To the extent permitted by any applicable law, members of board of directors are able make any decision or determination with respect to the us or our business and affairs, whether pursuant to the terms of the Third ARLLCA or otherwise in their sole and absolute discretion, and are entitled to consider only such interests and factors as they desire, including their own interests, and shall have no duty or obligation, fiduciary or otherwise, to give any consideration to any interest of or factors affecting us or any of our shareholders, including holders of Preferred Shares. As a result, if members of our board of directors interests and duties to other entities conflict with our interests, members of our board of directors may favor their own interest over the interest of us and our shareholders.

Furthermore, the Third ARLLCA provides that to the fullest extent permitted by DLLCA, members of our board of directors will not be liable to us or any of our shareholders for monetary damages unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such member engaged in fraud, and we will also indemnify such members of our board of directors for to the fullest extent permitted by the DLLCA.

The Third ARLLCA contains an exclusive forum provision that may discourage lawsuits against us or our directors and officers.

The Third ARLLCA requires any dispute, controversy or claim arising out of or relating to the Third ARLLCA, or any breach, termination or the validity of the Third ARLLCA, our internal affairs, the ownership, transfer or rights or obligations of or with respect to any shares, or any action or inaction arising out of the foregoing, as well as any question of the arbitrator’s jurisdiction or the existence, scope or validity of the Third ARLLCA’s arbitration mechanism, to be submitted, upon notice delivered by any party to such claim, to confidential, final and binding arbitration. The foregoing arbitration requirements do not apply with respect to any suits brought to enforce a duty or liability created by the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. Furthermore, the Third ARLLCA provides that unless we consent in writing to the selection of an alternative forum, the federal district courts of the United States shall be the exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act. Any person or entity purchasing or otherwise acquiring any interest in our equity securities is deemed to have received notice of and consented to these provisions. These choice of forum provisions may result in increased costs to shareholders to bring a claim, limit a shareholder’s ability to bring a claim in a forum that it finds favorable for disputes with us or our directors, officers or other employees, and may generally have the effect of discouraging lawsuits against us and our directors, officers and other employees. However, shareholders are not deemed to have waived our compliance with the federal securities laws and the rules and regulations thereunder. The enforceability of similar choice of forum provisions in other companies’ governing documents has been challenged in legal proceedings, and it is possible that a court could find these types of provisions to be inapplicable or unenforceable. If a court were to find these provisions in our Third ARLLCA to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could adversely affect our business and financial condition.

Risks Related to Certain Tax Matters

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or if we were otherwise subject to a material amount of entity- level taxation, then cash available for distribution could be reduced.

The anticipated after-tax economic benefit of an investment in us depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are organized as a limited liability company under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based on our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our classification as a partnership for U.S. federal income tax purposes.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate and we would also likely pay additional state and local income taxes at varying rates. Distributions would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to our members. Because a tax would be imposed upon us as a corporation, the cash available to make principal and interest payments on the Notes and distribution payments on the Preferred Shares could be reduced. Thus, treatment of us as a corporation could result in a reduction in the anticipated cash-flow and after-tax return to our members, which would cause a reduction in the value of an investment in us and could cause a material adverse effect on our business, results of operation, and financial condition.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, capital, and other forms of business taxes, as well as subjecting nonresident partners to taxation through the imposition of withholding obligations and composite, combined, group, block, or similar filing obligations on nonresident partners receiving a distributive share of state “sourced” income. We currently own property or do business in Montana, Utah, Wyoming, Texas, North Dakota and Colorado, among other states. Imposition on us of any of these taxes in jurisdictions in which we own assets or conduct business or an increase in the existing tax rates could result in a reduction in the anticipated cash-flow and after-tax return to our members, which would cause a reduction in the value of your investment in us and could cause a material adverse effect on our business, results of operation, and financial condition.

The tax treatment of publicly traded partnerships or an investment in us could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our shares, may be modified by administrative, legislative or judicial interpretation. From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships or an investment in our shares, including eliminating partnership tax treatment for certain publicly traded partnerships, as well as reducing or eliminating certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies.

Any changes to federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to be treated as a partnership for federal income tax purposes or otherwise adversely affect our business, financial condition or results of operations. Any such changes or interpretations thereof could cause a material adverse effect on our business, results of operation, and financial condition.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for Preferred Shares and the cost of any IRS contest will reduce our cash available for distribution.

The IRS has made no determination as to our status as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. As a result, any such contest with the IRS may materially and adversely impact the market for our shares and the price at which our shares trade. In addition, our costs of any contest with the IRS, principally legal, accounting and related fees, will be indirectly brne by our members because the costs will reduce our cash available for distribution.

Preferred Shares that are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of Preferred Shares) may be considered disposed. If so, the holder of such Preferred Shares would no longer be treated for tax purposes as a partner with respect to those Preferred Shares during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a holder of Preferred Shares that are the subject of a securities loan may be considered as having disposed of the loaned shares. In that case, the holder of such Preferred Shares may no longer be treated for tax purposes as a partner with respect to those Preferred Shares during the period of the loan and may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those Preferred Shares may not be reportable by the shareholder and any cash distributions received by the holder as to those Preferred Shares could be fully taxable as ordinary income. You are encouraged to consult a tax advisor if you desire to assure your status as a partner and avoid the risk of gain recognition from a securities loan.

Certain tax consequences of the ownership of our Preferred Shares, including treatment of distributions as guaranteed payments for the use of capital, are uncertain.

The tax treatment of distributions on our Preferred Shares is uncertain. We treat the holders of the Preferred Shares as partners for tax purposes and will treat distributions on the Preferred Shares as guaranteed payments for the use of capital that will generally be taxable to the holders of the Preferred Shares as ordinary income. Although a holder of Preferred Shares will recognize taxable income from the accrual of such a guaranteed payment (even in the absence of a contemporaneous cash distribution), we anticipate accruing and making the guaranteed payment distributions quarterly. Otherwise, except in the case of our liquidation, the holders of Preferred Shares are generally not anticipated to share in our items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to the holders of Preferred Shares. If the Preferred Shares were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of Preferred Shares.

A holder of Preferred Shares will be required to recognize a gain or loss on a sale of Preferred Shares equal to the difference between the amount realized by such holder and such holder’s tax basis in the Preferred Shares sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such Preferred Shares. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a Preferred Share will generally be equal to the sum of the cash and the fair market value of other property paid by the holder of such Preferred Shares to acquire such Preferred Shares. Gain or loss recognized by a holder of Preferred Shares on the sale or exchange of a Preferred Share held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of Preferred Shares will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.

Investment in the Preferred Shares by tax-exempt investors, such as employee benefit plans and individual retirement accounts, and non-U.S. persons raises issues unique to them. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for U.S. federal income tax purposes. Distributions to non-U.S. holders of Preferred Shares are subject to withholding taxes. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders of Preferred Shares may be required to file U.S. federal income tax returns in order to seek a refund of such excess. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor with respect to the consequences of owning our Preferred Shares.

Our treatment of distributions on our Preferred Shares as guaranteed payments for the use of capital means that such distributions will not be eligible for the 20% deduction for qualified business income.

For taxable years ending on or before December 31, 2025, a non-corporate member may be entitled to a deduction equal to 20% of its “qualified business income” attributable to its interest in a partnership, subject to certain limitations. As described above, we will treat distributions on the Preferred Shares as guaranteed payments for the use of capital, and under the applicable existing and proposed Treasury regulations promulgated under the Code (the “Treasury Regulations”) a guaranteed payment for the use of capital will not be taken into account for purposes of computing qualified business income. As a result, distributions received by the holders of our Preferred Shares will not be eligible for the 20% deduction for qualified business income. Holders of Preferred Shares should consult their tax advisors regarding the availability of the deduction for qualified business income.

Risks Relating to Our Status as a Public Reporting Company

We only recently became a public reporting company, and the obligations associated with being a public reporting company will require significant resources and management attention.

We only recently became a public reporting company, following the effectiveness of our Registration Statement with respect to the continuous offering of up to $750.0 million aggregate principal amount of Registered Notes, on May 14, 2025. As a recent public reporting company, we incur significant legal, regulatory, finance, accounting, investor relations, and other expenses that we previously did not incur 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 currently does, and will need to continue to, devote a substantial amount of time to ensure that we comply with all of these additional 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.

Failure to comply with requirements to design, implement, and maintain effective internal controls could have a material adverse effect on our business.

We were not previously 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 are subject to significant requirements for enhanced financial reporting and internal controls. The process of designing, implementing and maintaining 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 effectiveness of the Registration Statement. 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 control 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.

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 Topic 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.

We are a “controlled company” within the meaning of the corporate governance standards of the NYSE American and rely, and may continue to rely, on exemptions from certain corporate governance standards.

Phoenix Equity holds all of our common shares, representing limited liability company interests, and, as a result, other than under the limited circumstances described in the Share Designation setting forth the rights, powers and preferences of the Preferred Shares (the “Share Designation”) in which holders of the Preferred Shares have voting rights, Phoenix Equity has all of the voting power of our Company. As such, we are a “controlled company” under the rules of NYSE American. As a controlled company, we may elect not to comply with certain corporate governance requirements, including the requirements that:

•

a majority of our board of directors consists of “independent directors,” as defined under the rules of such exchange;

•

our board of directors has a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

•

our board of directors has a nominating and corporate governance committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

For so long as we remain a “controlled company,” we may continue to rely on these exemptions. We have elected not to comply with certain corporate governance requirements under the rules, including the requirements above. As a result of these and any additional future elections, our board of directors currently does not and may not in the future have a majority of independent directors, we currently do not have and may never have a compensation committee consisting entirely of independent directors, and our directors currently are not and may not in the future be nominated or selected by independent directors.

We are a company with only preferred securities listed on the NYSE American and thus are only required to comply with certain corporate governance requirements, including with respect to our audit committee, to the extent required by Rule 10A-3 under the Exchange Act.

The rules of NYSE American provide that companies with only preferred or debt securities listed on NYSE American are only required to comply with the requirements to have a board that is composed of a majority of “independent directors,” an audit committee that is composed entirely of independent directors, an audit committee charter, and audit committee meeting requirements, responsibilities and authorities, to the extent required by Rule 10A-3 under the Exchange Act. We are a company with only preferred securities listed on NYSE American and thus are only required to comply with such requirements to the extent required by Rule 10A-3 under the Exchange Act. We intend to comply with these reduced requirements and with the requirements of Rule 10A-3 under the Exchange Act. As a result, under these rules, we must have an audit committee of at least one director, which director must be independent. We currently have one independent director who qualifies as independent for audit committee purposes. As a result of these reduced requirements, you will not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of NYSE American, particularly with respect to the audit committee requirements set forth in the rules of NYSE American.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

(a)

Recent Sales of Unregistered Securities : On September 29, 2025, Company completed its offering of Preferred Shares pursuant to Tier 2 of Regulation A+ promulgated under the U.S. Securities Act of 1933, as amended. The Preferred Shares were offered pursuant to the Company’s offering statement on Form 1-A, initially filed with the U.S. Securities and Exchange Commission (the “SEC”) on June 26, 2025 and initially qualified by the SEC on August 27, 2025. For more information, see the Company’s Current Report on Form 8-K filed with the SEC on September 30, 2025.

(b)

Use of Proceeds : On May 14, 2025, the Registration Statement was declared effective, pursuant to which the Issuer intends to sell up to $750.0 million aggregate principal amount of Registered Notes on a continuous basis. The offering of the Registered Notes is ongoing and, as of the date of this Quarterly Report, the Issuer has sold $18.4 million of Registered Notes.

On September 29, 2025, the Company sold an aggregate of 2,704,023 Preferred Shares representing $67,600,575.00 in initial liquidation preference at a public offering price of $20.00 per share for gross proceeds of approximately $54.1 million, before payment of selling agent commissions of approximately $4.2 million and transaction fees and expenses.

The Company plans to use the net proceeds from these offerings (a) to make investments in Phoenix Operating, LLC or to otherwise finance potential drilling and exploration operations, (b) to purchase mineral rights and non-operated working interests, as well as for additional asset acquisitions, and (c) for other working capital needs.

(c)

Purchases of Equity Securities by the Issuer and Affiliated Purchasers : None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

During the three months ended September 30, 2025,

director or officer of the Company adopted or terminated a “Rule

10b5-1

trading arrangement” or

“non-Rule

10b5-1

trading arrangement,” as each term is defined in Item 408 of Regulation

S-K.

10-Q

Oil and Gas Disclosure

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 September 30, 2025, we owned mineral, royalty, and working interests in 7,335 productive wells, the majority of which are oil wells that also produce natural gas and NGLs.

As of September 30, 2025, we had 180 wells that fall under our “wells in progress” (“WIP”) category, and we had 45.0 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 nine months ended September 30, 2025, the E&P operators of our properties, including PhoenixOp, a direct, wholly owned subsidiary of the Company, drilled 278 gross and 44.4 net productive development wells on the acreage underlying our mineral and royalty interests. This compares to 327 gross and 16.7 net productive development wells drilled by E&P operators on the acreage underlying our mineral and royalty interests in the nine months ended September 30, 2024.

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 September 30, 2025, PhoenixOp had drilled a total of 78 gross and 69.7 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 14 gross and 14 net saltwater disposal wells, and had 42 gross and 37.2 net development wells in progress as of September 30, 2025.

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.

Wells

As of September 30, 2025, we owned mineral, royalty, and working interests in 7,335 total gross wells and 126.3 total net wells. The following table sets forth information about the productive wells in which we have a mineral or royalty interest as of September 30, 2025:


	Well Count
	Oil				Gas
Basin or Producing Region	oss		Net		Gross		Net
Bakken/Williston Basin		4,255		105.2		3		0.0
DJ Basin/Rockies/Niobrara		1,375		16.2		5		0.0
Permian Basin		726		1.4		1		0.0
Other		476		1.2		494		2.3

Total		6,832		124.0		503		2.3

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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 September 30, 2025:

•

Acreage of Mineral Interest


	Net Royalty Acres
Basin	Developed Acreage		Undeveloped Acreage		Total Acreage
Bakken/Williston Basin		19,814		81,571		101,385
DJ Basin/Rockies/Niobrara/PRB		5,332		12,445		17,777
Permian Basin		657		354		1,011
Other		470		435,680		436,150

Total Net Royalty Acres		26,273		530,050		556,323


	Gross Royalty Acres
Basin	Developed Acreage		Undeveloped Acreage		Total Acreage
Bakken/Williston Basin		598,338		980,552		1,578,890
DJ Basin/Rockies/Niobrara/PRB		122,762		376,079		498,841
Permian Basin		94,083		24,603		118,686
Other		17,579		2,216,297		2,233,876

Total Gross Royalty Acres		832,762		3,597,531		4,430,293

•

Acreage of Working Interest


	Net Mineral Acres
Basin	Developed Acreage		Undeveloped Acreage		Total Acreage
Bakken/Williston Basin		51,260		260,878		312,138
DJ Basin/Rockies/Niobrara/PRB		4,178		35,896		40,074
Permian Basin		28		36		64
Other		259		259,474		259,733

Total Net Mineral Acres		55,725		556,284		612,009


	Gross Mineral Acres
Basin	Developed Acreage		Undeveloped Acreage		Total Acreage
Bakken/Williston Basin		254,304		829,222		1,083,526
DJ Basin/Rockies/Niobrara/PRB		44,142		216,241		260,383
Permian Basin		7,680		1,280		8,960
Other		15,872		1,309,568		1,325,440

Total Gross Mineral Acres		321,998		2,356,311		2,678,309

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 helps support the accuracy of estimates regarding gross royalty acres. 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 September 30, 2025, we have 493,035 gross and 70,837 net working interest acres expiring through the end of 2027, with an additional 478,909 gross and 57,296 net working acres expiring in 2028, and 518,618 gross and 79,300 net working interest acres expiring in 2029. The remaining 320,388 gross and 53,482 net working interest acres expire in years 2030 and beyond.

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 September 30, 2025 (1)(2)			As of December 31,
	As of September 30, 2025 (1)(2)			2024 (2)(3)			2023 (2)(4)			2022 (5)
Estimated proved developed reserves
Oil (Bbl)		29,774,089			18,624,758			7,124,194			3,691,722
Natural gas (Mcf)		32,284,307			20,819,874			12,250,285			7,624,212
Natural gas liquids (Bbl)		6,895,752			2,848,355			1,514,761			—
Total (Boe)(6:1) (6)		42,050,559			24,943,093			10,680,669			4,962,424
Estimated proved undeveloped reserves
Oil (Bbl)		41,256,342			31,197,795			24,925,841			—
Natural gas (Mcf)		26,551,536			17,491,089			19,565,808			—
Natural gas liquids (Bbl)		7,466,828			4,753,257			6,648,747			—
Total (Boe)(6:1) (6)		53,148,426			38,866,233			34,835,556			—
Estimated proved reserves
Oil (Bbl)		71,030,431			49,822,554			32,050,035			3,691,722
Natural gas (Mcf)		58,835,843			38,310,963			31,816,093			7,624,212
Natural gas liquids (Bbl)		14,362,579			7,601,611			8,163,508			—
Total (Boe)(6:1) (6)		95,198,985			63,809,326			45,516,225			4,962,424
Percent proved developed		44	%		39	%		23	%		100	%
Estimated probable undeveloped reserves
Oil (Bbl)		131,800,987			107,769,309			74,877,268			—
Natural gas (Mcf)		140,602,188			134,083,603			88,184,111			—
Natural gas liquids (Bbl)		—			—			—			—
Total (Boe)(6:1) (6)		155,234,685			130,116,577			89,574,620			—

(1)

Estimates of reserves of oil and natural gas as of September 30, 2025 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 September 30, 2025, 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 $68.07 per Bbl for oil and $3.102 per MMBtu for natural gas at September 30, 2025. Estimates of reserves of NGL as of September 30, 2025 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at September 30, 2025 was $21.51 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, 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.

(4)

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.

100

Table of Contents

(5)

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.

(6)

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 September 30, 2025 was used, the conversion factor would be approximately 21.9 Mcf per Bbl of oil.

At September 30, 2025, total estimated proved reserves were approximately 95,198,985 Boe, a 31,389,659 Boe net increase from the estimate of 63,809,326 at December 31, 2024. Proved developed reserves of 42,050,559 Boe represented an increase of approximately 17,107,466 Boe from December 31, 2024 as a result of proved developed reserves sales and acquisitions of 36,232 Boe, extensions of 1,064,141 Boe, and total positive revisions of previous estimates of 19,062,441 Boe, offset by production of 2,550,211 Boe. The total positive revisions of previous estimates comprised: (i) negative price revisions of (259,733) Boe, (ii) positive revisions of 15,283,658 Boe due to transferring proved undeveloped reserves to proved developed reserves, (iii) positive well performance revisions of 550,635 Boe, (iv) write downs of (233,051) Boe, (v) positive interest changes of 3,721,458 Boe and (vi) negative revisions of (526) Boe due to changes in lifting cost. Proved undeveloped reserves of 53,148,426 Boe represented an increase of approximately 14,282,193 Boe from December 31, 2024 as a result of proved undeveloped extensions of 32,605,166 Boe and total negative revisions of previous estimates of (11,794,171) Boe, which comprised (i) negative price revisions (602,036) Boe, (ii) negative revisions of (15,283,658) Boe due to transferring proved undeveloped reserves to proved developed reserves, (iii) write downs of (6,437,228) Boe, (iv) positive well performance revisions of 2,422,863 Boe, (v) positive revisions of 119,791 Boe due to asset development timing, (vi) positive interest revisions of 7,995,683 Boe and (vii) negative revisions of (9,586) due to lifting cost changes. During the nine months ended September 30, 2025, approximately $484.6 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, 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 14,262,424 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.

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At December 31, 2023, total estimated proved reserves were approximately 45,516,225 Boe, a 40,553,801 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 5,718,244 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 34,835,557 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 September 30, 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, 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 Nine Months Ended September 30,						For the Years Ended December 31,
	2025			2024			2024			2023			2022
Production Data:
Bakken
Oil (Bbl)		5,179,839			1,693,276			3,022,810			943,930			360,604
Natural gas (Mcf)		1,270,611			1,271,187			1,301,782			1,123,859			522,523
Natural gas liquids (Bbl)		290,212			216,151			270,219			88,762			—
Total (Boe)(6:1) (1)		5,681,820			2,121,292			3,509,992			1,220,003			447,691
Average daily production (Boe/d)(6:1)		20,813			7,742			9,590			3,342			1,227
All Properties
Oil (Bbl)		5,731,412			2,307,011			3,830,461			1,446,928			523,416
Natural gas (Mcf)		2,146,843			2,712,407			2,979,341			2,152,939			1,058,506
Natural gas liquids (Bbl)		388,083			332,732			415,363			201,454			—
Total (Boe)(6:1) (1)		6,477,302			3,091,811			4,742,381			2,007,205			699,834
Average daily production (Boe/d)(6:1)		23,726			11,284			12,993			5,499			1,917
Average Realized Prices:
Bakken
Oil (Bbl)	$	67.09		$	73.65		$	71.77		$	71.43		$	80.67
Natural gas (Mcf)	$	2.64		$	2.05		$	2.12		$	3.47		$	3.77
Natural gas liquids (Bbl)	$	21.03		$	25.72		$	23.53		$	26.70		$	—
All Properties
Oil (Bbl)	$	65.36		$	71.18		$	68.49		$	73.10		$	91.01
Natural gas (Mcf)	$	2.57		$	1.75		$	1.86		$	3.15		$	6.66
Natural gas liquids (Bbl)	$	21.51		$	26.66		$	25.22		$	27.50		$	—
Average Unit Cost per Boe (6:1):
All Properties
Operating costs, production and ad valorem taxes	$	17.05		$	16.24		$	16.11		$	16.18		$	19.89
Operating costs excluding taxes	$	13.45		$	10.93		$	10.75		$	10.86		$	12.58
Percentage of revenue		28.4	%		26.9	%		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.

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Depletion expense was $113.3 million and $52.7 million for the nine months ended September 30, 2025 and 2024, respectively, and $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 $14.01 per Boe and $15.90 per Boe for the nine months ended September 30, 2025 and 2024, respectively, and $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 nine months ended September 30, 2025 compared to 2024 was primarily due to reduced realized production volumes within the mineral and

non-operating

segment and the significant growth in proved reserves due to drilling activity by our operating entity, PhoenixOp. 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 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 expense to continue to increase in subsequent periods as our gross production of oil, gas, and other products increase.

PV-10


	For the Nine Months Ended September 30,				For the Years Ended December 31,
(in thousands)	2025		2024		2024		2023		2022
PV-10 (estimated proved developed reserves) (1)	$	901,803	$	522,282	$	644,098	$	289,809	$	189,885
PV-10 (estimated proved undeveloped reserves) (1)	$	614,591	$	381,382	$	424,595	$	257,472	$	—
PV-10 (estimated total proved reserves) (1)	$	1,516,394	$	903,664	$	1,068,692	$	547,281	$	189,885

(1)

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 generally accepted accounting principles in the United States (“U.S. 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 Company 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.

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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 Nine Months Ended September 30,				For the Years Ended December 31,
(in thousands)	2025		2024		2024		2023		2022
Estimated proved developed reserves:
Standardized measure of discounted future net cash flows	$	901,803	$	522,282	$	644,098	$	289,809	$	189,885
Discounted future income taxes		—		—		—		—		—
PV-10	$	901,803	$	522,282	$	644,098	$	289,809	$	189,885
Estimated proved undeveloped reserves:
Standardized measure of discounted future net cash flows	$	614,591	$	381,382	$	424,595	$	257,472	$	—
Discounted future income taxes		—		—		—		—		—
PV-10	$	614,591	$	381,382	$	424,595	$	257,472	$	—
Estimated total proved reserves:
Standardized measure of discounted future net cash flows	$	1,516,394	$	903,664	$	1,068,692	$	547,281	$	189,885
Discounted future income taxes		—		—		—		—		—
PV-10	$	1,516,394	$	903,664	$	1,068,692	$	547,281	$	189,885

105

Item 6. Exhibits

Incorporated by Reference

Exhibit No.

Exhibit Description+

Form

Date of First
Filing

Exhibit
Number

Filed
Herewith

3.1

Certificate of Formation of Phoenix Capital Group Holdings, LLC, dated as of April 16, 2019.

S-1

10/29/2024

3.1

3.2

Certificate of Amendment to the Certificate of Formation of Phoenix Energy One, LLC, dated as of January 23, 2025.

S-1/A

03/28/2025

3.2

3.3

Third Amended and Restated Limited Liability Company Agreement of Phoenix Energy One, LLC

8-K

09/30/2025

3.1

3.4

Phoenix Energy One, LLC Share Designation with Respect to the Series A Cumulative Redeemable Preferred Shares

8-K

09/30/2025

3.2

106

Incorporated by Reference

Exhibit No.

Exhibit Description+

Form

Date of First
Filing

Exhibit
Number

Filed
Herewith

10.1

Form of Indemnification Agreement.

8-K

09/30/2025

10.1

10.2

Form of Non-Employee Director Compensation Letter.

8-K

09/30/2025

10.2

10.3++

Amendment No. 6 to Amended and Restated Senior Credit Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of August 1, 2025.

8-K

08/01/2025

10.1

10.4++

Amendment No. 7 to Amended and Restated Senior Credit Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of October 24, 2025.

8-K

10/27/2025

10.1

10.5

Fifth Amendment to the Loan Agreement, by and between Phoenix Energy One, LLC, Phoenix Operating, LLC, and Adamantium Capital LLC, dated as of October 6, 2025.

31.1

Certifications of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certifications of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH

XBRL Taxonomy Extension Schema Document.

104

Cover Page Interactive Data File (the cover page XBRL tags)

+	Capitalized terms have the meanings assigned to them in the Report contained in this Quarterly Report.

++	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 SEC upon request.

*	Filed herewith.

**	Furnished herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


				PHOENIX ENERGY ONE, LLC

November 12, 2025				/s/ Curtis Allen
				Curtis Allen
				Chief Financial Officer

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TABLE OF CONTENTS

Part I. Item 1. Financial Statements Note 13 Commitments and Contingencies Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3. Defaults Upon Senior Securities Item 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits

3.1 Certificate of Formation of Phoenix Capital Group Holdings, LLC, dated as of April16, 2019. S-1 10/29/2024 3.1 3.2 Certificate of Amendment to the Certificate of Formation of Phoenix Energy One, LLC, dated as of January23, 2025. S-1/A 03/28/2025 3.2 3.3 Third Amended and Restated Limited Liability Company Agreement of Phoenix Energy One, LLC 8-K 09/30/2025 3.1 3.4 Phoenix Energy One, LLC Share Designation with Respect to the Series A Cumulative Redeemable Preferred Shares 8-K 09/30/2025 3.2 10.1 Form of Indemnification Agreement. 8-K 09/30/2025 10.1 10.2 Form of Non-Employee Director Compensation Letter. 8-K 09/30/2025 10.2 10.3++ Amendment No.6 to Amended and Restated Senior Credit Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of August1, 2025. 8-K 08/01/2025 10.1 10.4++ Amendment No.7 to Amended and Restated Senior Credit Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, each of the lenders from time to time party thereto, and Fortress Credit Corp., dated as of October24, 2025. 8-K 10/27/2025 10.1 10.5 Fifth Amendment to the Loan Agreement, by and between Phoenix Energy One, LLC, Phoenix Operating, LLC, and Adamantium Capital LLC, dated as of October6, 2025. * 31.1 Certifications of Chief Executive Officer Pursuant to Section302 of the Sarbanes-Oxley Act of 2002. * 31.2 Certifications of Chief Financial Officer Pursuant to Section302 of the Sarbanes-Oxley Act of 2002. * 32.1 Certification of Chief Executive Officer Pursuant to Section906 of the Sarbanes-Oxley Act of 2002. * * 32.2 Certification of Chief Financial Officer Pursuant to Section906 of the Sarbanes-Oxley Act of 2002. * *

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