Phoenix Energy (PHXE-P) prospectus supplement adds Q1 2026: $298.7M revenue, $140.1M loss

Rhea-AI Filing Summary

Phoenix Energy One, LLC files a prospectus supplement to its Form S-1 to incorporate selected disclosures from its Quarterly Report on March 31, 2026, including condensed consolidated financial statements and MD&A. The supplement updates the offering materials with the Company’s March 31, 2026 financial results and related notes.

The March 31, 2026 results show $298.7 million of revenues and a $140.1 million net loss, driven principally by a $178.8 million mark-to-market loss on commodity derivatives and increased interest expense. The supplement also discloses liquidity context: $70.2 million cash, $1.70 billion of outstanding debt, and 100,000,000 common shares outstanding as of May 12, 2026.

Insights

Credit & Capital Markets Analyst

Derivative mark-to-market and elevated debt are principal drivers of near-term earnings volatility.

The Company reported a $178.8M loss on commodity derivatives and $52.5M net interest expense for Q1 2026, resulting in a $140.1M net loss. These items, recorded in other expense, materially drove the quarter’s negative EPS.

Liquidity signals include $70.2M cash and $1.70B debt outstanding; management states it raised ~$92.7M of debt post-period and expects to fund significant capex (company estimates $750M–$810M over next 12 months). Subsequent filings will clarify financing plans and covenant status.

Commodities Risk Specialist

Open crude derivatives and non-hedge accounting drive earnings sensitivity to forward oil curves.

The Company discloses extensive crude derivative positions (swaps, collars, long calls) with Level 2 valuations; unrealized losses of $157.8M (component of total derivative loss). Derivatives are not hedge-designated, so mark-to-market flows through earnings.

Key watch items: realized cash settlements vs. unrealized mark movements in later filings, and whether hedging designation or contract revisions are implemented to reduce P&L volatility.

Key Figures

Total revenues: $298,680 Net income (loss): $(140,119) Cash and cash equivalents: $70,173 +4 more

7 metrics

Total revenues $298,680 Three months ended March 31, 2026 (in thousands)

Net income (loss) $(140,119) Net loss for three months ended March 31, 2026 (in thousands)

Cash and cash equivalents $70,173 As of March 31, 2026 (in thousands)

Total outstanding debt $1,702,332 As of March 31, 2026 (in thousands)

Loss on derivatives $(178,753) Three months ended March 31, 2026 (in thousands)

Common shares outstanding 100,000,000 shares As of May 12, 2026

Series A Preferred liquidation preference $67.6M Aggregate liquidation preference as of March 31, 2026

Key Terms

mark-to-market on commodity derivatives, units-of-production depletion, Fortress Credit Agreement, Adjusted EBITDA

4 terms

mark-to-market on commodity derivatives financial

"Loss on derivatives of $(178,753) recorded as unrealized mark-to-market loss"

units-of-production depletion financial

"Property acquisition costs depleted on a units-of-production basis over proved reserves"

Fortress Credit Agreement regulatory

"Senior secured credit agreement amended to provide a $75.0 million term loan"

Adjusted EBITDA financial

"Adjusted EBITDA excludes unrealized gains and losses on open commodity derivative contracts"

Adjusted EBITDA is a way companies measure how much money they make from their core operations, like running a business, by removing certain costs or income that aren’t part of regular business activities. It helps investors see how well a company is doing without distractions from unusual expenses or gains, making it easier to compare companies or track performance over time.

AI-generated analysis. How Rhea-AI works. Not financial advice.

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Accepted by SEC EDGAR 05/13/2026 - 09:48 PM Learn about SEC filing dates

FAQ

What did PHXE-P disclose about Q1 2026 revenue and net income?

PHXE-P reported $298.7 million of revenue for the three months ended March 31, 2026 and a net loss of $140.1 million, driven largely by derivative mark-to-market losses and higher interest expense.

How much cash and total debt did Phoenix Energy report as of March 31, 2026?

The Company reported $70.2 million in cash and $1.702 billion of total outstanding debt as of March 31, 2026 in the condensed consolidated balance sheet.

What was the scale of the Company’s derivative losses disclosed in the supplement?

The supplement shows a $178.8 million loss on derivative instruments for Q1 2026, including an unrealized component of $157.8 million recognized in earnings.

How many common shares were outstanding and who owns them?

As of May 12, 2026, Phoenix Energy reported 100,000,000 common shares outstanding, and all common shares are owned by Phoenix Equity Holdings, LLC.

What liquidity and capital plans did management disclose in the supplement?

Management reported raising approximately $92.7 million of debt after the balance sheet date, expects to fund operations via operating cash flow and debt/equity issuances, and estimated $750M–$810M of capital expenditures over the next 12 months.

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Filed pursuant to Rule 424(b)(3)

SEC File No. 333-282862

PROSPECTUS SUPPLEMENT NO. 1

(To Prospectus dated May 4, 2026)

PHOENIX ENERGY ONE, LLC

This prospectus supplement updates, amends, and supplements the prospectus, dated May 4, 2026 (as updated, amended, and supplemented to date, the “Prospectus”), which forms a part of our Registration Statement on Form S-1 (Registration No. 333-282862). Capitalized terms used in this prospectus supplement and not otherwise defined herein have the meanings specified in the Prospectus.

This prospectus supplement is being filed to update, amend, and supplement the information included in the Prospectus with the information contained in our Quarterly Report on Form 10-Q filed with the SEC on May 13, 2026, which is set forth below.

This prospectus supplement is not complete without the Prospectus. This prospectus supplement should be read in conjunction with the Prospectus, which is to be delivered with this prospectus supplement, and is qualified by reference thereto, except to the extent that the information in this prospectus supplement updates or supersedes the information contained in the Prospectus. Please keep this prospectus supplement with your Prospectus for future reference.

Investing in the Notes involves risks. See “Risk Factors” beginning on page 27 of the Prospectus.

Neither the U.S. Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus supplement or the accompanying Prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus supplement is May 13, 2026.

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2026

OR

☐ 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: 001-42868

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)

Registrant’s telephone number, including area code: (949) 416-5037

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 ☒ No ☐

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.

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 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 ☒

As of May 12, 2026, there were 100,000,000 common shares of the registrant outstanding. All of the registrant’s common shares are owned by Phoenix Equity Holdings, LLC.

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				Page
PART I.		FINANCIAL INFORMATION			5
Item 1.		Financial Statements (Unaudited)			5
		Condensed Consolidated Balance Sheets			5
		Condensed Consolidated Statements of Operations			6
		Condensed Consolidated Statements of Changes in Equity (Deficit)			7
		Condensed Consolidated Statements of Cash Flows			8
		Notes to the Condensed Consolidated Financial Statements			9
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			22
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			34
Item 4.		Controls and Procedures			36
PART II.		OTHER INFORMATION			37
Item 1.		Legal Proceedings			37
Item 1A.		Risk Factors			37
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			37
Item 3.		Defaults Upon Senior Securities			37
Item 4.		Mine Safety Disclosures			37
Item 5.		Other Information			37
Item 6.		Exhibits			45
SIGNATURES					47

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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:

• “2025 Annual Report” means the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2025.

• “Adamantium” means Adamantium Capital LLC, a Delaware limited liability company and a direct, wholly-owned subsidiary of the Company.

• “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 Company under the Adamantium Loan Agreement (as defined below), as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Adamantium Securities.”

• “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 Company and PhoenixOp, as borrowers, and Adamantium, as lender, as the same may be amended and supplemented from time to time, as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Adamantium Securities.”

• “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, as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Adamantium Securities.”

• “Adamantium Securities” means, collectively, indebtedness outstanding under the Adamantium Bonds and Adamantium Secured Note.

• “August 2023 506(c) Bonds” means unsecured bonds offered and sold by the Company pursuant to an offering under Rule 506(c) of Regulation D, as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Reg D/Reg A Bonds and Exchange Notes.”

• “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.

• “December 2022 506(c) Bonds” means unsecured bonds offered and sold by the Company pursuant to an offering under Rule 506(c) of Regulation D, as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Reg D/Reg A Bonds and Exchange Notes.”

• “E&P” means exploration and production.

• “Exchange Act” means the U.S. Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

• “Exchange Notes” means unsecured bonds issued by the Company to holders of the Reg A Bonds in exchange for their Reg A Bonds in offerings exempt from registration under Section 3(a)(9) and/or 4(a)(2) of the Securities Act, as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Reg D/Reg A Bonds and Exchange Notes.”

• “Firebird Marketing” means Firebird Marketing, LLC, a Delaware limited liability company and a direct, wholly-owned subsidiary of the Company.

• “Firebird Services” means Firebird Services, LLC, a Delaware limited liability company and a direct, wholly-owned subsidiary of PhoenixOp.

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• “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 Company, 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, as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Fortress Credit Agreement.”

• “Mcf” means one thousand cubic feet.

• “MMBtu” means one million Btus.

• “NGL” means natural gas liquids.

• “NMAs” means net mineral acres.

• “NRAs” means net royalty acres.

• “NYSE American” means NYSE American LLC.

• “Phoenix Equity” means Phoenix Equity Holdings, LLC, a Delaware limited liability company and the holder of 100% of the common equity interests of the Company.

• “PhoenixOp” means Phoenix Operating LLC, a Delaware limited liability company and a direct, wholly-owned subsidiary of Phoenix Energy.

• “Reg A Bonds” means unsecured bonds offered and sold by the Company pursuant to an offering under Regulation A under the Securities Act, as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Reg D/Reg A Bonds and Exchange Notes.”

• “Reg D Bonds” means, collectively, the Senior Reg D Bonds and the Subordinated Reg D Bonds.

• “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 Company on a continuous basis pursuant to a registration statement on Form S-1 (File No. 333-282862), including the related prospectus, as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Registered Notes.”

• “Regulation A” means Regulation A promulgated under the Securities Act.

• “Regulation D” means Regulation D promulgated under the Securities Act.

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

• “Securities Act” means the U.S. Securities Act of 1933, as amended, and the rules and regulations of the SEC promulgated thereunder.

• “Senior Debt” means any indebtedness that the Company 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 Phoenix Bonds.

• “Senior Reg D Bonds” means unsecured bonds offered and sold by the Company pursuant to an offering under Rule 506(c) of Regulation D, as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Indebtedness—Reg D/Reg A Bonds and Exchange Notes.”

• “Senior Phoenix Bonds” means the Reg D/Reg A Bonds that are not Subordinated Reg D Bonds and the Exchange Notes.

• “Series A Preferred Shares” means the Series A Cumulative Redeemable Preferred Shares offered and sold by the Company pursuant to an offering under Regulation A under the Securities Act, as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Preferred Equity.”

• “Subordinated Reg D Bonds” means, collectively, the August 2023 506(c) Bonds and the December 2022 506(c) Bonds.

• “we,” “us,” “our,” the “Company,” 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.

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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 on 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 our 2025 Annual 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 the section of our 2025 Annual Report entitled “Risk Factors”. 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 of 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;

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• 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;

• geopolitical developments, including armed conflict, political instability, or civil unrest in oil and gas producing regions;

• the prior restatement of our financial statements; and

• the other factors set forth in the section of our 2025 Annual Report entitled “Risk Factors.”

Except as required by law, we are under no duty to, and we do not intend to, update or review any of our forward-looking statements after the date of this 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 the Company, our products and 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.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(in thousands, except share amounts)

		March 31, 2026				December 31, 2025
		(unaudited)
ASSETS
Current assets
Cash and cash equivalents		$	70,173			$	65,791
Accounts receivable			107,304				75,515
Earnest payments			608				240
Current derivative assets			—				26,824
Other current assets			3,590				5,218
Total current assets			181,675				173,588
Property, plant, and equipment
Oil and gas properties			2,160,093				1,921,418
Other property and equipment			4,170				2,913
Less: accumulated depreciation, depletion, and amortization			(378,254	)			(318,095	)
Total property, plant, and equipment, net			1,786,009				1,606,236
Right-of-use assets, net			9,194				9,507
Noncurrent derivative assets			—				16,564
Other noncurrent assets			869				874
TOTAL ASSETS		$	1,977,747			$	1,806,769
LIABILITIES AND EQUITY (DEFICIT)
Current liabilities
Accounts payable		$	104,012			$	122,033
Accrued expenses			52,834				43,438
Current portion of long-term debt			148,666				147,922
Current portion of deferred closings			7,369				9,974
Escrow account			137				5,762
Current operating lease liabilities			1,269				1,256
Current derivative liabilities			112,412				—
Other current liabilities			113,090				88,027
Total current liabilities			539,789				418,412
Long-term debt, net of current portion			1,393,555				1,235,713
Accrued interest			69,027				59,711
Deferred closings			3,276				3,315
Operating lease liabilities			9,339				9,625
Asset retirement obligations			2,102				1,781
Noncurrent derivative liabilities			24,256				—
Total liabilities			2,041,344				1,728,557
Commitments and contingencies (Note 13)
Equity (deficit)
Series A Preferred Shares (2,704,023 shares issued and outstanding at an aggregate liquidation preference of $67.6 million at March 31, 2026 and December 31, 2025, respectively)			48,275				48,106
Common equity			434				434
Retained earnings (accumulated deficit)			(112,306	)			29,672
Total equity (deficit)			(63,597	)			78,212
TOTAL LIABILITIES AND EQUITY (DEFICIT)		$	1,977,747			$	1,806,769

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

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(unaudited)

(in thousands)

		Three Months Ended March 31,
		2026				2025
REVENUES
Product sales		$	181,596			$	84,269
Mineral and royalty revenues			35,705				29,886
Purchased crude oil sales			77,084				—
Water services			4,197				1,503
Other revenue			98				89
Total revenues			298,680				115,747
OPERATING EXPENSES
Cost of sales			56,092				27,083
Depreciation, depletion, and amortization			60,249				31,225
Purchased crude oil expenses			75,600				—
Selling, general, and administrative			4,345				9,514
Payroll and payroll-related			9,363				7,929
Advertising and marketing			369				320
Impairment expense			828				516
Total operating expenses			206,846				76,587
INCOME FROM OPERATIONS			91,834				39,160
OTHER INCOME (EXPENSE)
Interest income			213				689
Interest expense, net			(52,510	)			(35,849	)
Gain (loss) on derivatives			(178,753	)			1,920
Loss on debt extinguishments			(903	)			(321	)
Total other expenses			(231,953	)			(33,561	)
NET INCOME (LOSS)		$	(140,119	)		$	5,599

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

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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				Common Equity				Retained Earnings (Accumulated Deficit)				Total Equity (Deficit)
Balance, December 31, 2025			2,704,023			$	48,106			$	434			$	29,672			$	78,212
Amortization of Series A Preferred Shares discount			—				169				—				(169	)			—
Distributions on Series A Preferred Shares			—				—				—				(1,690	)			(1,690	)
Net loss			—				—				—				(140,119	)			(140,119	)
Balance, March 31, 2026			2,704,023			$	48,275			$	434			$	(112,306	)		$	(63,597	)
Balance, December 31, 2024			—			$	—			$	434			$	(34,492	)		$	(34,058	)
Net income			—				—				—				5,599				5,599
Balance, March 31, 2025			—			$	—			$	434			$	(28,893	)		$	(28,459	)

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

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(unaudited)

(in thousands)

		Three Months Ended March 31,
		2026				2025
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)		$	(140,119	)		$	5,599
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization			60,249				31,225
Equity-based compensation expense			68				—
Amortization of right-of-use assets			313				259
Amortization of debt discount and debt issuance costs			7,380				5,166
Impairment expense			828				516
Write-offs of earnest payments			3				—
Unrealized (gain) loss on derivatives			157,789				(2,823	)
Loss on debt extinguishments			903				321
Changes in operating assets and liabilities:
Accounts receivable			(31,789	)			(16,500	)
Earnest payments			(1,067	)			(10,874	)
Accounts payable			(2,513	)			(1,127	)
Accrued expenses			(5,600	)			(1,875	)
Derivative assets and liabilities, net			22,267				—
Other current liabilities			21,755				11,108
Escrow account			(5,625	)			(9,229	)
Accrued interest			17,600				9,862
Other operating activities			1,359				(3,526	)
Net cash provided by operating activities			103,801				18,102
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties and leases			(238,483	)			(182,252	)
Additions to other property and equipment			(146	)			(109	)
Other investing activities			—				(23	)
Net cash used in investing activities			(238,629	)			(182,384	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuances of debt, net of discount			185,649				105,948
Payments of debt issuance costs			(19,934	)			(14,543	)
Repayments of debt			(20,501	)			(11,104	)
Distributions on Series A Preferred Shares			(1,690	)			—
Payments of deferred closings			(4,314	)			(1,467	)
Net cash provided by financing activities			139,210				78,834
Net change in cash and cash equivalents			4,382				(85,448	)
Cash and cash equivalents at beginning of year			65,791				120,814
Cash and cash equivalents at end of year		$	70,173			$	35,366

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

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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”) is a Delaware limited liability company focused on oil and gas operations and acquisitions 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 as Phoenix Capital Group Holdings, LLC and changed its name 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 take title to oil at or near the wellhead and market production to third-party purchasers. It manages commercial and logistical activities related to the sale of hydrocarbons, including transportation coordination, blending and quality optimization, scheduling, and counterparty negotiations, and assumes market, operational and credit risks related thereto. In return, Firebird Marketing may earn marketing margins based on market conditions and its ability to optimize sales execution.

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, 2025 (the “2025 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 retained earnings.

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 March 31, 2026, the Company had negative working capital of approximately $358.0 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 $92.7 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.

The Company may need to conduct asset sales, which is not a planned course of action, and/or issue debt or equity securities if liquidity risk increases in any given period. The Company believes it has sufficient funds to meet foreseeable obligations by actively monitoring its credit facilities through use of the loans, asset sales, cost reductions and coordinating payment and revenue cycles.

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(unaudited)

The Company is required to evaluate whether or not its current financial condition, including its sources of liquidity at the date that the condensed consolidated financial statements are issued, will enable the Company to meet its obligations as they come due within one year of the date of the issuance of these condensed consolidated financial statements and to make a determination as to whether or not it is probable, under the application of this accounting guidance, that the Company will be able to continue as a going concern. In applying applicable accounting guidance, we considered the Company’s current financial condition and liquidity sources, including current funds available, forecasted future cash flows, the Company’s obligations due over the next twelve months as well as the Company’s recurring business operating expenses, and believe that the Company has sufficient financial resources to operate beyond the next twelve months following the date these condensed consolidated financial statements are issued.

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 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.

Inventory

Crude oil in storage tanks that has not yet been sold is classified as inventory and recorded within other current assets on the Company’s condensed consolidated balance sheets. Inventory is stated at the lower of cost and net realizable value, with cost determined using a weighted average cost method, and includes costs incurred to bring the inventory to its present location and condition.

Recent accounting standards not yet adopted

In November 2024, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2024-03, Income Statement—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses (“ASU 2024-03”). ASU 2024-03 requires disclosure in the Company’s annual and interim consolidated financial statements of specified information about certain costs and expenses, including depletion, depreciation, and amortization recognized as part of crude oil and natural gas producing activities, cost of sales, selling, general, and administrative expenses, and employee compensation. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027. Early adoption is permitted. ASU 2024-03 can be applied prospectively or retrospectively at the Company’s election. The Company is currently evaluating the impact of the standard on its financial statements and disclosures and its plans for adoption, including the transition method and adoption date.

In December 2025, the FASB issued ASU 2025-11, Interim Reporting (Topic 270): Narrow-Scope Improvements (“ASU 2025-11”). ASU 2025-11 clarifies interim disclosure requirements and provides a comprehensive list of required interim disclosures. The update also incorporates a disclosure principle that requires entities to disclose events that occur after the end of the last annual reporting period. This update is effective for interim periods within annual periods beginning after December 15, 2027. Early adoption is permitted. 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.

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(unaudited)

Note 3. Property, Plant, and Equipment

The following table summarizes the Company’s property, plant, and equipment, net as of the dates presented:

(in thousands)		March 31, 2026				December 31, 2025
Proved oil and natural gas properties(a)		$	1,735,851			$	1,404,034
Unproved oil and natural gas properties			424,242				517,384
Total oil and gas properties			2,160,093				1,921,418
Other property and equipment			4,170				2,913
Less: accumulated depreciation, depletion, and amortization			(378,254	)			(318,095	)
Total property, plant, and equipment, net		$	1,786,009			$	1,606,236

(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 $60.0 million and $31.3 million for the three months ended March 31, 2026 and 2025, respectively.

Depreciation expense on the Company’s equipment and other property was $0.1 million and less than $0.1 million for the three months ended March 31, 2026 and 2025, respectively.

Impairment expense on the Company’s oil and gas properties was $0.8 million and $0.5 million for the three months ended March 31, 2026 and 2025, 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 March 31, 2026
(in thousands)		Operating				Mineral and Non-operating				Securities				Eliminations				Total
Product sales
Crude oil		$	174,699			$	—			$	—			$	—			$	174,699
Natural gas			2,593				—				—				—				2,593
NGL			4,304				—				—				—				4,304
Total product sales			181,596				—				—				—				181,596
Mineral and royalty revenues
Crude oil			—				31,635				—				180				31,815
Natural gas			—				2,190				—				—				2,190
NGL			—				1,700				—				—				1,700
Total mineral and royalty revenues			—				35,525				—				180				35,705
Purchased crude oil sales			77,264				—				—				(180	)			77,084
Water services			4,197				—				—				—				4,197
Other revenue			—				—				98				—				98
Intersegment revenue			—				291				43,521				(43,812	)			—
Total revenues		$	263,057			$	35,816			$	43,619			$	(43,812	)		$	298,680

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(unaudited)

		Three Months Ended March 31, 2025
(in thousands)		Operating				Mineral and Non-operating				Securities				Eliminations				Total
Product sales
Crude oil		$	83,202			$	—			$	—			$	—			$	83,202
Natural gas			428				—				—				—				428
NGL			639				—				—				—				639
Total product sales			84,269				—				—				—				84,269
Mineral and royalty revenues
Crude oil			—				26,263				—				—				26,263
Natural gas			—				1,803				—				—				1,803
NGL			—				1,820				—				—				1,820
Total mineral and royalty revenues			—				29,886				—				—				29,886
Water services			1,503				—				—				—				1,503
Other revenue			—				—				89				—				89
Intersegment revenue			—				38				29,752				(29,790	)			—
Total revenues		$	85,772			$	29,924			$	29,841			$	(29,790	)		$	115,747

Note 5. Other Current Assets

The following table summarizes the Company’s other current assets as of the dates presented:

(in thousands)		March 31, 2026				December 31, 2025
Prepaid expenses			2,142				4,110
Inventory			1,331				—
Deposits			117				112
Other			—				996
Total		$	3,590			$	5,218

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.

The Company may enter into crude oil derivative contracts, including collars, fixed-price swaps, put options and call options, to hedge a portion of its anticipated future production and reduce exposure to commodity price volatility. Collars establish both a floor and a ceiling price on contracted volumes, allowing the Company to receive payments if index prices fall below the floor, while requiring payments if index prices exceed the ceiling. Fixed-price swaps establish a fixed price for contracted volumes, resulting in payments to the Company when the index price is below the fixed price and payments by the Company when the index price exceeds the fixed price. Long call options provide the Company with the right to purchase crude oil at a specified strike price and are used to provide price protection in rising commodity price environments in exchange for the payment of an option premium. As of March 31, 2026, 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; therefore, changes in the fair value of these instruments, as well as cash settlements, are recognized in earnings in the period incurred. All derivative contracts are recorded at fair value on the condensed consolidated balance sheets as assets or liabilities and are presented on a net basis when a legally enforceable master netting arrangement exists with the counterparty.

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(unaudited)

As of March 31, 2026, the Company’s open crude oil derivative contracts consisted of the following:

		Settlement Period
(volumes in Bbl and prices in $/Bbl)		2026				2027				2028
Two-Way Collars
Notional Volumes			261,000				259,000				—
Weighted Average Ceiling Price		$	71.69			$	69.86			$	—
Weighted Average Floor Price		$	56.01			$	54.76			$	—
Swaps
Notional Volumes			4,727,578				3,782,455				2,827,866
Weighted Average Contract Price		$	61.57			$	60.93			$	60.26
Long Calls
Notional Volumes			870,000				3,037,830				855,600
Strike Price(a)		$	75.00			$	75.00			$	75.00

(a) Excludes a weighted average option premium of $3.31/Bbl, $5.41/Bbl and $3.31/Bbl for the settlement periods ending December 31, 2026, 2027 and 2028, respectively.

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 on the condensed consolidated statements of cash flows.

		Three Months Ended March 31,
(in thousands)		2026				2025
Gain (loss) on derivative instruments		$	(178,753	)		$	1,920
Net cash receipts (payments) on derivatives			1,303				(903	)

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.

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 March 31, 2026 and December 31, 2025. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.

						March 31, 2026
(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			Current derivative assets			$	—			$	18,482			$	—			$	18,482			$	(18,482	)		$	—
Commodity derivatives			Noncurrent derivative assets				—				17,943				—				17,943				(17,943	)			—
Total assets						$	—			$	36,425			$	—			$	36,425			$	(36,425	)		$	—
Liabilities
Commodity derivatives			Current derivative liabilities			$	—			$	(130,894	)		$	—			$	(130,894	)		$	18,482			$	(112,412	)
Commodity derivatives			Noncurrent derivative liabilities				—				(42,199	)			—				(42,199	)			17,943				(24,256	)
Total liabilities						$	—			$	(173,093	)		$	—			$	(173,093	)		$	36,425			$	(136,668	)

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(unaudited)

						December 31, 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			Current derivative assets			$	—			$	27,117			$	—			$	27,117			$	(293	)		$	26,824
Commodity derivatives			Noncurrent derivative assets				—				17,270				—				17,270				(706	)			16,564
Total assets						$	—			$	44,387			$	—			$	44,387			$	(999	)		$	43,388
Liabilities
Commodity derivatives			Current derivative liabilities			$	—			$	(293	)		$	—			$	(293	)		$	293			$	—
Commodity derivatives			Noncurrent derivative liabilities				—				(706	)			—				(706	)			706				—
Total liabilities						$	—			$	(999	)		$	—			$	(999	)		$	999			$	—

Note 7. Debt

The following table summarizes the Company’s long-term debt as of the dates presented:

		Maturity Date
(in thousands)		Earliest Date				Latest Date				Interest Rate(a)				March 31, 2026				December 31, 2025
Fortress Term Loans			—				10/27/2028				Term SOFR + 7.10	%		$	525,000			$	450,000
Unregistered Debt Offerings
Regulation D Bonds			4/10/2026				3/10/2037				9.0% to 14.0%				765,579				710,697
Adamantium Securities			6/10/2029				3/10/2037				13.0% to 16.5%				287,332				253,331
Regulation A Bonds			4/10/2026				8/10/2027				9.0%				33,783				50,166
Exchange Notes			12/10/2027				3/10/2037				9.0% to 12.0%				35,540				31,017
Total unregistered debt offerings															1,122,234				1,045,211
Registered Notes			5/10/2028				3/10/2037				9.0% to 12.0%				55,098				34,679
Total outstanding debt															1,702,332				1,529,890
Less: Unamortized debt discount and issuance costs(b)															(160,111	)			(146,255	)
Less: Current portion of long-term debt															(148,666	)			(147,922	)
Total long-term debt, net of current portion														$	1,393,555			$	1,235,713

(a) Represents the contractual interest rate as of March 31, 2026.

(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 debt offerings are classified as loss on debt extinguishments on the condensed consolidated statements of operations.

Fortress Credit Agreement

In August 2024, the Company entered into a senior secured credit agreement with Fortress Credit Corp. (the “Fortress Credit Agreement”) as lender and administrative agent, which was subsequently amended to add additional term loan tranches and syndicated to include an additional institutional lender. In February 2026, the Fortress Credit Agreement was further amended to provide a $75.0 million term loan funded at closing and up to $225.0 million available on a discretionary basis. 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 all-in interest rate for the Fortress Term Loans was 10.8% and 11.1% at March 31, 2026 and December 31, 2025, 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.

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(unaudited)

On May 7, 2026, subsequent to the balance sheet date, the Company obtained a waiver of noncompliance with its current ratio covenant as of March 31, 2026, which resulted primarily from the timing of accelerated well completion expenditures undertaken to capitalize on higher commodity prices.

Unregistered Debt Offerings

Regulation D Bonds

In March 2026, the Company approved an increase to the maximum offering amount of the August 2023 506(c) Bonds from $1.5 billion to $2.0 billion. 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.

Adamantium Securities

In March 2026, the Company amended the Adamantium Loan Agreement to increase the amount available to borrow under the agreement from $409.3 million to $609.3 million. Correspondingly, the offering amount of Adamantium Bonds being offered by Adamantium was also increased from $400.0 million to $600.0 million, and the Adamantium Secured Note from $8.6 million to $9.3 million (collectively, the “Adamantium Securities”). The Adamantium Securities have maturity terms that range from five to eleven years and bear interest ranging from 13.0% to 16.5% per annum.

Interest Expense on Debt

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

		Three Months Ended March 31,
(in thousands)		2026				2025
Stated interest		$	51,082			$	33,008
Amortization of debt discount and debt issuance costs			7,380				5,166
Total interest cost			58,462				38,174
Capitalized interest			(5,952	)			(2,325	)
Total interest expense, net		$	52,510			$	35,849

Note 8. Other Current Liabilities

The following table summarizes the Company’s other current liabilities as of the dates presented:

(in thousands)		March 31, 2026				December 31, 2025
Revenue payables		$	64,117			$	50,642
Advances from joint interest partners			19,061				17,116
Production taxes payable			16,458				10,939
Accrued interest			5,359				5,033
Unredeemed matured bonds			4,185				1,542
Dividends payable			1,465				1,465
Asset retirement obligations			910				540
Other			1,535				750
Total		$	113,090			$	88,027

Note 9. Preferred Equity

In September 2025, the Company completed its offering of the Series A Preferred Shares, 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. In addition, at issuance, the Company recorded a $2.4 million discount associated with the stepped distribution rate feature of the Series A Preferred Shares, which provides for increases in the distribution rate prior to the commencement of the 11.0% perpetual distribution rate in year five. For the three months ended March 31, 2026, $0.2 million of this discount was amortized.

During the three months ended March 31, 2026, the Company paid $1.7 million of distributions to the holders of the Series A Preferred Shares equal to $0.625 per share. In March 2026, the Company’s Board of Directors authorized and declared a distribution on the Series A Preferred Shares equal to $0.625 per share, which was paid on April 15, 2026, to holders of record as of April 1, 2026, and totaled $1.7 million. As of March 31, 2026, the Company had accrued $1.5 million of dividends payable, which is included in other current liabilities on the condensed consolidated balance sheet.

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(unaudited)

Note 10. Equity-Based Compensation

The Company’s parent, Phoenix Equity, has granted equity awards to employees and non-employee service providers of the Company under the 2024 Long-Term Incentive Plan (the “2024 Incentive Plan”).

A summary of the activity under the 2024 Incentive Plan for the three months ended March 31, 2026 is presented below:

		Number of Units				Weighted Average Per Share Grant Date Fair Value
Nonvested at December 31, 2025			2,949,435
Granted—Class A Units			—				—
Granted—Class B Units			—				—
Granted—Phantom Units			15,000			$	65.10
Vested			(999	)		$	63.66
Forfeited			—				—
Nonvested at March 31, 2026			2,963,436

The Phantom Unit awards granted to employees are subject to both a performance condition and a service condition, each of which must be satisfied for the awards to vest. The performance condition requires the occurrence of an exit event (e.g., change in control) by the Company. No compensation cost will be recognized for the employee Phantom Unit awards unless and until the occurrence of such an exit event is deemed probable. As of March 31, 2026, the Company determined that the occurrence of a change in control event was not probable, and accordingly, no equity-based compensation expense was recognized in connection with these awards for the three months ended March 31, 2026. The Phantom Unit awards granted to the non-employee service provider vest partially upon the grant date, with the remaining portion subject to a monthly vesting schedule based on a service condition. The Company recognized $0.1 million of equity-based compensation expense in connection with the Phantom Unit awards granted to the non-employee service provider for the three months ended March 31, 2026, which is included in selling, general, and administrative expenses on the condensed consolidated statement of operations. The related liability is presented within other current liabilities in the accompanying condensed consolidated balance sheet.

As of March 31, 2026 and December 31, 2025, there was $194.4 million and $193.4 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 three months ended March 31, 2026 are presented in the table below:

		March 31, 2026
Dividend yield(a)			—	%
Risk-free interest rate(b)			3.73	%
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.

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(unaudited)

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 three months ended March 31, 2026 and 2025, these officers and their family members purchased, in aggregate, 201 and 1,104 of the combined Regulation A Bonds, Regulation D and Adamantium Bonds for a total purchase price of $0.2 million and $1.1 million, respectively. As of March 31, 2026 and December 31, 2025, there were 6,489 and 6,288 of bonds outstanding with carrying values of $6.5 million and $6.3 million, respectively. Interest expense attributable to these securities was $0.2 million and less than $0.1 million for the three months ended March 31, 2026 and 2025, respectively.

Lion of Judah

The Company paid interest expense to a financial institution on behalf of Lion of Judah Capital LLC (“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 March 31, 2026 and 2025. Interest payments made by the Company on behalf of Lion of Judah are discretionary in nature.

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				March 31, 2026				December 31, 2025
Right-of-use assets – operating			Right-of-use assets, net			$	9,194			$	9,507
Total right-of-use assets						$	9,194			$	9,507
Current operating lease liabilities			Current operating lease liabilities			$	1,269			$	1,256
Noncurrent operating lease liabilities			Operating lease liabilities				9,339				9,625
Total lease liabilities						$	10,608			$	10,881

Operating lease cost of $0.8 million and $0.6 million for the three months ended March 31, 2026 and 2025, respectively, was classified as a component of selling, general, and administrative expenses 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 has entered into drilling rig contracts to procure drilling services for wells operated by PhoenixOp. The contracts are short-term and provide a daily operating rate as consideration for services performed by the third-party provider. As of March 31, 2026, the Company was subject to $0.2 million of commitments under these contracts.

Natural Gas Processing Contracts

The Company has entered into contracts for mobile cryogenic gas processing units to process raw gas, produce and store NGL, 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 March 31, 2026, the Company was subject to $5.7 million of commitments under these contracts.

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(unaudited)

Generator Contracts

The Company has entered into contracts with a third-party provider to supply generators used to provide power at wells operated by PhoenixOp. The contracts range from 12 months to 24 months and require monthly service payments for power generation and related equipment. As of March 31, 2026, the Company had approximately $10.0 million of remaining commitments under these contracts.

Saltwater Disposal Pump Contracts

The Company has entered into contracts for pumps which are used to inject produced water and flowback into its saltwater disposal facilities on wells for which PhoenixOp serves as the operator. The contracts provide for monthly payments and have terms of twelve months or less. As of March 31, 2026, the Company had approximately $1.4 million of remaining commitments under these contracts.

Delivery Commitments

PhoenixOp is subject to arrangements pursuant to which it has committed to deliver barrels of crude oil to a purchaser through 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 its 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. The Company delivered 0.2 million barrels of crude oil during the three months ended March 31, 2026, and the remaining aggregate commitment under the contract as of March 31, 2026 is approximately 1.0 million barrels of crude oil.

Note 14. Supplemental Cash Flow Information

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

		Three Months Ended March 31,
(in thousands)		2026				2025
Supplemental disclosure of cash flow information:
Cash interest paid, net of capitalized interest		$	27,530			$	19,930
Cash paid for operating leases			563				372
Supplemental disclosure of non-cash transactions:
Capital expenditures in accounts payable and accrued expenses		$	122,654			$	69,492
Unpaid property acquisition costs in deferred closings			1,444				1,704
Distributions declared but unpaid on Series A Preferred Shares			1,465				—
Accretion of Series A Preferred Shares discount			169				—
Right-of-use asset obtained in exchange for lease liability			—				2,195
Modification of right-of-use asset and lease liability			—				1,985

Note 15. Segments

Segment operating profit is used as a performance metric by the CODM in determining how to allocate resources and assess performance as this measure provides insight into the segments’ operations and overall success of a segment for a given period. Segment operating profit is calculated as total segment revenue less operating costs attributable to the segment, which includes allocated corporate costs that are overhead in nature and not directly associated with the segments, such as certain general and administrative expenses, executive or shared-function payroll costs and certain limited marketing activities. Corporate costs are allocated to the segments based on usage and headcount, as appropriate. Segment operating profit excludes other income and expense, such as interest expense, interest income, gain (loss) on derivatives, loss on debt extinguishments, even though these amounts are allocated to the segments and provided to the CODM. Transactions between segments are accounted for on an accrual basis and are eliminated upon consolidation. Interest expense is allocated to the segments based on the carrying value of the oil and gas properties owned by the respective segment at the balance sheet date, and interest income and gain (loss) on derivatives are allocated using the same basis as corporate costs.

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

		Three Months Ended March 31,
(in thousands)		2026				2025
Segment operating profit
Operating		$	86,839			$	36,257
Mineral and Non-operating			9,335				7,658
Securities			39,181				24,997
Eliminations			(43,521	)			(29,752	)
Total segment operating profit			91,834				39,160
Interest income			213				689
Interest expense			(52,510	)			(35,849	)
Gain (loss) on derivatives			(178,753	)			1,920
Loss on debt extinguishments			(903	)			(321	)
Net income (loss)		$	(140,119	)		$	5,599

The following tables present financial information by segment as of March 31, 2026 and December 31, 2025, and for the three months ended March 31, 2026 and 2025:

		Three Months Ended March 31,
(in thousands)		2026				2025
Significant expenses
Operating
Cost of sales		$	49,632			$	22,539
Depreciation, depletion, and amortization			47,287				22,960
Purchased crude oil expenses			75,600				—
Selling, general, and administrative			(303	)			1,997
Payroll and payroll-related			3,849				2,019
Other segment item(a)			153				—
Mineral and Non-operating
Cost of sales		$	6,751			$	4,582
Depreciation, depletion, and amortization			12,962				8,265
Selling, general, and administrative			2,924				4,944
Payroll and payroll-related			2,867				3,959
Other segment items(b)			977				516
Securities
Selling, general, and administrative		$	1,724			$	2,573
Payroll and payroll-related			2,647				1,951
Advertising and marketing			67				320
Interest expense
Operating		$	26,100			$	12,559
Mineral and Non-operating			26,410				23,290
Securities			43,521				29,752
Eliminations			(43,521	)			(29,752	)
Total interest expense, net		$	52,510			$	35,849
Capital expenditures
Operating		$	210,274			$	96,150
Mineral and Non-operating			44,651				89,428
Eliminations			(16,296	)			(3,194	)
Total capital expenditures		$	238,629			$	182,384

(a) Other segment item includes advertising and marketing expense.

(b) Other segment items include advertising and marketing expense and impairment expense.

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(unaudited)

(in thousands)		March 31, 2026				December 31, 2025
Assets
Operating		$	1,058,011			$	892,224
Mineral and Non-operating			1,405,632				1,342,251
Securities			302,749				272,391
Eliminations			(788,645	)			(700,097	)
Total assets		$	1,977,747			$	1,806,769

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

		March 31, 2026
(in thousands)		Operating				Mineral and Non-operating				Securities				Eliminations				Consolidated Total
Oil and natural gas properties, proved
Williston Basin		$	1,189,737			$	329,514			$	—			$	—			$	1,519,251
Powder River Basin			—				58,760				—				—				58,760
Denver-Julesburg			—				58,200				—				—				58,200
Permian Basin			—				25,808				—				—				25,808
Marcellus			—				1,306				—				—				1,306
Uinta Basin			—				70,133				—				—				70,133
Other			—				2,393				—				—				2,393
Total proved properties		$	1,189,737			$	546,114			$	—			$	—			$	1,735,851
Oil and natural gas properties, unproved
Williston Basin		$	2,344			$	346,641			$	—			$	—			$	348,985
Powder River Basin			—				35,113				—				—				35,113
Denver-Julesburg			—				20,407				—				—				20,407
Permian Basin			—				1,245				—				—				1,245
Uinta Basin			—				17,123				—				—				17,123
Other			—				1,369				—				—				1,369
Total unproved properties		$	2,344			$	421,898			$	—			$	—			$	424,242

		December 31, 2025
(in thousands)		Operating				Mineral and Non-operating				Securities				Eliminations				Consolidated Total
Oil and natural gas properties, proved
Williston Basin		$	993,215			$	245,463			$	—			$	—			$	1,238,678
Powder River Basin			—				52,623				—				—				52,623
Denver-Julesburg			—				47,060				—				—				47,060
Permian Basin			—				20,429				—				—				20,429
Marcellus			—				1,306				—				—				1,306
Uinta Basin			—				42,247				—				—				42,247
Other			—				1,691				—				—				1,691
Total proved properties		$	993,215			$	410,819			$	—			$	—			$	1,404,034
Oil and natural gas properties, unproved
Williston Basin		$	7,433			$	386,492			$	—			$	—			$	393,925
Powder River Basin			—				36,084				—				—				36,084
Denver-Julesburg			—				34,857				—				—				34,857
Permian Basin			—				6,679				—				—				6,679
Uinta Basin			—				43,768				—				—				43,768
Other			—				2,071				—				—				2,071
Total unproved properties		$	7,433			$	509,951			$	—			$	—			$	517,384

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PHOENIX ENERGY ONE, LLC AND SUBSIDIARIES

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Note 16. Subsequent Events

Management has evaluated subsequent events through May 13, 2026, in connection with the preparation of these condensed consolidated financial statements, which is the date the condensed consolidated financial statements were available to be issued. The Company has determined that there were no material such events that warrant disclosure or recognition on the condensed consolidated financial statements, except for the following:

In April 2026, the Company paid cash distributions totaling $1.7 million to holders of its Series A Preferred Shares, pursuant to distributions declared by the Company’s Board of Directors in March 2026.

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 $92.7 million of debt securities under these offerings.

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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 condensed consolidated financial statements and the 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 2025 Annual Report. 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 the section of our Quarterly Report entitled “Cautionary Statement Regarding Forward-Looking Statements,” in the section of our 2025 Annual Report entitled “Risk Factors,” and elsewhere in this Quarterly Report and in our 2025 Annual 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 and the Powder River and Denver-Julesburg Basins in Wyoming. Our royalty and working interest acquisitions center around a variety of assets, including mineral interests, leasehold interests, overriding royalty interests, and perpetual royalty interests. These efforts have historically targeted assets in the Williston, Permian, Powder River, Uinta, and Denver-Julesburg Basins. We are agnostic as to geography and prioritize operational and asset potential when executing on our strategy.

Our Segments

We operate under three segments: Operating; Mineral and Non-operating; and Securities. Our Operating segment comprises our operations related to our drilling, extraction, and production activities, which today are conducted through PhoenixOp and its wholly-owned subsidiary, Firebird Services. The sale and marketing of our operated production are conducted through Firebird Marketing. 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 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.

First Quarter 2026 Financial and Operational Highlights

• In February 2026, the Fortress Credit Agreement was amended to provide for a new $75.0 million facility under the discretionary commitments established by the October 2025 Amendment, reducing the commitments available on a discretionary basis from $300.0 million to $225.0 million.

• In March 2026, we produced 1.23 million Bbls of crude oil, representing our highest monthly production volume to date.

• We increased completion activity by ramping operations to three active hydraulic fracturing crews to capitalize on favorable commodity pricing and support accelerated development activity.

• We disposed of approximately 11.5 million Bbls of produced water through our own saltwater disposal wells during the period, with approximately 98.6% of total produced water volumes handled internally through our operated facilities.

• We rig released 22 wells, hydraulically fractured 11 wells and placed 22 wells on production. In addition, we placed three saltwater disposal wells on production.

• We completed six drillouts in six days on the Charlene Ferrari 9 pad.

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Results of Operations for the Three Months Ended March 31, 2026 Compared to the Three Months Ended March 31, 2025

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

		Three Months Ended March 31,								Change
(in thousands)		2026				2025				$				%
Revenues
Product sales		$	181,596			$	84,269			$	97,327				115.5	%
Mineral and royalty revenues			35,705				29,886				5,819				19.5	%
Purchased crude oil sales			77,084				—				77,084				NM
Water services			4,197				1,503				2,694				179.2	%
Other revenue			98				89				9				10.1	%
Total revenues			298,680				115,747				182,933				158.0	%
Operating expenses
Cost of sales			56,092				27,083				29,009				107.1	%
Depreciation, depletion, and amortization			60,249				31,225				29,024				93.0	%
Purchased crude oil expenses			75,600				—				75,600				NM
Selling, general, and administrative			4,345				9,514				(5,169	)			(54.3	)%
Payroll and payroll-related			9,363				7,929				1,434				18.1	%
Advertising and marketing			369				320				49				15.3	%
Impairment expense			828				516				312				60.5	%
Total operating expenses			206,846				76,587				130,259				170.1	%
Income from operations			91,834				39,160				52,674				134.5	%
Other income (expenses)
Interest income			213				689				(476	)			(69.1	)%
Interest expense, net			(52,510	)			(35,849	)			(16,661	)			(46.5	)%
Gain (loss) on derivatives			(178,753	)			1,920				(180,673	)			(9,410.1	)%
Loss on debt extinguishments			(903	)			(321	)			(582	)			(181.3	)%
Total other expenses			(231,953	)			(33,561	)			(198,392	)			(591.1	)%
Net income (loss)		$	(140,119	)		$	5,599			$	(145,718	)			(2,602.6	)%

NM – not meaningful.

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

		Three Months Ended March 31, 2026
(in thousands)		Operating				Mineral and Non-operating				Securities				Eliminations				Total
Total revenues		$	263,057			$	35,816			$	43,619			$	(43,812	)		$	298,680
Total operating expenses			(176,218	)			(26,481	)			(4,438	)			291				(206,846	)
Segment operating profit		$	86,839			$	9,335			$	39,181			$	(43,521	)		$	91,834

		Three Months Ended March 31, 2025
(in thousands)		Operating				Mineral and Non-operating				Securities				Eliminations				Total
Total revenues		$	85,772			$	29,924			$	29,841			$	(29,790	)		$	115,747
Total operating expenses			(49,515	)			(22,266	)			(4,844	)			38				(76,587	)
Segment operating profit		$	36,257			$	7,658			$	24,997			$	(29,752	)		$	39,160

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

		Three Months Ended March 31,								Change
		2026				2025				$				%
Production Data:
Crude oil (Bbl)			2,916,301				1,552,609				1,363,692				87.8	%
Natural gas (Mcf)			1,306,171				712,492				593,679				83.3	%
NGL (Bbl)			283,870				87,962				195,908				222.7	%
Total (Boe)(6:1)			3,417,866				1,759,320				1,658,546				94.3	%
Average daily production (Boe/d) (6:1)			37,976				19,548				18,428				94.3	%
Average Realized Prices(a):
Crude oil (Bbl)		$	70.81			$	70.50			$	0.31				0.4	%
Natural gas (Mcf)		$	3.66			$	3.13			$	0.53				16.9	%
NGL (Bbl)		$	21.15			$	27.95			$	(6.80	)			(24.3	%)

(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 March 31,								Change
(in thousands)		2026				2025				$				%
Product sales
Crude oil		$	174,699			$	83,202			$	91,497				110.0	%
Natural gas			2,593				428				2,165				505.8	%
NGL			4,304				639				3,665				573.6	%
Total product sales			181,596				84,269				97,327				115.5	%
Mineral and royalty revenues
Crude oil			31,815				26,263				5,552				21.1	%
Natural gas			2,190				1,803				387				21.5	%
NGL			1,700				1,820				(120	)			(6.6	%)
Total mineral and royalty revenues			35,705				29,886				5,819				19.5	%
Purchased crude oil sales			77,084				—				77,084				NM
Water services			4,197				1,503				2,694				179.2	%
Other revenue			98				89				9				10.1	%
Total revenues		$	298,680			$	115,747			$	182,933				158.0	%

NM – not meaningful.

Revenue was $298.7 million for the three months ended March 31, 2026, as compared to $115.7 million for the same period in 2025, an increase of $183.0 million, or 158.2%. The increase was primarily attributable to a $97.3 million increase in product sales generated from our direct drilling, extraction, and related oil and gas operating activities, $77.1 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, a $5.8 million increase in mineral and royalty revenues generated from our mineral and non-operating activities, and a $2.7 million increase in revenue from water disposal services.

Operating Segment

Operating segment revenue was $263.1 million for the three months ended March 31, 2026, as compared to $85.8 million for the same period in 2025, an increase of $177.3 million, or 206.6%. The increase was primarily attributable to a $97.3 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 121 producing wells in service as of March 31, 2026, as compared to 37 producing wells in service as of March 31, 2025, $77.1 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 $2.7 million increase in revenue from water disposal services driven by higher disposal volumes, with 11.5 million barrels of saltwater disposed by Firebird Services during the three months ended March 31, 2026, as compared to 4.2 million barrels during the same period in 2025, and a 2.1% increase in average realized price from $71.33/Bbl to $72.81/Bbl for crude oil in 2026 as compared to the same period in 2025.

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Mineral and Non-operating Segment

Mineral and non-operating segment revenue was $35.8 million for the three months ended March 31, 2026, as compared to $29.9 million for the same period in 2025, an increase of $5.9 million, or 19.7%. The increase in segment revenue was primarily driven by increased revenues from crude oil due to a 33.8% increase in production volumes and increased revenues from natural gas due to a 6.4% increase in production volumes and a 14.3% increase in the average realized price for natural gas from $2.79/Mcf for the three months ended March 31, 2025 to $3.19/Mcf for the three months ended March 31, 2026.

Operating Expenses

Cost of Sales

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

		Three Months Ended March 31,								Change
(in thousands)		2026				2025				$				%
Cost of sales
Production costs		$	21,629			$	9,000			$	12,629				140.3	%
Production taxes			18,681				10,206				8,475				83.0	%
Lease operating expenses			15,782				7,877				7,905				100.4	%
Total		$	56,092			$	27,083			$	29,009				107.1	%

Cost of sales was $56.1 million for the three months ended March 31, 2026, as compared to $27.1 million for the same period in 2025, an increase of $29.0 million, or 107.0%. The increase was primarily driven by increased drilling, extraction, and related oil and gas operating activities associated with wells operated by PhoenixOp, and an increase in cost of sales due to higher lease operating expense and severance taxes resulting from increased crude oil production volumes from our acquisitions of mineral and non-operated working interests during the three months ended March 31, 2026 as compared to the same period in 2025.

Operating Segment

Operating segment cost of sales was $49.6 million for the three months ended March 31, 2026, as compared to $22.5 million for the same period in 2025, an increase of $27.1 million, or 120.4%. The increase in segment cost of sales was driven by additional wells placed into service, of which there were 121 producing wells as of March 31, 2026, as compared to 37 producing wells in service as of March 31, 2025, resulting in increased lease operating expenses, production costs, and production and ad valorem taxes during the three months ended March 31, 2026 as compared to the same period in 2025.

Mineral and Non-operating Segment

Mineral and non-operating segment cost of sales was $6.8 million for the three months ended March 31, 2026, as compared to $4.6 million for the same period in 2025, an increase of $2.2 million, or 47.8%. The increase in segment cost of sales was primarily attributable to higher lease operating expense and severance taxes resulting from a 33.8% increase in crude oil production volumes from our acquisitions of mineral and non-operated working interests during three months ended March 31, 2026 as compared to the same period in 2025.

Depreciation, Depletion, and Amortization Expense

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

		Three Months Ended March 31,								Change
(in thousands)		2026				2025				$				%
Depreciation, depletion, and amortization
Depletion		$	60,033			$	31,258			$	28,775				92.1	%
Depreciation			57				5				52				1,040.0	%
Amortization			70				—				70				NM
Accretion on asset retirement obligations			89				(38	)			127				334.2	%
Total		$	60,249			$	31,225			$	29,024				93.0	%

NM – not meaningful.

Depreciation, depletion, and amortization expense was $60.2 million for the three months ended March 31, 2026, as compared to $31.2 million for the same period in 2025, an increase of $29.0 million, or 92.9%, primarily due to a $24.3 million increase in depletion expense within the operating segment driven by increases in our depletable cost bases and a $4.7 million increase in depletion expense within the mineral and non-operating segment, primarily due to a higher depletion rate driven by increased realized production volumes, and increases in the depletable cost bases.

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Operating Segment

Depreciation, depletion, and amortization expense for the operating segment was $47.3 million for the three months ended March 31, 2026, as compared to $23.0 million for the same period in 2025, an increase of $24.3 million, or 105.7%, primarily due to an increase in depletion expense from increases in the depletable cost bases, partially offset by a lower depletion rate during the three months ended March 31, 2026 as compared to the same period in 2025. The lower depletion rate is primarily attributable to significant growth in proved reserves due to drilling activity by PhoenixOp.

Mineral and Non-operating Segment

Depreciation, depletion, and amortization expense for the mineral and non-operating segment was $13.0 million for the three months ended March 31, 2026, as compared to $8.3 million for the same period in 2025, an increase of $4.7 million, or 56.6%. On a per unit basis, depletion expense was $17.66 per Boe and $14.86 per Boe for the three months ended March 31, 2026 and 2025, respectively, an increase of $2.80 per Boe, driven by a higher depletion rate, primarily due to increased realized production volumes, and increases in the depletable cost bases.

Purchased Crude Oil Expense

Purchased crude oil expense was $75.6 million for the three months ended March 31, 2026, with no comparable activity for the same period in 2025. 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 $4.3 million for the three months ended March 31, 2026, as compared to $9.5 million for the same period in 2025, a decrease of $5.2 million, or 54.7%. The decrease was primarily due to a $5.0 million increase in the overhead attributable to field-level operations charged to operated wells, which reduced selling, general, and administrative expense, and a $2.3 million decrease in professional legal service fees. The decrease was partially offset by a $1.0 million increase in allocated corporate overhead, a $0.4 million increase in technology expenses, and a $0.4 million increase in fees charged by purchasers for early revenue payments received within the operating segment.

Operating Segment

Selling, general, and administrative expense for the operating segment was ($0.3) million for the three months ended March 31, 2026 as compared to $2.0 million for the same period in 2025, a decrease of $2.3 million, or 115.0%, primarily due to a $5.0 million increase in the overhead attributable to field-level operations charged to operated wells, which reduced selling, general, and administrative expense, partially offset by increased allocated corporate overhead of $1.1 million, a $1.0 million increase in fees associated with lease acquisition fees allocated to the operating segment, increased fees charged by purchasers for early revenue payments received of $0.4 million, and increased professional legal fees of $0.2 million within the operating segment.

Mineral and Non-operating Segment

Selling, general, and administrative expense for the mineral and non-operating segment was $2.9 million for the three months ended March 31, 2026, as compared to $4.9 million for the same period in 2025, a decrease of $2.0 million, or 40.8%. The decrease was primarily due to decreased professional service fees of $1.8 million, and decreased allocated corporate overhead of $0.3 million.

Securities Segment

Selling, general, and administrative expense for the securities segment was $1.7 million for the three months ended March 31, 2026, as compared to $2.6 million for the same period in 2025, a decrease of $0.9 million, or 34.6%, primarily due to decreased professional legal service fees of $1.0 million.

Payroll and Payroll-Related Expense

Payroll and payroll-related expense was $9.4 million for the three months ended March 31, 2026, as compared to $7.9 million for the same period in 2025, an increase of $1.5 million, or 19.0%, primarily as a result of increased employee headcount and compensation. Employee headcount increased from 154 employees at March 31, 2025 to 189 employees at March 31, 2026.

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Operating Segment

Payroll and payroll-related expense for the operating segment was $3.8 million for the three months ended March 31, 2026, as compared to $2.0 million for the same period in 2025, an increase of $1.8 million, or 90.0%, primarily due to the

increased number of personnel engaged in our oil and gas operating activities, partially offset by a $0.2 million increase in labor charged to wells operated by us, which reduced payroll and payroll-related expense.

Mineral and Non-operating Segment

Payroll and payroll-related expense for the mineral and non-operating segment was $2.9 million for the three months ended March 31, 2026, as compared to $4.0 million for the same period in 2025, a decrease of $1.1 million, or 27.5%, primarily due to a greater allocation of labor to other segments during the three months ended March 31, 2026 as compared to the same period in 2025, reflecting an alignment of employee time and responsibilities across segments.

Securities Segment

Payroll and payroll-related expense for the securities segment was $2.6 million for the three months ended March 31, 2026, as compared to $2.0 million for the same period in 2025, an increase of $0.6 million, or 30.0%, primarily due to increased employee compensation and the increased number of personnel engaged in the administration and management of our securities offerings.

Advertising and Marketing Expense

Advertising and marketing expense was $0.4 million for the three months ended March 31, 2026, as compared to $0.3 million for the same period in 2025, an increase of $0.1 million, or 33.3%, which was not material for the periods presented.

Impairment Expense

Impairment expense was $0.8 million for the three months ended March 31, 2026, as compared to $0.5 million for the same period in 2025, an increase of $0.3 million, or 60.0%, primarily as a result of lease expirations within the mineral and non-operating segment.

Other Expenses

Interest Expense, Net

Interest expense, net, was $52.5 million for the three months ended March 31, 2026, as compared to $35.8 million for the same period in 2025, an increase of $16.7 million, or 46.6%. The increase was primarily due to a $12.2 million increase in interest costs associated with sales of our unregistered debt securities and Registered Notes, which increased from $1.1 billion outstanding at March 31, 2025 to $1.2 billion outstanding at March 31, 2026, with no significant changes in interest rates between the periods, a $6.5 million increase in interest costs associated with the Fortress Credit Agreement, and a $1.5 million increase in interest costs associated with securities-related debt issuance costs for the three months ended March 31, 2026. The increase was partially offset by a $3.6 million increase in capitalized interest primarily due to higher qualifying asset expenditures.

Gain (Loss) on Derivatives

Loss on derivatives was $178.8 million for the three months ended March 31, 2026, as compared to a gain on derivatives of $1.9 million for the same period in 2025, an increase of $180.7 million, primarily as a result of unfavorable changes in the mark-to-market value of commodity derivatives entered into during the three months ended March 31, 2026 as compared to the same period in 2025.

Loss on Debt Extinguishments

Loss on debt extinguishments was $0.9 million for the three months ended March 31, 2026, as compared to $0.3 million for the same period in 2025, an increase of $0.6 million, or 200.0%. The increase was primarily due to increased write-offs of debt issuance costs associated with the redemption of bonds issued pursuant to our debt offerings, of which $8.2 million of bonds were redeemed during the three months ended March 31, 2026, as compared to $2.6 million of bonds redeemed for the same period in 2025.

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

		Three Months Ended March 31,								Change
(in thousands)		2026				2025				$				%
Reg D Bonds
August 2023 506(c) Bonds		$	4,620			$	1,593			$	3,027				190.0	%
Senior Reg D Bonds			—				100				(100	)			(100.0	)%
December 2022 506(c) Bonds			709				40				669				1,672.5	%
Total Reg D Bonds			5,329				1,733				3,596				207.5	%
Reg A Bonds			409				319				90				28.2	%
Adamantium Bonds			1,997				500				1,497				299.4	%
Registered Notes			231				—				231				NM
Exchange Notes			204				—				204				NM
Total		$	8,170			$	2,552			$	5,618				220.1	%

NM – not meaningful.

Non-GAAP Financial Measures

Our management uses EBITDA and Adjusted 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. Adjusted EBITDA is also used to understand and compare our results across accounting periods without giving effect to unsettled gains and losses on open commodity derivative contracts. Each of EBITDA and Adjusted 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 these non-GAAP financial measures, 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.

Each of EBITDA and Adjusted 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, each of EBITDA and Adjusted EBITDA excludes certain material costs, such as interest expense, and certain non-cash charges, such as depreciation, depletion, and amortization expense, which have been necessary elements of our expenses. Adjusted EBITDA further excludes non-cash charges related to unsettled gains and losses on open commodity derivative contracts. Because each of EBITDA and Adjusted 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 and/or Adjusted EBITDA may differ from computations of similarly titled measures of other companies. Therefore, our EBITDA and Adjusted 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 table shows a reconciliation of EBITDA and Adjusted EBITDA to net income (loss), the most comparable GAAP measure, as presented on the condensed consolidated statements of operations for the periods presented:

		Three Months Ended March 31,								Change
(in thousands)		2026				2025				$				%
Net income (loss)		$	(140,119	)		$	5,599			$	(145,718	)			(2,602.6	)%
Interest income			(213	)			(689	)			476				69.1	%
Interest expense, net			52,510				35,849				16,661				46.5	%
Depreciation, depletion, and amortization			60,249				31,225				29,024				93.0	%
EBITDA			(27,573	)			71,984				(99,557	)			(138.3	)%
Unrealized (gain) loss on derivatives			157,789				(2,823	)			160,612				5,689.4	%
Adjusted EBITDA		$	130,216			$	69,161			$	61,055				88.3	%

EBITDA was $(27.6) million for the three months ended March 31, 2026 as compared to $72.0 million for the three months ended March 31, 2025, a decrease of $99.6 million, or 138.3%. The decrease in EBITDA was primarily driven by a $180.7 million increase in loss on derivatives, primarily as a result of unfavorable changes in the mark-to-market value of commodity derivatives entered into during the three months ended March 31, 2026, and a $101.2 million increase in operating expense (excluding depreciation, depletion, and amortization expense), primarily driven by purchased crude oil expenses, increased cost of sales, and increased payroll and payroll-related expenses, partially offset by a $183.0 million increase in consolidated revenues. Adjusted EBITDA, which excludes unrealized gains and losses on derivatives, was $130.2 million for

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the three months ended March 31, 2026 as compared to $69.2 million for the three months ended March 31, 2025, an increase of $61.0 million, or 88.2%. Unrealized loss on derivatives increased by $160.6 million due to unfavorable mark-to-market changes in our open commodity derivative contracts.

The following table shows a reconciliation of EBITDA and Adjusted EBITDA to net income (loss), the most comparable GAAP measure, for the years ended December 31, 2025, 2024, and 2023:

		Year Ended December 31,
(in thousands)		2025				2024				2023
Net income (loss)		$	66,108			$	(24,793	)		$	(16,189	)
Interest income			(1,653	)			(705	)			(66	)
Interest expense, net			161,214				90,210				47,882
Depreciation, depletion, and amortization			177,913				85,977				34,228
EBITDA			403,582				150,689				65,855
Unrealized (gain) loss on derivatives			(48,289	)			7,518				32
Adjusted EBITDA		$	355,293			$	158,207			$	65,887

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, and the issuance of the Series A Preferred Shares in September 2025. Future sources of liquidity may also include other credit facilities, continued issuances of debt or equity securities, which may be different than the type of debt or equity securities we have issued so far in terms of security, maturity, and interest rates, asset-backed or other securitizations, 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 and ad valorem taxes for mineral and royalty interests, production costs, including gathering, processing, and transportation costs, debt service payments and distributions on the Series A Preferred Shares, 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 March 31, 2026, we had cash and cash equivalents of $70.2 million, outstanding indebtedness of $1.7 billion, and a liquidation preference of Series A Preferred Shares of $67.6 million.

As of March 31, 2026, we had $148.7 million of debt coming due and $146.5 million of interest payable within the next 12 months, as well as $1.7 million of distributions payable on the Series A Preferred Shares. Over the next 12 months, we expect to drill between 75 to 105 gross and 54.0 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 between 310 to 410 gross and 10.8 to 14.2 net wells across our non-operated leasehold. We estimate that these direct drilling operations and non-operated activity will require between $750.0 million and $810.0 million of capital expenditures over the next 12 months.

Our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, making distributions on the Series A Preferred Shares, or refinancing our indebtedness, will depend on our ability to generate cash in the future. We raised $185.6 million in proceeds from the issuance of debt securities and increased borrowings under the Fortress Credit Agreement during the three months ended March 31, 2026. We believe that these sources of liquidity will be sufficient to meet our cash requirements, with respect to our current commitments, 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. Although we expect that our cash flows from operations will be sufficient to meet our fixed obligations, to fully realize our business plan we anticipate that we would need to raise approximately $147.3 million in capital in 2026, which may involve different types of financing or issuances of debt or equity securities that differ from the types of securities we have previously issued.

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. Although oil prices have surged recently, rising to $112.95 per Bbl as of April 7, 2026, following the onset of the conflict in the Middle East involving Iran, Israel, the United States, and numerous other oil producing countries in the region, and the closure of the Strait of Hormuz, this follows weaker oil prices that persisted through much of the second half of 2025, when oil prices went from $70.00 per barrel as of July 30, 2025 to $55.27 per barrel as of December 16, 2025. These prices were below

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those assumed for purposes of our business plan. While we believe we are 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. Conversely, subject to commodity prices, operational conditions and capital availability, we may contemplate adding additional completion resources during the second quarter of 2026 in order to accelerate the timing of bringing certain wells online and increase production volumes, and may also evaluate the addition of a fourth drilling rig later in 2026. We may also be required to raise additional capital, above our current expectations, in order to fully realize our current or adjusted business plan. 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 “Risks Related to Our Business and Operations” and “Risks Related to Our Indebtedness” in Part I. Item 1A of our 2025 Annual Report.

We or our affiliates may from time to time seek to repurchase or retire Registered Notes, other indebtedness, or Series A Preferred Shares through cash purchases and/or exchanges for equity or debt securities, in open-market purchases, privately negotiated transactions, tender or exchange offers, or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity, contractual restrictions, and other factors. The amounts involved may be material. For more information regarding the material terms of our outstanding indebtedness, see “—Indebtedness” below.

Cash Flows

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

		Three Months Ended March 31,								Change
(in thousands)		2026				2025				$				%
Net cash provided by (used in):
Operating activities		$	103,801			$	18,102			$	85,699				473.4	%
Investing activities			(238,629	)			(182,384	)			(56,245	)			(30.8	)%
Financing activities			139,210				78,834				60,376				76.6	%
Net increase (decrease) in cash and cash equivalents		$	4,382			$	(85,448	)		$	89,830				105.1	%

Operating Activities

Net cash provided by operating activities for the three months ended March 31, 2026 was $103.8 million, as compared to $18.1 million for the same period in 2025, an increase of $85.7 million in cash provided by operating activities. The increase was primarily due to a $145.7 million increase in net loss, adjusted for non-cash charges of $192.9 million, and net favorable fluctuations of $38.5 million from changes in operating assets and liabilities. The $38.5 million cash inflow from changes in operating assets and liabilities was primarily due to increased other current liabilities, earnest payments, and accrued interest totaling $28.2 million, increased net derivative liability of $22.3 million, and decreased escrow account liability of $3.6 million, partially offset by an increase in accounts receivable of $15.3 million, primarily due to the timing of cash receipts and payments during the three months ended March 31, 2026 as compared to the same period in 2025.

Investing Activities

Net cash used in investing activities for the three months ended March 31, 2026 was $238.6 million, as compared to $182.4 million for the same period in 2025, an increase of $56.2 million in cash used in investing activities. The increase was driven by a $56.2 million increase in additions to oil and gas properties, primarily due to increased drilling and completion activities in our operating segment during three months ended March 31, 2026 as compared to the same period in 2025.

Financing Activities

Net cash provided by financing activities for the three months ended March 31, 2026 was $139.2 million, as compared to $78.8 million for the same period in 2025, an increase of $60.4 million in cash provided by financing activities. The increase was primarily driven by increased proceeds from issuances of debt, net of debt discount, of $79.7 million, partially offset by a $9.4 million increase in repayments of debt related to securities, a $5.4 million increase in payments of debt issuance costs, a $2.8 million increase in payments of deferred closings associated with mineral interest acquisitions, and a $1.7 million increase in payments of dividends for the Series A Preferred Shares.

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Preferred Equity

In September 2025, we completed our offering of the Series A Preferred Shares, 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. In addition, at issuance we recorded a $2.4 million discount associated with the stepped distribution rate feature of the Series A Preferred Shares, which provides for increases in the distribution rate prior to the commencement of the 11.0% perpetual distribution rate in year five. For the three months ended March 31, 2026, $0.2 million of this discount was amortized.

During the three months ended March 31, 2026, the Company paid $1.7 million of distributions to the holders of the Series A Preferred Shares equal to $0.625 per share. In March 2026, the Company’s Board of Directors authorized and declared a distribution on the Series A Preferred Shares equal to $0.625 per share, which was paid on April 15, 2026, to holders of record as of April 1, 2026, and totaled $1.7 million. As of March 31, 2026, the Company had accrued $1.5 million of dividends payable, which is included in other current liabilities on the condensed consolidated balance sheet.

Indebtedness

Set forth below is a chart of our outstanding third-party indebtedness as of March 31, 2026 (dollars in thousands):

Indebtedness

Offering Commencement

Principal Amount Outstanding

Term

Earliest Maturity

Latest Maturity

Interest Rate

Secured

Fortress Credit Agreement(1)

N/A

$

525,000

3 years

—

10/27/2028

Term SOFR + 7.10%

Adamantium Secured Note(2)

N/A

9,300

7 years

—

11/1/2031

16.5%

Unsecured

Reg A Bonds(3)

12/23/2021

33,783

3 years

4/10/2026

8/10/2027

9.0%

Senior Reg D Bonds(4)

7/20/2022

7,604

5 years

7/31/2027

12/31/2027

11.0%

December 2022 506(c) Bonds(5):

Series B

12/22/2022

8,323

3 years

4/10/2026

10/10/2026

10.0%

Series C

12/22/2022

9,035

5 years

12/10/2027

9/10/2028

11.0%

Series D

12/22/2022

33,449

7 years

12/10/2029

10/10/2030

12.0%

August 2023 506(c) Bonds(5):

Series U, AA, and FF

8/29/2023

102,472

1 year

4/10/2026

3/10/2027

9.0%—10.0%

Series V, BB, and GG

8/29/2023

120,664

3 years

8/10/2026

3/10/2029

10.0%—11.0%

Series W, CC, and HH

8/29/2023

79,404

5 years

8/10/2028

3/10/2031

11.0%—12.0%

Series X, DD, and II

8/29/2023

95,280

7 years

9/10/2030

3/10/2033

12.0%—13.0%

Series Y

8/29/2023

3,579

9 years

9/10/2032

9/10/2033

12.5%

Series Z, EE, and JJ

8/29/2023

305,769

11 years

9/10/2034

3/10/2037

13.0%—14.0%

Total Reg D/Reg A Bonds

799,362

Exchange Notes(3):

Three-Year Exchange Notes

5/15/2025

5,306

3 years

12/10/2027

3/10/2029

9.0%

Five-Year Exchange Notes

5/15/2025

8,531

5 years

12/10/2029

3/10/2031

10.0%

Seven-Year Exchange Notes

5/15/2025

4,453

7 years

12/10/2031

3/10/2033

11.0%

Eleven-Year Exchange Notes

5/15/2025

17,250

11 years

5/10/2036

3/10/2037

12.0%

Total Exchange Notes

35,540

Registered Notes(6):

Three-Year Registered Notes

5/14/2025

16,739

3 years

5/10/2028

3/10/2029

9.0%

Five-Year Registered Notes

5/14/2025

11,015

5 years

5/10/2030

3/10/2031

10.0%

Seven-Year Registered Notes

5/14/2025

5,238

7 years

5/10/2032

3/10/2033

11.0%

Eleven-Year Registered Notes

5/14/2025

22,106

11 years

5/10/2036

3/10/2037

12.0%

Total Registered Notes

55,098

Adamantium Bonds(7)

9/29/2023

278,032

5-11 years

6/10/2029

3/10/2037

13.0%—16.0%

Total Unsecured Debt

1,168,032

Total Debt

$

1,702,332

(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 on October 11, 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, a $100.0 million term loan facility, borrowed in full on August 1, 2025, a tranche of commitments to make term loans available in an aggregate principal amount of $350.0 million, of which $50.0 million was borrowed on October 27, 2025, and up to $300.0 million available on a discretionary basis. On February 12, 2026, the Fortress Credit Agreement was amended to provide for a $75.0 million term loan facility, which was borrowed in full on February 12, 2026, reducing the commitments available on a discretionary basis from $300.0 million to $225.0 million. The Fortress Credit Agreement also provides

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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, the Exchange Notes, and the Registered Notes to the extent of the value of Adamantium’s assets, including the collateral securing the Adamantium Loan Agreement. On February 12, 2026, an additional $0.7 million of principal amount was issued under the Adamantium Secured Note (and the Adamantium Loan Agreement was amended to provide for a corresponding borrowing amount).

(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, and the Exchange Notes are contractually subordinated to amounts under the Fortress Credit Agreement and the Adamantium Debt. Amount displayed does not include amounts of Exchange Notes issued after March 31, 2026.

(4) The Senior Reg D Bonds are pari passu obligations with the Reg A Bonds and the Exchange Notes, are contractually subordinated to amounts under the Fortress Credit Agreement and the Adamantium Debt, 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 Adamantium Debt, the Reg A Bonds, the Exchange Notes, the Senior Reg D Bonds, and the Registered Notes. Amount displayed does not include amounts issued after March 31, 2026.

(6) The Registered Notes are contractually subordinated to amounts under the Fortress Credit Agreement, the Adamantium Debt, the Senior Phoenix Bonds, and are contractually senior to the Subordinated Reg D Bonds. Amount displayed does not include amounts issued after March 31, 2026.

(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, the Exchange Notes, and the Registered Notes 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 and the Reg D Bonds. Amount displayed does not include amounts issued after March 31, 2026.

Fortress Credit Agreement

In August 2024, we entered into a senior secured credit agreement with Fortress Credit Corp. (the “Fortress Credit Agreement”) as lender and administrative agent, which was subsequently amended to add additional term loan tranches and syndicated to include an additional institutional lender. In February 2026, the Fortress Credit Agreement was further amended to provide a $75.0 million term loan funded at closing and up to $225.0 million available on a discretionary basis. Proceeds are to be used to finance the development of our oil and gas properties in accordance with the approved plan of development provided in the Fortress Credit Agreement.

The Fortress Credit Agreement contains various customary covenants, including financial covenants that require us to maintain ratios around our maximum total secured leverage, minimum asset coverage, current assets to current liabilities, and working capital as of the last day of each calendar month or fiscal quarter, as the case may be. On May 7, 2026, subsequent to the balance sheet date, we obtained a waiver of noncompliance with the current ratio covenant as of March 31, 2026, which resulted primarily from the timing of accelerated well completion expenditures undertaken to capitalize on higher commodity prices.

Adamantium Securities

In September 2023, we entered into the Adamantium Loan Agreement with Adamantium, as lender, which was amended in October 2023 to add PhoenixOp as a borrower, and subsequently amended to increase the loan amount under the agreement (the “Adamantium Loan Agreement”). The Adamantium Loan Agreement provides for up to $609.3 million in aggregate principal amount of borrowings in one or more advances, comprising $600.0 million from the proceeds of Adamantium Bonds and $9.3 million from the proceeds of the Adamantium Secured Note. 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 March 31, 2026, $278.0 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%—16.0% per annum, and $9.3 million aggregate principal amount was outstanding under the Adamantium Secured Note, which 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.

Registered Notes

In May 2025, the SEC declared effective our registration statement with respect to the continuous offering of up to $750.0 million aggregate principal amount of our 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. As of March 31, 2026, we had issued $56.7 million aggregate principal amount of Registered Notes.

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Reg D/Reg A Bonds and Exchange Notes

As of March 31, 2026, we had $834.9 million aggregate principal amount outstanding of unsecured bonds issued pursuant to Regulation D, Regulation A, and Section 3(a)(9) and/or 4(a)(2) of the Securities Act (other than the Adamantium Bonds), consisting of:

(a) $7.6 million aggregate principal amount outstanding of Senior Reg D 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, and which are pari passu with the Reg A Bonds and the Exchange Notes, are contractually subordinated to amounts under the Fortress Credit Agreement and the Adamantium Debt, and are contractually senior to obligations under the Subordinated Reg D Bonds and the Registered Notes;

(b) $758.0 million aggregate principal amount outstanding of Subordinated Reg D Bonds, which are contractually subordinated to obligations under the Fortress Credit Agreement, the Adamantium Debt, the Reg A Bonds, the Exchange Notes, the Senior Reg D Bonds, and the Registered Notes, comprising:

(i) $50.8 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) $707.2 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;

(c) $33.8 million aggregate principal amount outstanding of Reg A Bonds, which are unsecured bonds offered and sold pursuant to an offering under Regulation A, which commenced in December 2021 and terminated in December 2024, with a term of three years from the issue date and an interest rate of 9.0% per annum, which Reg A Bonds are pari passu with the Senior Reg D Bonds and Exchange Notes and are contractually senior to obligations under the Subordinated Reg D Bonds and the Registered Notes; and

(d) $35.5 million aggregate principal amount outstanding of Exchange Notes, which are unsecured bonds issued by us to holders of the Reg A Bonds in exchange for their Reg A Bonds in offerings exempt from registration under Section 3(a)(9) and/or 4(a)(2) of the Securities Act, with maturity dates of three, five, seven, or eleven years from the issue date and interest rates ranging from 9.0% to 12.0% per annum, which Exchange Notes are pari passu with the Senior Reg D Bonds and Reg A Bonds, are contractually senior to obligations under the Subordinated Reg D Bonds and the Registered Notes, and are contractually subordinated to obligations under the Fortress Credit Agreement and the Adamantium Debt.

In March 2026, we approved an increase to the maximum offering amount of the August 2023 506(c) Bonds from $1.5 billion to $2.0 billion.

Contractual Obligations and Commitments

As part of our ongoing operations, we enter into contractual arrangements that obligate us to make future cash payments. These obligations impact our liquidity and capital resource needs. Our estimated future obligations consist of debt obligations, interest on debt obligations, leases, deferred closing arrangements, and purchase obligations. As of March 31, 2026, there were no material changes outside the ordinary course of business since December 31, 2025 to our contractual obligations and commitments and the related cash requirements.

Critical Accounting Policies and Use of Estimates

Our critical accounting policies are described in Note 2, “Significant Accounting Policies,” of the notes to the accompanying condensed consolidated financial statements included elsewhere in this Quarterly Report. During the three months ended March 31, 2026, there have been no material changes in our critical accounting policies from those discussed under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Use of Estimates” in our 2025 Annual Report except as discussed below.

Inventory

Crude oil in storage tanks that has not yet been sold is classified as inventory and recorded within other current assets on our condensed consolidated balance sheets. Inventory is stated at the lower of cost and net realizable value, with cost determined using a weighted average cost method, and includes costs incurred to bring the inventory to its present location and condition.

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Recent Accounting Pronouncements

See Note 2, “Significant Accounting Policies,” of the notes to the accompanying 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, natural gas, and NGL 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, natural gas, and NGL 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, natural gas, and NGL 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, natural gas, and NGL prices on our revenues, we periodically enter into commodity derivative contracts with respect to certain of our oil, natural gas, and NGL 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 of March 31, 2026, over approximately the next three years through December 2028, we had 16.6 million Bbl of anticipated oil production hedged through a combination of: fixed-price swaps at a weighted average contract price of $61.03 per Bbl, collars with weighted average floor and ceiling prices of $55.39 and $70.78 per Bbl, respectively, and call options with a strike price of $75.00 per Bbl, excluding the effect of deferred option premiums. Assuming a price of $0 per Bbl, these derivative contracts would generate aggregate cash settlements of approximately $0.7 billion over the same period. 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.

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 liability of $136.7 million as of March 31, 2026. Based upon our open commodity derivative positions at March 31, 2026, a hypothetical 10.0% increase in the NYMEX WTI price would increase our net derivative liability position by $87.4 million, while a 10.0% decrease in the NYMEX WTI price would decrease our net derivative liability position by $87.4 million.

A $1.00 per Bbl change in our realized oil price would have resulted in a $2.9 million and a $1.6 million change in our oil revenues for the three months ended March 31, 2026 and 2025, respectively. A $0.10 per Mcf change in our realized natural gas price would have resulted in a $0.1 million and a less than $0.1 million change in our natural gas revenues for the three months ended March 31, 2026 and 2025, respectively. A $1.00 per Bbl change in NGL prices would have resulted in a $0.3 million and a less than $0.1 million change in our NGL revenues for the three months ended March 31, 2026 and 2025, respectively. Revenues from oil sales contributed 95.0% and 94.6%, revenues from natural gas sales contributed 1.6% and 1.9%, and revenues from NGL sales contributed 2.0% and 2.1% of our consolidated revenues for the three months ended March 31, 2026 and 2025, respectively.

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Interest Rate Risk

Our primary exposure to interest rate risk results from outstanding borrowings under our credit facilities, which bear interest at a floating rate. The average interest rate incurred when such facility was outstanding on our borrowings under the Fortress Credit Agreement during the three months ended March 31, 2026 and 2025 was 10.8% and 11.4%, respectively. 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 $5.3 million. See “—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 March 31, 2026, one purchaser of our commodities and nine third-party E&P operators made up 45.6% and 9.3% of our consolidated revenue, respectively, as compared to one purchaser of our commodities and eleven third-party E&P operators that made up 66.5% and 23.5% of our consolidated revenue, respectively, for the three months ended March 31, 2025.

Similarly, as of March 31, 2026, we had concentrations in accounts receivable of 24.2% with one purchaser of our commodities, as compared to 20.0%, 15.0%, and 14.0% with three third-party E&P operators as of March 31, 2025. 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.

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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 March 31, 2026 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 audit of our consolidated financial statements as of and for the year ended December 31, 2025, our auditors identified several material weaknesses in our internal control over financial reporting. The material weaknesses identified were: (i) inadequate segregation of duties within key financial areas; (ii) entity-level controls that were not sufficiently designed, documented or consistently maintained across the Committee of Sponsoring Organizations of the Treadway Commission (COSO) components to provide reasonable assurance that material misstatements would be prevented or detected on a timely basis; (iii) ineffective processes for identifying and assessing risks impacting internal control over financial reporting; (iv) insufficient evaluation and determination as to whether components of internal controls were present and functioning; (v) ineffective information technology general controls supporting the financial reporting process; and (vi) ineffective controls over the completeness and accuracy of information used in the operation of control activities.

These material weaknesses did not result in any identified material misstatements in the Company’s condensed consolidated financial statements included in this Quarterly Report. However, these material weaknesses could result in a misstatement of the Company’s financial statements that would not be prevented or detected on a timely basis.

Management’s Remediation Efforts

Management has begun implementing measures designed to remediate the material weaknesses described above. These remediation efforts include, but are not limited to: enhancing segregation of duties within financial reporting and related systems; enhancing the design and documentation of entity-level controls across the COSO components; strengthening the Company’s formal risk assessment processes related to financial reporting; implementing additional procedures to evaluate whether internal control components are present and functioning; implementing improvements to information technology general controls, including user access management, system change management, and system monitoring controls; establishing additional controls over the completeness and accuracy of information used in financial reporting processes; and expanding internal control documentation, training and monitoring activities.

These measures include 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. In addition, the Company implemented a new accounting system effective January 1, 2026, which management believes will enhance financial reporting processes and support improvements to internal control over financial reporting. The Company will continue to evaluate the effectiveness of controls associated with this system as part of its remediation efforts.

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 three months ended March 31, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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. Such matters are subject to many uncertainties, and outcomes are not predictable with certainty. 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. Based on currently available information and after consultation with legal counsel, 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. We have not recorded any material accruals related to these matters as of March 31, 2026. See “Notes to the Condensed Consolidated 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

In addition to the other information set forth in this Quarterly Report, you should carefully consider the factors set forth in the section of our 2025 Annual Report entitled “Risk Factors.” These factors could materially adversely affect our business, financial condition, liquidity, results of operations and capital position, and could cause our actual results to differ materially from our historical results or the results contemplated by any forward-looking statements contained in this Quarterly Report. There have been no material changes from the risk factors disclosed under the heading “Risk Factors” in our 2025 Annual Report.

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

(a) Recent Sales of Unregistered Securities: None.

(b) Use of Proceeds: On May 14, 2025, the registration statement with respect to up to $750.0 million aggregate principal amount of Registered Notes (File No. 333-282862) was declared effective and the Company commenced the offering of the Registered Notes on a continuous basis. Crescent Securities Group, Inc. currently acts as managing broker-dealer for the offering. The offering of the Registered Notes is ongoing, and, as of the date of this Quarterly Report, the Company has sold $56.7 million aggregate principal amount of Registered Notes, before payment of broker-dealer commissions of approximately $0.4 million and transaction fees and expenses. The proceeds of the Registered Notes have been and will continue to be used as described in the prospectus with respect to the offering.

(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 March 31, 2026, no 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 Disclosures

Our Oil and Natural Gas Properties

Productive Wells

Productive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells. As of March 31, 2026, we owned mineral, royalty, and working interests in 8,192 productive wells, the majority of which are oil wells that also produce natural gas and NGL.

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As of March 31, 2026, we had 245 wells that fall under our “wells in progress” (“WIP”) category, and we had 86 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: (i) a well that is not actively being drilled but is in the process of being developed; (ii) a well currently being drilled and awaiting completion; (iii) a drilled well in the completion process; and (iv) 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 three months ended March 31, 2026, the E&P operators of our properties, including PhoenixOp, drilled 33 gross and 13.7 net productive development wells on the acreage underlying our mineral and royalty interests. This compares to 26 gross and 4.2 net productive development wells drilled by E&P operators on the acreage underlying our mineral and royalty interests in the three months ended March 31, 2025.

Included in our total drilled wells figures, as of March 31, 2026, PhoenixOp had drilled a total of 113 gross and 101.2 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 22 gross and 22 net saltwater disposal wells, and had 93 gross and 74.1 net development wells in progress as of March 31, 2026.

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 March 31, 2026, we owned mineral, royalty, and working interests in 8,192 total gross wells and 182.9 total net wells. The following table sets forth information about the productive wells in which we have a mineral or working interest as of March 31, 2026:

		Well Count
		Oil								Gas
		Gross				Net				Gross				Net
Basin or Producing Region
Bakken/Williston Basin			4,854				162.0				3				0.0
Denver-Julesburg Basin/Rockies/Niobrara			1,574				18.0				6				0.0
Permian Basin			744				1.4				2				0.0
Other			494				1.5				515				0.0
Total			7,666				182.9				526				0.0

Acreage of Mineral and Working Interests

The following tables set forth information relating to the acreage underlying our mineral and working interests as of March 31, 2026:

Acreage of Mineral Interest

		Net Royalty Acres
		Developed Acreage				Undeveloped Acreage				Total Acreage
Basin
Bakken/Williston Basin			49,818				62,269				112,087
Denver-Julesburg Basin/Rockies/Niobrara/PRB			9,313				7,982				17,295
Permian Basin			930				81				1,011
Other			10,863				425,393				436,256
Total Net Royalty Acres			70,924				495,725				566,649

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		Gross Royalty Acres
		Developed Acreage				Undeveloped Acreage				Total Acreage
Basin
Bakken/Williston Basin			628,929				1,008,262				1,637,191
Denver-Julesburg Basin/Rockies/Niobrara/PRB			126,151				378,322				504,473
Permian Basin			94,083				24,603				118,686
Other			17,579				2,216,297				2,233,876
Total Gross Royalty Acres			866,742				3,627,484				4,494,226

Acreage of Working Interest

		Net Mineral Acres
		Developed Acreage				Undeveloped Acreage				Total Acreage
Basin
Bakken/Williston Basin			54,435				287,745				342,180
Denver-Julesburg Basin/Rockies/Niobrara/PRB			2,663				32,028				34,691
Permian Basin			61				3				64
Other			252				259,873				260,125
Total Net Mineral Acres			57,411				579,649				637,060

		Gross Mineral Acres
		Developed Acreage				Undeveloped Acreage				Total Acreage
Basin
Bakken/Williston Basin			305,821				882,049				1,187,870
Denver-Julesburg Basin/Rockies/Niobrara/PRB			44,222				236,711				280,933
Permian Basin			7,680				1,280				8,960
Other			15,872				1,309,568				1,325,440
Total Gross Mineral Acres			373,595				2,429,608				2,803,203

Acreage Expirations

As of March 31, 2026, we have 459,413 gross and 66,096 net working interest acres expiring through the end of 2027, with an additional 547,882 gross and 69,696 net working acres expiring in 2028, and 555,754 gross and 83,420 net working interest acres expiring in 2029. The remaining 458,456 gross and 79,323 net working interest acres expire in years 2030 and beyond.

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Oil, Natural Gas, and NGL Reserves

The following table presents our estimated proved and probable oil, natural gas, and NGL reserves as of each of the dates indicated:

		As of				As of December 31,
		March 31, 2026(1)(2)				2025(2)(3)				2024(2)(4)				2023(2)(5)
Estimated proved developed reserves
Oil (Bbl)			46,755,372				39,367,935				18,624,758				7,124,194
Natural gas (Mcf)			43,305,693				32,222,398				20,819,874				12,250,285
Natural gas liquids (Bbl)			11,234,663				6,882,740				2,848,355				1,514,761
Total (Boe)(6:1)(6)			65,207,650				51,621,074				24,943,092				10,680,669
Estimated proved undeveloped reserves
Oil (Bbl)			58,163,102				49,888,499				31,197,795				24,925,841
Natural gas (Mcf)			49,123,015				27,916,131				17,491,089				19,565,808
Natural gas liquids (Bbl)			13,195,144				7,451,608				4,753,257				6,648,747
Total (Boe)(6:1)(6)			79,545,415				61,992,797				38,866,234				34,835,556
Estimated proved reserves
Oil (Bbl)			104,918,474				89,256,434				49,822,553				32,050,035
Natural gas (Mcf)			92,428,708				60,138,529				38,310,963				31,816,093
Natural gas liquids (Bbl)			24,429,807				14,334,348				7,601,612				8,163,508
Total (Boe)(6:1)(6)			144,753,066				113,613,871				63,809,326				45,516,226
Percent proved developed			45	%			45	%			39	%			23	%
Estimated probable undeveloped reserves
Oil (Bbl)			186,778,266				178,532,093				107,769,309				74,877,268
Natural gas (Mcf)			100,758,792				105,888,056				134,083,603				88,184,111
Natural gas liquids (Bbl)			33,051,879				31,779,646				—				—
Total (Boe)(6:1)(6)			236,623,277				227,959,749				130,116,576				89,574,620

(1) Estimates of reserves of oil and natural gas as of March 31, 2026 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 March 31, 2026, 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 $63.80 per Bbl for oil and $3.720 per MMBtu for natural gas at March 31, 2026. Estimates of reserves of NGL as of March 31, 2026 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at March 31, 2026 was $21.15 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, 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 December 31, 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 $66.01 per Bbl for oil and $3.387 per MMBtu for natural gas at December 31, 2025. Estimates of reserves of NGL as of December 31, 2025 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2025 was $20.90 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, 2024 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2024, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $76.32 per Bbl for oil and $2.130 per MMBtu for natural gas at December 31, 2024. Estimates of reserves of NGL as of December 31, 2024 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2024 was $25.22 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(5) Estimates of reserves of oil and natural gas as of December 31, 2023 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month of the 12 months ended December 31, 2023, in accordance with SEC guidelines applicable to reserve estimates as of the end of such period. The unweighted arithmetic average first day of the month prices were $78.21 per Bbl for oil and $2.637 per MMBtu for natural gas at December 31, 2023. Estimates of reserves of NGL as of December 31, 2023 were calculated using the average of realized wellhead prices of such reserves. The average NGL price realized at December 31, 2023 was $19.21 per Bbl. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, production costs, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

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(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 March 31, 2026 was used, the conversion factor would be approximately 17.15 Mcf per Bbl of oil.

At March 31, 2026, total estimated proved reserves were approximately 144,753,066 Boe, a 31,139,195 Boe net increase from the estimate of 113,613,871 at December 31, 2025. Proved developed reserves of 65,207,650 Boe represented an increase of approximately 13,586,576 Boe from the estimate of 51,621,074 Boe at December 31, 2025 as a result of proved developed extensions of 23,706,620 Boe and total negative revisions of previous estimates of (10,120,044) Boe, which comprised: (i) negative revisions due to effective-date roll-forward of reserve estimates of (3,421,490) Boe, (ii) negative price revisions of (124,286) Boe, (iii) negative revisions of (26,125) Boe due to divestitures and trades, (iv) negative revisions of (6) Boe due to schedule adjustments, (v) positive revisions of 14,720,684 Boe due to transferring proved undeveloped reserves to proved developed reserves, (vi) positive shrink and yield revisions of 4,436,385 Boe, (vii) positive interest adjustments of 2,450,538 Boe, (viii) positive revisions of 2,042,482 Boe due to changes in lifting cost, (ix) negative well performance revisions of (6,548,137) Boe, and (x) positive revisions of 56,531 due to acquisitions of new properties. Proved undeveloped reserves of 79,545,415 Boe represented an increase of approximately 17,552,618 Boe from the estimate of 61,992,797 Boe at December 31, 2025 as a result of proved undeveloped extensions of 34,411,537 Boe and total negative revisions of previous estimates of (16,858,919) Boe, which comprised: (i) negative revisions due to effective-date roll-forward of reserve estimates of (108,060) Boe, (ii) negative price revisions of (116,724) Boe, (iii) negative revisions of (1,820,353) Boe due to divestitures and trades, (iv) positive revisions of 62,301 Boe due to schedule adjustments, (v) negative revisions of (14,720,684) Boe due to transferring proved undeveloped reserves to proved developed reserves, (vi) positive shrink and yield revisions of 2,155,135 Boe, (vii) positive interest adjustments of 4,318,801 Boe, (viii) positive revisions of 1,263,287 Boe due to changes in lifting cost, (ix) negative well performance revisions of (93,098) Boe, and (x) positive revisions of 26,612,013 Boe due to acquisitions of new properties. During the three months ended March 31, 2026, approximately $186.1 million in capital expenditures went toward the development of proved reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells.

At December 31, 2025, total estimated proved reserves were approximately 113,613,871 Boe, a 49,804,545 Boe net increase from the estimate of 63,809,326 Boe at December 31, 2024. The increase was primarily the result of extensions and discoveries of 71,088,631 Boe, partially offset by revisions of previous estimates of (12,396,675) Boe and production of (9,924,337) Boe during the year. Proved developed reserves of 51,621,074 Boe represented an increase of 26,677,982 Boe from December 31, 2024, primarily due to extensions and discoveries of 8,782,530 Boe, transfers of 19,515,344 Boe from proved undeveloped reserves, purchases of reserves in place of 571,500 Boe, and revisions of previous estimates of 8,008,132 Boe, partially offset by production of (9,924,337) Boe and divestitures and trades of (275,187) Boe. The revisions of previous estimates affecting proved developed reserves comprised of timing adjustments associated with the effective-date roll-forward, write-downs of certain locations, shrink and yield revisions, well performance revisions, price revisions, interest adjustments, and changes in lifting costs. Proved undeveloped reserves of 61,992,797 Boe represented an increase of 23,126,563 Boe from December 31, 2024, primarily due to extensions and discoveries of 62,306,101 Boe and purchases of reserves in place of 740,613 Boe, partially offset by transfers of (19,515,344) Boe to proved developed reserves and revisions of previous estimates of (20,404,807) Boe. The revisions of previous estimates affecting proved undeveloped reserves primarily reflected timing adjustments associated with the effective-date roll-forward of reserve estimates, write-downs of certain locations, shrink and yield revisions, well performance revisions, price revisions, interest adjustments, and changes in lifting costs. During the year ended December 31, 2025, approximately $686.8 million in capital expenditures went toward the 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, an 18,293,100 Boe net increase from the previous year end’s estimate of 45,516,226 Boe. Proved developed reserves of 24,943,092 Boe increased approximately 14,262,423 Boe from December 31, 2023 as a result of proved developed reserves acquisitions of 1,047,809 Boe, extensions of 3,268,997 Boe, and total positive revisions of previous estimates of 14,759,886 Boe, partially 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 38,866,234 Boe increased approximately 4,030,678 Boe from December 31, 2023 as a result of proved undeveloped reserves extensions of 21,207,289 Boe 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 45,516,226 Boe, a 40,553,802 Boe net increase from the previous year end’s estimate of 4,962,424 Boe. Proved developed reserves of 10,680,669 Boe increased approximately 5,718,245 Boe from December 31, 2022 as a result of proved developed reserves acquisitions of 1,426,545 Boe, extensions of 5,682,894 Boe, and total positive revisions of previous estimates of 616,010 Boe, partially offset by production from proved developed reserves of 2,007,205 Boe. The total positive revisions of previous estimates comprised: (i) negative price revisions of (13,622) Boe; (ii) transfer of 89,378 Boe from proved developed to proved undeveloped due to previous misclassifications of reserve; (iii) positive well performance revisions of 515,938 Boe; and (iv) positive revisions of 203,072 Boe due to changes in lifting cost. Proved undeveloped reserves of 34,835,556 Boe increased approximately 34,835,556 Boe from December 31, 2022 as a result of revisions due to previous misclassification of 89,378 Boe of reserves as proved developed reserves and due to the addition of 34,746,179 Boe of operated proved undeveloped reserves stemming from the signing of a drilling rig contract in June 2023. During the year ended December 31, 2023, approximately $171.2 million in capital expenditures went toward the acquisition and development of proved developed reserves, which includes drilling, completion, and other facility costs associated with acquiring and developing wells. At December 31, 2022, there were no proved undeveloped reserves. Therefore, no capital expenditures for the year ended December 31, 2023 were related to the conversion of proved undeveloped reserves to proved developed reserves. All proved undeveloped reserves disclosed as of December 31, 2023 are scheduled to be converted to proved developed status within five years of initial disclosure.

Delivery Commitments

We are subject to arrangements pursuant to which we have committed to deliver barrels of crude oil to a purchaser through December 31, 2030. We will be subject to a shortfall fee for failure to meet this commitment. As a part of these arrangements, we have dedicated to the counterparties certain rights to all oil extracted from our wells in certain properties in Dunn County, North Dakota. We have assessed the productivity potential of our leasehold in the area, as well as the feasibility of executing an operational plan to extract oil on our leasehold within the commitment period and dedication area, and deemed it to be reasonable to enter into such an agreement. We delivered 0.2 million barrels of crude oil during the three months ended March 31, 2026, and the remaining aggregate commitment under the contract as of March 31, 2026 is approximately 1.0 million barrels of crude oil. Based on current production levels from the dedicated acreage, we believe we have sufficient production capacity to satisfy the remaining contractual volume commitments. However, future production levels are subject to operational, commodity price, and reservoir performance risks. In the event of a shortfall, any associated fees would not be expected to materially impair our liquidity position.

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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 Three Months Ended March 31,								For the Years Ended December 31,
		2026				2025				2025				2024				2023
Production Data:
Bakken
Oil (Bbl)			2,770,306				1,386,145				7,831,787				3,022,810				943,930
Natural gas (Mcf)			975,571				331,296				2,176,128				1,301,782				1,123,859
Natural gas liquids (Bbl)			251,284				54,214				576,561				270,219				88,762
Total (Boe)(6:1)(1)			3,184,185				1,495,575				8,771,036				3,509,992				1,220,003
Average daily production (Boe/d)(6:1)			35,380				16,618				24,030				9,590				3,342
All Properties
Oil (Bbl)			2,916,301				1,552,609				8,641,089				3,830,461				1,446,928
Natural gas (Mcf)			1,306,171				712,492				3,427,154				2,979,341				2,152,939
Natural gas liquids (Bbl)			283,870				87,962				712,056				415,363				201,454
Total (Boe)(6:1)(1)			3,417,866				1,759,320				9,924,337				4,742,381				2,007,205
Average daily production (Boe/d)(6:1)			37,976				19,548				27,190				12,993				5,499
Average Realized Prices:
Bakken
Oil (Bbl)		$	71.76			$	72.17			$	64.02			$	71.77			$	71.43
Natural gas (Mcf)		$	3.95			$	3.53			$	2.33			$	2.12			$	3.47
Natural gas liquids (Bbl)		$	21.32			$	26.83			$	20.76			$	23.53			$	26.70
All Properties
Oil (Bbl)		$	70.81			$	70.50			$	62.45			$	68.49			$	73.10
Natural gas (Mcf)		$	3.66			$	3.13			$	2.31			$	1.86			$	3.15
Natural gas liquids (Bbl)		$	21.15			$	27.95			$	20.90			$	25.22			$	27.50
Average Unit Cost per Boe (6:1):
All Properties
Operating costs, production and ad valorem taxes		$	21.91			$	18.01			$	18.99			$	16.11			$	16.18
Operating costs excluding taxes		$	16.47			$	12.21			$	14.38			$	10.75			$	10.86
Percentage of revenue(2)			34.5	%			27.8	%			33.5	%			26.4	%			16.7	%

(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.

(2) Operating costs per Boe increased in 2025 primarily due to (i) the increased proportion of operated production as compared to royalty production, which carries higher direct operating expenses, (ii) inflationary pressures on field services and disposal costs, and (iii) the integration of newly developed wells into our production base. We expect unit costs to moderate over time as operated production scales and fixed field-level costs are absorbed across a larger production base.

Depletion of Oil and Natural Gas Properties

We account for our oil and gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities, are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves. The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs, as well as the anticipated proceeds from salvaging equipment.

Depletion expense was $60.0 million and $31.3 million for the three months ended March 31, 2026 and 2025, respectively. On a per unit basis, depletion expense was $17.56 per Boe and $17.77 per Boe, for the three months ended March 31, 2026 and 2025, respectively. The decrease in our depletion rate for the three months ended March 31, 2026 compared to 2025 was primarily due to increased proved reserves relative to the change in aggregated proved leasehold and development costs associated with those proved reserves. The depletion rate for the development capital is depleted at a higher rate as compared to leasehold due to the use of proved developed reserves versus total proved reserves under the successful efforts accounting method. We expect overall depletion to continue to increase in subsequent periods as our gross production of oil, gas, and other products increase.

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PV-10

		For the Three Months Ended March 31,								For the Years Ended December 31,
(in thousands)		2026				2025				2025				2024				2023
PV-10 (estimated proved developed reserves)		$	1,479,560			$	751,363			$	1,094,359			$	644,098			$	289,809
PV-10 (estimated proved undeveloped reserves)		$	932,498			$	472,937			$	687,042			$	424,595			$	257,472
PV-10 (estimated total proved reserves)		$	2,412,058			$	1,224,300			$	1,781,401			$	1,068,693			$	547,281

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 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.

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 Three Months Ended March 31,								For the Years Ended December 31,
(in thousands)		2026				2025				2025				2024				2023
Estimated proved developed reserves:
Standardized measure of discounted future net cash flows		$	1,479,560			$	751,363			$	1,094,359			$	644,098			$	289,809
Discounted future income taxes			—				—				—				—				—
PV-10		$	1,479,560			$	751,363			$	1,094,359			$	644,098			$	289,809
Estimated proved undeveloped reserves:
Standardized measure of discounted future net cash flows		$	932,498			$	472,937			$	687,042			$	424,595			$	257,472
Discounted future income taxes			—				—				—				—				—
PV-10		$	932,498			$	472,937			$	687,042			$	424,595			$	257,472
Estimated total proved reserves:
Standardized measure of discounted future net cash flows		$	2,412,058			$	1,224,300			$	1,781,401			$	1,068,693			$	547,281
Discounted future income taxes			—				—				—				—				—
PV-10		$	2,412,058			$	1,224,300			$	1,781,401			$	1,068,693			$	547,281

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Item 6. Exhibits

Incorporated by Reference

Exhibit No.

Description

Form

Date of First Filing

Exhibit Number

Filed Herewith

3.1

Certificate of Formation of Phoenix Energy One, LLC (f/k/a 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

4.1

First Supplemental Indenture, by and between Phoenix Energy One, LLC and UMB Bank, N.A., as trustee, dated March  17, 2026, governing the Registered Notes.

10-K

03/17/2026

4.5

4.2

Fourth Supplemental Indenture, by and between Phoenix Energy One, LLC and UMB Bank, N.A., as trustee, dated as of March 16, 2026, governing the August 2023 506(c) Bonds.

10-K

03/17/2026

4.20

10.1†

Employee Agreement, by and between Phoenix Energy One, LLC and Adam Ferrari, effective as of January 1, 2026.

8-K

01/21/2026

10.1

10.2†

Employee Agreement, by and between Phoenix Energy One, LLC and Curtis Allen, effective as of January 1, 2026.

8-K

01/21/2026

10.2

10.3†

Employee Agreement, by and between Phoenix Energy One, LLC and Lindsey Wilson, effective as of January 1, 2026.

8-K

01/21/2026

10.3

10.4++

Amendment No. 8 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 February 12, 2026.

8-K

02/13/2026

10.1

10.5

Sixth Amendment to Loan Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, and Adamantium Capital LLC, dated as of February 12, 2026.

10-K

03/17/2026

10.26

10.6

Seventh Amendment to Loan Agreement, by and among Phoenix Energy One, LLC, Phoenix Operating LLC, and Adamantium Capital LLC, dated as of March 16, 2026.

10-K

03/17/2026

10.27

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

Certifications of Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*

*

32.2

Certifications of Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*

*

101.INS

Inline 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

Inline XBRL Taxonomy Extension Schema with Embedded Linkbase Documents.

*

104

The cover page for the Company’s Quarterly Report on Form 10-Q has been formatted in Inline XBRL and contained in Exhibit 101.

*

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* Filed herewith.

** Furnished herewith.

++ 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.

† Management contract or compensatory plan or arrangement.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

				PHOENIX ENERGY ONE, LLC
Date: May 13, 2026				By:		/s/ Curtis Allen
						Curtis Allen
						Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature		Title		Date
/s/ Adam Ferrari Adam Ferrari		Chief Executive Officer and Director (Principal Executive Officer)		May 13, 2026
/s/ Curtis Allen Curtis Allen		Chief Financial Officer and Director (Principal Financial Officer and Principal Accounting Officer)		May 13, 2026
/s/ Daniel Glen Ferrari, by Charlene Ferrari, POA Daniel Ferrari by Charlene Ferrari, POA		Director		May 13, 2026
/s/ Jason Allan Pangracs Jason Allan Pangracs		Director		May 13, 2026
/s/ Jason Montgomery Wagner Jason Montgomery Wagner		Director		May 13, 2026

47