UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended ~~September~~December 3031, 2025


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

For the transition period from to

Commission File Number 001-32942

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)


Nevada		41-1781991
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079

(Address of principal executive offices and zip code)

(713) 935-0122

(Registrant’s telephone number, including area code)

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


Title of Each Class	Trading Symbol(s)	Name of Each Exchange On Which Registered
Common Stock, $0.001 par value	EPM	NYSE American

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 definition 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: ☒

At ~~November~~February 76, ~~2025~~2026, 3435,~~690~~003,~~864~~844 shares of the Registrant’s Common Stock, $0.001 par value per share, were outstanding.

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EVOLUTION PETROLEUM CORPORATION

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Forward-Looking Statements		2
PART I.	FINANCIAL INFORMATION	4
Item 1.	Condensed Consolidated Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets (Unaudited) as of ~~September~~December 3031, 2025 and June 30, 2025	4
	Condensed Consolidated Statements of Operations (Unaudited) for the three and six months ended ~~September~~December 3031, 2025 and 2024	5
	Condensed Consolidated Statements of Cash Flows (Unaudited) for the ~~three~~six months ended ~~September~~December 3031, 2025 and 2024	6
	Condensed Consolidated Statements of Changes in Stockholders’ Equity (Unaudited) for the three and six months ended ~~September~~December 3031, 2025 and 2024	7
	Notes to Unaudited Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2425
Item 3.	Quantitative and Qualitative Disclosures about Market Risks	3237
Item 4.	Controls and Procedures	3237
PART II. OTHER INFORMATION		3338
Item 1.	Legal Proceedings	3338
Item 1A.	Risk Factors	3338
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	3439
Item 3.	Defaults Upon Senior Securities	3439
Item 4.	Mine Safety Disclosures	3439
Item 5.	Other Information	3439
Item 6.	Exhibits	3540
	Signatures	3641

We use the terms, “EPM,” “Company,” “we,” “us,” and “our” to refer to Evolution Petroleum Corporation, and unless the context otherwise requires, its wholly-owned subsidiaries.

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FORWARD-LOOKING STATEMENTS

This Form 10-Q and the information referenced herein contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, except for statements of historical fact, are forward-looking statements. The words “plan,” “expect,” “project,” “estimate,” “may,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words or phrases. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors, which may include, but are not limited to, the following:

●

our expectations of plans, strategies and objectives, including anticipated development activity and capital spending;

●

our capital allocation strategy, capital structure, anticipated sources of funding, growth in long-term shareholder value and ability to preserve balance sheet strength;

●

our ability to complete future acquisitions and the need for additional capital to complete future acquisitions;

●

the benefits of our multi-basin portfolio, including operational and commodity flexibility;

●

our ability to maximize cash flow and the application of excess cash flows to pay dividends;

●

estimates of our oil, natural gas and NGLs production and commodity mix;

●

anticipated oil, natural gas and NGL prices;

●

anticipated drilling and completions activity;

● drilling and operational risks by our third-party operators, including accidents, equipment failures, fires, and releases of toxic or hazardous materials;

●

estimates of our oil, natural gas and NGL reserves and recoverable quantities;

●

our ability to access credit facilities and the availability of other sources of liquidity to meet financial obligations throughout commodity price cycles;

●

limitations on our ability to obtain funding based on environmental, social, and corporate governance performance;

●

future interest expense;

●

our ability to manage debt and financial ratios, finance growth and comply with financial covenants;

●

the implementation and outcomes of risk management programs, including exposure to commodity price and interest rate fluctuations, the volume of oil and natural gas production hedged, and the markets or physical sales locations hedged;

●

the possible impact of changes in federal, state, provincial and local, rules and regulations;

●

anticipated compliance with current or proposed environmental requirements, including the costs thereof;

●

the impact of greenhouse gas (“GHG”) emissions limitations and renewable energy incentives;

●

adequacy of provisions for abandonment and site reclamation costs;

●

our operational and financial flexibility, discipline and ability to respond to evolving market conditions;

●

the declaration and payment of future dividends and any anticipated repurchase of our outstanding common shares;

●

the adequacy of our provision for taxes and legal claims;

●

our ability to manage cost inflation and expected cost structures, including expected operating, transportation, processing and labor expenses;

●

our competitiveness relative to our peers, including with respect to capital, materials, people, assets and production;

●

oil, natural gas and NGL inventories and global demand for oil, natural gas and NGLs;

●

the outlook of the oil and natural gas industry generally, including impacts from changes to the geopolitical environment;

●

adverse weather events;

●

anticipated staffing levels;

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●

anticipated payments related to our commitments, obligations and contingencies, and the ability to satisfy the same; and

●

the possible impact of accounting and tax pronouncements, rule changes and standards.

Readers are cautioned against unduly relying on forward-looking statements which, by their nature, involve numerous assumptions and are subject to both known and unknown risks and uncertainties (many of which are beyond our control) that may cause actual events or results to differ materially and/or adversely from those expressed or implied, which include, but are not limited to, the following assumptions:

●

future commodity prices and basis differentials;

●

our ability to access credit facilities and shelf prospectuses;

●

assumptions contained in our corporate guidance;

●

the availability of attractive commodity or financial hedges and the enforceability of risk management programs;

●

expectations that counterparties will fulfill their obligations pursuant to gathering, processing, transportation and marketing agreements;

●

access to adequate gathering, transportation, processing and storage facilities;

●

assumed tax, royalty and regulatory regimes;

●

expectations and projections made in light of, and generally consistent with, our historical experience and our perception of historical industry trends; and

●

the other assumptions contained herein.

Readers are cautioned that the assumptions, risks and uncertainties referenced above, and in the other documents incorporated herein by reference (if any), are not exhaustive. Although we believe the expectations represented by our forward-looking statements are reasonable based on the information available to us as of the date such statements are made, forward-looking statements are only predictions and statements of our current beliefs and there can be no assurance that such expectations will prove to be correct.

When considering any forward-looking statement, the reader should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil, natural gas and NGLs, third-party operating risks and other risk factors as described under the Risk Factors section of our previously filed Annual Report on Form 10-K for the fiscal year ended June 30, 2025, as well as the other disclosures contained herein, therein, and as also may be described from time to time in future reports we file with the Securities and Exchange Commission (“SEC”). Readers should also consider such information in conjunction with our condensed consolidated financial statements and related notes and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations in this report. There also may be other factors that we cannot anticipate or that are not described in this report, generally because we do not currently perceive them to be material. Such factors could cause results to differ materially from our expectations.

Forward-looking statements speak only as of the date they are made, and we do not undertake to update these statements other than as required by law. Readers are advised, however, to review any further disclosures we make on related subjects in our filings with the SEC.

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Part I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

EVOLUTION PETROLEUM CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except share and per share amounts)


	~~September~~December 3031, 2025		June 30, 2025
Assets
Current assets
Cash and cash equivalents	$	~~714~~3,762	$	2,507
Receivables from crude oil, natural gas, and natural gas liquids revenues		89,~~485~~345		10,804
Derivative contract assets		23,~~075~~196		1,777
Prepaid expenses and other current assets		~~1,235~~859		2,287
Total current assets		1217,~~509~~162		17,375
Property and equipment, net of depletion, depreciation, and impairment
Oil and natural gas properties—full-cost method of accounting:
Oil and natural gas properties, subject to amortization, net		~~149~~146,~~934~~476		142,248
Oil and natural gas properties, not subject to amortization		54,~~812~~645		—
Total property and equipment, net		~~155~~151,~~746~~121		142,248

Other noncurrent assets
Derivative contract assets		~~402~~135		198
Other assets		~~474~~847		431
Total assets	$	169,~~131~~265	$	160,252
Liabilities and Stockholders' Equity
Current liabilities
Accounts payable	$	11,~~167~~041	$	12,901
Accrued liabilities and other		5,~~443~~308		6,909
Derivative contract liabilities		1,~~216~~505		1,577
State and federal taxes payable		551,272		—
Total current liabilities		1719,~~881~~126		21,387
Long term liabilities
Senior secured credit facility		5354,~~000~~500		37,500
Deferred income taxes		54,~~848~~935		6,234
Asset retirement obligations		2122,~~928~~309		21,535
Derivative contract liabilities		~~1,343~~465		1,783
Total liabilities		100,000		88,439
Operating lease liability		386		—
Total liabilities		101,721		88,439
Commitments and contingencies (Note 10)
Stockholders' equity
Common stock; par value $0.001; 100,000,000 shares authorized: issued and
outstanding 34,647,751 and 34,337,188 shares as of September 30, 2025
outstanding 35,003,844 and 34,337,188 shares as of December 31, 2025
and June 30, 2025, respectively		35		34
Additional paid-in capital		4748,~~300~~843		46,650
Retained earnings		2118,~~796~~666		25,129
Total stockholders' equity		6967,~~131~~544		71,813
Total liabilities and stockholders' equity	$	169,~~131~~265	$	160,252

See accompanying notes to unaudited condensed consolidated financial statements.

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EVOLUTION PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share amounts)


	Three Months Ended				Six Months Ended
	~~September~~December 3031,				December 31,
	2025		2024		2025		2024
Revenues
Crude oil	$	1210,~~872~~696	$	1411,~~737~~763	$	23,568	$	26,500
Natural gas		57,~~900~~441		45,~~285~~793		13,341		10,078
Natural gas liquids		2,~~516~~542		2,~~874~~719		5,058		5,593
Total revenues		2120,~~288~~679		2120,~~896~~275		41,967		42,171
Operating costs
Lease operating costs		1311,~~087~~510		1112,~~790~~793		24,597		24,583
Depletion, depreciation, and accretion		5,~~961~~919		5,~~725~~433		11,880		11,158
General and administrative expenses		2,~~325~~592		2,~~527~~654		4,917		5,181
Total operating costs		2120,~~373~~021		20,~~042~~880		41,394		40,922
Income (loss) from operations		~~(85)~~658		~~1,854~~(605)		573		1,249
Other income (expense)
Net gain (loss) on derivative contracts		2,~~181~~235		(1,~~798~~219)		4,416		579
Interest and other income		1012		5752		22		109
Interest expense		(~~917~~1,003)		(~~823~~764)		(1,920)		(1,587)
Income (loss) before income taxes		1,~~189~~902		(2,~~886~~536)		3,091		350
Income tax (expense) benefit		(~~365~~837)		~~(821)~~711		(1,202)		(110)
Net income (loss)	$	~~824~~1,065	$	2(1,~~065~~825)	$	1,889	$	240
Net income (loss) per common share:
Basic	$	0.0203	$	(0.06)	$	0.05	$	—
Diluted	$	0.0203	$	(0.06)	$	0.05	$	—
Weighted average number of common shares outstanding:
Basic		33,~~725~~904		32,~~722~~934		33,815		32,828
Diluted		3334,~~977~~025		32,~~868~~934		34,001		32,994

See accompanying notes to unaudited condensed consolidated financial statements.

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EVOLUTION PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)


	~~Three~~Six Months Ended ~~September~~December 3031,
	2025		2024
	2025		2024
Cash flows from operating activities:
Net income (loss)	$	~~824~~1,889	$	~~2,065~~240
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, and accretion		511,~~961~~880		511,~~725~~158
Stock-based compensation		~~537~~1,150		~~559~~1,218
Settlement of asset retirement obligations		(19180)		(98280)
Deferred income taxes		(~~386~~1,299)		(~~281~~29)
Unrealized (gain) loss on derivative contracts		(12,~~303~~746)		(~~1,868~~500)
Accrued settlements on derivative contracts		(~~385~~10)		(6657)
Amortization of debt issuance costs		3978		—
Other		(38)		(23)
Changes in operating assets and liabilities:
Receivables from crude oil, natural gas, and natural gas liquids revenues		21,~~555~~509		(378)
Prepaid expenses and other current assets		1,~~202~~359		~~1,929~~435
Accounts payable, accrued liabilities and other		(1,~~272~~664)		~~(238)~~3,233
State and federal taxes payable		551,272		(74)
Net cash provided by operating activities		713,~~805~~230		715,~~614~~333
Cash flows from investing activities:
Acquisition of oil and natural gas properties		(16,~~867~~647)		(~~262~~331)
Capital expenditures for oil and natural gas properties		(34,~~819~~656)		(23,~~740~~498)
Net cash used in investing activities		(2021,~~686~~303)		(3,~~002~~829)
Cash flows from financing activities:
Common stock dividends paid		(48,~~157~~352)		(48,~~033~~115)
Common stock repurchases, including stock surrendered for tax withholding		(~~132~~182)		(88191)
Borrowings under senior secured credit facility		1720,~~500~~000		—
Repayments of senior secured credit facility		(23,000)		—
Debt issuance costs		(379)		—
Issuance of common stock		~~266~~1,272		—2,259
Offering costs		(1031)		—(236)
Net cash provided by (used in) financing activities		119,~~088~~328		(46,~~121~~283)
Net increase (decrease) in cash and cash equivalents		(1,~~793)~~255		~~491~~5,221
Cash and cash equivalents, beginning of period		2,507		6,446
Cash and cash equivalents, end of period	$	~~714~~3,762	$	611,~~937~~667

Supplemental disclosures of cash flow information:
Non-cash investing and financing transactions:
Increase (decrease) in accrued capital expenditures for oil and natural gas properties	$	(1,~~604~~340)	$	2(1,~~014~~709)
Oil and natural gas property costs attributable to the recognition (derecognition) of asset retirement obligations		(178)		(47)

See accompanying notes to unaudited condensed consolidated financial statements.

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EVOLUTION PETROLEUM CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (Unaudited)

(In thousands)


				Additional						Total
	Common Stock			Paid-in		Retained		Treasury		Stockholders'
	Shares	Par Value		Capital		Earnings		Stock		Equity
For the Three Months Ended September 30, 2025
For the Three Months Ended December 31, 2025
Balances at June 30, 2025	34,337	$	34	$	46,650	$	25,129	$	—	$	71,813
Issuance of restricted common stock	280		1		(1)		—		—		—
Common stock repurchases, including stock surrendered for tax withholding	—		—		—		—		(132)		(132)
Retirements of treasury stock	(26)		—		(132)		—		132		—
Issuance of common stock	57		—		266		—		—		266
Offering costs	—		—		(20)		—		—		(20)
Stock-based compensation	—		—		537		—		—		537
Net income (loss)	—		—		—		824		—		824
Common stock dividends paid	—		—		—		(4,157)		—		(4,157)
Balances at September 30, 2025	34,648	$	35	$	47,300	$	21,796	$	—	$	69,131
Issuance of restricted common stock	121		—		—		—		—		—
Common stock repurchases, including stock surrendered for tax withholding	—		—		—		—		(50)		(50)
Retirements of treasury stock	(11)		—		(50)		—		50		—
Issuance of common stock	246		—		1,006		—		—		1,006
Offering costs	—		—		(26)		—		—		(26)
Stock-based compensation	—		—		613		—		—		613
Net income (loss)	—		—		—		1,065		—		1,065
Common stock dividends paid	—		—		—		(4,195)		—		(4,195)
Balances at December 31, 2025	35,004	$	35	$	48,843	$	18,666	$	—	$	67,544

For the Three Months Ended September 30, 2024
For the Six Months Ended December 31, 2025
Balances at June 30, 2024	33,340	$	33	$	41,091	$	40,003	$	—	$	81,127
Balances at June 30, 2025	34,337	$	34	$	46,650	$	25,129	$	—	$	71,813
Issuance of restricted common stock	~~284~~401		1		(1)		—		—		—
Common stock repurchases, including stock surrendered for tax withholding	—		—		—		—		(88182)		(88182)
Retirements of treasury stock	(1737)		—		(88182)		—		88182		—
Stock-based compensation	—		—		559		—		—		559
Issuance of common stock	303		—		1,272		—		—		1,272
Net income (loss)	—		—		—		2,065		—		2,065
Offering costs	—		—		(46)		—		—		(46)
Common stock dividends paid	—		—		—		(4,033)		—		(4,033)
Stock-based compensation	—		—		1,150		—		—		1,150
Net income (loss)	—		—		—		1,889		—		1,889
Common stock dividends paid	—		—		—		(8,352)		—		(8,352)
Balances at December 31, 2025	35,004	$	35	$	48,843	$	18,666	$	—	$	67,544

For the Three Months Ended December 31, 2024
Balances at September 30, 2024	33,607	$	34	$	41,561	$	38,035	$	—	$	79,630
Issuance of restricted common stock	92		—		—		—		—		—
Forfeitures of restricted stock	(8)		—		—		—		—		—
Common stock repurchases, including stock surrendered for tax withholding	—		—		—		—		(103)		(103)
Retirements of treasury stock	(19)		—		(103)		—		103		—
Issuance of common stock	405		—		2,259		—		—		2,259
Offering costs	—		—		(236)		—		—		(236)
Stock-based compensation	—		—		659		—		—		659
Net income (loss)	—		—		—		(1,825)		—		(1,825)
Common stock dividends paid	—		—		—		(4,082)		—		(4,082)
Balances at December 31, 2024	34,077	$	34	$	44,140	$	32,128	$	—	$	76,302

For the Six Months Ended December 31, 2024
Balances at June 30, 2024	33,340	$	33	$	41,091	$	40,003	$	—	$	81,127
Issuance of restricted common stock	376		1		(1)		—		—		—
Forfeitures of restricted stock	(8)		—		—		—		—		—
Common stock repurchases, including stock surrendered for tax withholding	—		—		—		—		(191)		(191)
Retirements of treasury stock	(36)		—		(191)		—		191		—
Issuance of common stock	405		—		2,259		—		—		2,259
Offering costs	—		—		(236)		—		—		(236)
Stock-based compensation	—		—		1,218		—		—		1,218
Net income (loss)	—		—		—		240		—		240
Common stock dividends paid	—		—		—		(8,115)		—		(8,115)
Balances at December 31, 2024	34,077	$	34	$	44,140	$	32,128	$	—	$	76,302

See accompanying notes to unaudited condensed consolidated financial statements.

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Financial Statement Presentation

Nature of Operations. Evolution Petroleum Corporation (“Evolution,” and together with its consolidated subsidiaries, the “Company”) is an independent energy company focused on maximizing returns to shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States. The Company’s long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties, built through acquisitions and through selective development opportunities, production enhancement, and other exploitation efforts on its oil and natural gas properties.

The Company’s oil and natural gas properties consist of non-operated working and mineral interests in the following areas: the SCOOP and STACK plays of the Anadarko Basin located in central Oklahoma; the Chaveroo Field in Chaves and Roosevelt Counties of New Mexico; the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field located in Hot Springs County, Wyoming, a secondary oil recovery field utilizing water injection wells to pressurize the reservoir; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO₂ enhanced oil recovery project; the TexMex interests located in Lea, Eddy and Chaves Counties, New Mexico and Stephens County, Texas; as well as small overriding royalty interests in four onshore Texas wells.

Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information and the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included. The interim financial information and notes hereto should be read in conjunction with the Company’s 2025 Annual Report on Form 10-K for the fiscal year ended June 30, 2025, as filed with the SEC on September 17, 2025. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year. The Company has evaluated events and transactions through the date of issuance of these unaudited condensed consolidated financial statements.

Principles of Consolidation and Reporting. The unaudited condensed consolidated financial statements include the accounts of Evolution Petroleum Corporation and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The unaudited condensed consolidated financial statements for the previous year may be condensed or include certain reclassifications to conform to the current presentation.

Risk and Uncertainties. The Company’s oil and natural gas interests are operated by third-party operators and involve other third-party working interest owners. As a result, the Company has limited ability to influence the operation or future development of such properties. However, the Company proactively works with its third-party operators to review the management of capital expenditures for its non-operated working interests.

Oil and Natural Gas Properties. The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration, and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs that are directly related to property acquisition, exploration, and development activities, but does not include any costs related to production, general corporate overhead, or similar activities. Oil and natural gas properties include costs that are excluded from depletion and amortization, which represent investments in unproved and unevaluated properties and include non-producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. These costs are excluded until the project is evaluated and proved reserves are established or impairment is determined.

Use of Estimates. The preparation of the Company’s unaudited condensed consolidated financial statements in conformity with GAAP requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

statements and the reported amounts of revenues and expenses during the respective reporting periods. Significant estimates include (a) reserve quantities and estimated future cash flows associated with proved reserves, which may significantly impact depletion expense and potential impairments of oil and natural gas properties, (b) asset retirement obligations, (c) stock-based compensation, (d) fair values of derivative contract assets and liabilities, (e) income taxes and the valuation of deferred income tax assets, (f) commitments and contingencies, and (g) accruals of crude oil, natural gas, and NGL revenues and operating expenses. The Company analyzes estimates and judgments based on historical experience and various other assumptions and information that are believed to be reasonable. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as additional information is obtained, as new events occur, and as the Company’s environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s unaudited condensed consolidated financial statements.

Segment Information. The Company has one reportable segment, which focuses on the ownership of and investment in onshore oil and natural gas properties in the United States. The segment’s revenues are derived from the Company’s interests in the sales of crude oil, natural gas, and NGL production to customers in the United States. The Company evaluates performance based on various financial metrics, including but not limited to consolidated income or loss from operations, net revenue, and cash flow from operations. The Company’s chief executive officer, chief operating officer, and chief financial officer together function as the chief operating decision maker (“CODM”). The CODM manages the Company’s business activities as a single operating segment.

The accounting policies of the one reportable segment are identical to accounting policies described for the consolidated Company. The CODM uses income (loss), as reported in the unaudited condensed consolidated statement of operations to measure segment profitability, assess performance, and manage strategic capital resources allocations. The measure of segment assets is reported as “Total assets” on the unaudited condensed consolidated balance sheets. The significant expense categories regularly provided to and reviewed by the CODM are the expenses categories as noted on the unaudited condensed consolidated statements of operations.

Recently Issued Accounting Pronouncements

In July 2025, the FASB issued ASU 2025-05, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses for Accounts Receivable and Contract Assets (“ASU 2025-05”). ASU 2025-05 permits companies to apply a practical expedient which assumes that current conditions as of the balance sheet date do not change for the remaining life of the asset when developing estimates for credit losses for accounts receivable and contract assets under Topic 606, Revenue from Contracts with Customers. ASU 2025-05 is effective prospectively for annual reporting periods beginning after December 15, 2025, and interim reporting periods within those annual reporting periods, with early adoption permitted. The Company is currently evaluating ASU 2025-05 and the impact it may have on the Company’s financial position, results of operations, cash flow, or disclosures.

In November 2024, the FASB issued ASU 2024-03, Disaggregation of Income Statement Expenses (“ASU 2024-03”). ASU 2024-03 increases the transparency of expense information presented in the statement of operations through disclosures of expanded disaggregation of relevant expense captions, including purchases of inventory, employee compensation, depletion, depreciation, and amortization. ASU 2024-03 is effective for annual periods beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027, with early adoption permitted. The Company is currently evaluating ASU 2024-03 and the impact it may have to the Company’s disclosures.

In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures (“ASU 2023-09”). ASU 2023-09 enhances the transparency of income tax disclosures by expanding the income tax rate reconciliation disclosure and income taxes paid information. ASU 2023-09 also includes certain other amendments to improve the effectiveness of income tax disclosures. ASU 2023-09 is effective for annual periods beginning after December 15, 2024, and can be implemented either prospectively or retrospectively. As such, the Company adopted ASU 2023-09 effective July 1, 2025. The Company will include the applicable enhanced disclosures in its annual financial statements for the fiscal year ended June 30, 2026.

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Other accounting pronouncements that have recently been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations, cash flows, or disclosures.

Note 2. Revenue Recognition

The Company’s revenues are primarily generated from its crude oil, natural gas and NGL production from the SCOOP and STACK plays in central Oklahoma; the Chaveroo Field in Chaves and Roosevelt Counties of New Mexico; the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field in Wyoming; the Delhi Field in Northeast Louisiana; and the TexMex interests located in Lea, Eddy and Chaves Counties, New Mexico and Stephens County, Texas. Additionally, an overriding royalty interest retained in a past divestiture of Texas properties provides de minimis revenue. The following table disaggregates the Company’s revenues by major product for the three and six months ended ~~September~~December 3031, 2025 and 2024 (in thousands):


	Three Months Ended
	September 30,
	2025		2024
Revenues
Crude oil	$	12,872	$	14,737
Natural gas		5,900		4,285
Natural gas liquids		2,516		2,874
Total revenues	$	21,288	$	21,896


		Three Months Ended				Six Months Ended
		December 31,				December 31,
		2025		2024		2025		2024
Revenues
Crude oil		$	10,696	$	11,763	$	23,568	$	26,500
Natural gas			7,441		5,793		13,341		10,078
Natural gas liquids			2,542		2,719		5,058		5,593
Total revenues		$	20,679	$	20,275	$	41,967	$	42,171

In the Jonah Field, the Company has elected to take its natural gas and NGL working interest production in-kind and markets its NGL production to Enterprise Products Partners L.P. (“Enterprise”) and its natural gas production to different purchasers.

The Company does not take production in-kind at any of its other properties and does not negotiate contracts with customers for such production. The Company recognizes crude oil, natural gas, and NGL production revenue at the point in time when custody and title (“control”) of the product transfers to the customer. The sales of oil and natural gas are made under contracts which the Company’s third-party operators of its wells have negotiated with customers, which typically include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. The Company typically receives payment from the sale of oil and natural gas production one to two months after delivery.

Judgments made in applying the guidance in ASC 606, Revenue from Contracts with Customers, relate primarily to determining the point in time when control of products transfers to the customer. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.

The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon the transfer of control of produced hydrocarbons to a customer at a specified delivery point. Consideration is allocated to completed performance obligations at the end of an accounting period.

Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received by field operators one to two months before the Company receives payment and documentation from the operator, which is typical in the oil and natural gas industry. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for the sale of the product. To estimate accounts receivable from operators’ contracts with customers, the Company uses knowledge of its properties, information from field operators, historical ~~performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors. Because~~

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performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors. Because the contractual performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with field operators as “Receivables from crude oil, natural gas, and natural gas liquids revenues” on the unaudited condensed consolidated balance sheets. Differences between estimates and actual amounts received for product sales are recorded in the month that payments received from purchasers are remitted to the Company by field operators.

Note 3. Acquisitions

Purchase of SCOOP/STACK Minerals

On August 4, 2025, the Company completed the acquisition of certain mineral and royalty interests in the SCOOP and STACK plays in of Oklahoma from a non-affiliated private seller (the “Minerals Acquisition”) in a cash transaction valued at approximately $16.93 million, subject to customary post-closing adjustments. The Minerals Acquisition has an effective date of May 1, 2025. The Company accounted for the transaction as an asset acquisition, allocating $11.17 million of the purchase price to proved oil and natural gas properties, subject to amortization, and $54.86 million to unproved properties. The Company funded the purchase price for the Minerals Acquisition with a combination of $15.0 million in borrowings under its Senior Secured Credit Facility and cash on hand. The acquired assets include an average royalty interest of 0.6% across approximately 5,500 net royalty acres located primarily in Grady and Canadian Counties, Oklahoma.

TexMex Acquisition

On April 14, 2025, the Company closed the acquisition of non-operated working interests in certain oil and natural gas wells located primarily in Lea, Eddy, and Chaves Counties, New Mexico, and Stephens County, Texas (the “TexMex Acquisition”) from a private seller. The total purchase price for the TexMex Acquisition was approximately $9.0 million before customary post-closing adjustments, with an effective date of February 1, 2025. The Company funded the purchase price for the TexMex Acquisition through a combination of cash on hand and borrowings under its Senior Secured Credit Facility. The TexMex Acquisition includes an average working interest of 42% and an average revenue interest of 35% in approximately 600 gross wells.

Note 4. Property and Equipment

Property and equipment consisted of the following for the periods presented (in thousands):


	~~September~~December 3031, 2025		June 30, 2025
Oil and natural gas properties
Property costs subject to amortization	$	~~285~~287,~~742~~816	$	272,496
Property costs not subject to amortization		54,~~812~~645		—
Less: Accumulated depletion, depreciation, and impairment		(~~135~~141,~~808~~340)		(130,248)
Oil and natural gas properties, net	$	~~155~~151,~~746~~121	$	142,248

As of ~~September 30~~December 31, 2025, $54.86 million of oil and natural gas property costs were not subject to amortization. These costs related to mineral and royalty interests acquired as part of the Company’s Minerals Acquisition described in Note 3, “Acquisitions” above. The mineral and royalty interests include approximately 3,600 net royalty acres for unproved locations. Property costs identified at the Minerals Acquisition associated with proved reserves were recorded to evaluated oil and natural gas properties and subject to amortization.

The Company uses the full cost method of accounting for its investments in oil and natural gas properties. All costs of acquisition, exploration, and development of oil and natural gas reserves are capitalized as the cost of oil and natural gas properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs would be charged to expense as a write-down of oil and natural gas properties.

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Additionally, the Company assesses all properties classified as unproved property on a quarterly basis for possible impairment. The Company assesses properties on an individual basis or as a group, if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and the full cost ceiling test limitation.

Depletion on oil and natural gas properties was $511.61 million and $510.3 million for the ~~three~~six months ended ~~September~~December 3031, 2025 and 2024, respectively. During the ~~three~~six months ended ~~September~~December 3031, 2025 and 2024, the Company incurred development capital expenditures of $12.95 million and $12.02 million, respectively.

At ~~September~~December 3031, 2025, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended ~~September~~December 3031, 2025 of the West Texas Intermediate (“WTI”) crude oil spot price of $6866.0701 per barrel and Henry Hub natural gas spot price of $3.1140 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $23.8922, which was based on historical differentials to WTI as NGLs do not have any single comparable reference index price. Using these prices, at ~~September~~December 3031, 2025 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, subject to amortization, and, as a result, no write-down was applicable.

At ~~September~~December 3031, 2024, the ceiling test value of the Company’s reserves was calculated based on the first-day-of the month average for the 12-months ended ~~September~~December 3031, 2024 of the WTI crude oil spot price of $7976.4032 per barrel and Henry Hub natural gas spot price of $2.2113 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $2322.6360, which was based on historical prices received as NGLs do not have any single comparable reference index price. Using these prices, at ~~September~~December 3031, 2024 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, subject to amortization, and, as a result, no write-down was applicable.

Note 5. Senior Secured Credit Facility

On April 11, 2016, the Company entered into a senior secured reserve-based credit facility with MidFirst Bank in an amount up to $50.0 million. On June 30, 2025, the Company entered into a syndicated amended and restated senior secured reserve-based credit facility (the “Senior Secured Credit Facility”) with MidFirst Bank, as administrative agent for the lenders party, thereto, in an amount up to $200.0 million with an initial and current borrowing base of $65.0 million, maturing on June 30, 2028. The borrowing base will be redetermined semiannually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The Senior Secured Credit Facility carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Senior Secured Credit Facility will bear interest, at the Company’s option, at either (i) the Secured Overnight Financing Rate (“SOFR”), subject to a minimum SOFR of 3.25%, plus a credit spread adjustment of 0.05%, or (ii) the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%, plus, in either case of (i) or (ii), an applicable margin of 2.75%.

The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Secured Credit Facility without premium or penalty. Amounts outstanding under the Senior Secured Credit Facility are guaranteed by the Company’s direct and indirect subsidiaries and secured by a security interest in substantially all of the properties of the Company and its subsidiaries. Borrowings under the Senior Secured Credit Facility may be used for the acquisition and for the drilling and development of oil and natural gas properties, investments in cash flow generating properties complimentary to the production of oil and natural gas, and for letters of credit or other general corporate purposes.

The Senior Secured Credit Facility contains certain events of default, including non-payment; breaches of representation and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary

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bankruptcy; judgments and change in control. The Senior Secured Credit Facility also contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (i) a maximum total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. In addition, the Senior Secured Credit Facility contains hedging requirements that apply when utilization is greater than 25% of (x) the Margined Collateral Value, as defined under the Senior Secured Credit Facility, at any time when the leverage ratio is less than 2.25 to 1.00, or (y) the borrowing base, at any time when the leverage ratio is greater than or equal to 2.25 to 1.00. As of ~~September~~December 3031, 2025, the Company had $5354.05 million borrowings outstanding and $0.8 million of letters of credit outstanding under its Senior Secured Credit Facility, resulting in $119.27 million of available borrowing capacity. For the ~~three~~six months ended ~~September~~December 3031, 2025 and 2024, the weighted average interest on borrowings under the Senior Secured Credit Facility was 76.1288% and 87.0980%, respectively. ~~As of September 30, 2025, the Company is in compliance with all covenants under the Senior Secured Credit Facility.~~

On ~~August~~November 2928, 2025, the Company entered into ana ~~amendment~~letter ofagreement ~~its Senior Secured Credit Facility~~ with MidFirst Bank, ~~wherein~~pursuant itto ~~was~~which ~~determined~~Margined ~~for~~Collateral ~~purposes~~Value, ofas ~~the~~defined ~~hedge~~under ~~covenant~~the ~~that~~Senior ~~total~~Secured ~~crude~~Credit, ~~oil~~was ~~and~~modified ~~natural~~to ~~gas~~$65.0 ~~volumes~~million ~~from~~and ~~proved~~allowed ~~developed~~the ~~producing~~Company ~~reserves~~until ~~will~~December be31, ~~combined~~2025 onto aenter ~~barrels~~into ofadditional ~~oil~~commodity ~~equivalent~~hedge ~~basis~~transactions to ~~determine~~satisfy ~~compliance with~~ the ~~required~~level of hedging ~~covenant~~requirements.

~~The~~On August 29, 2025, the Company ~~capitalizes~~entered ~~certain~~into ~~direct~~the ~~costs~~first ~~associated~~amendment ~~with~~of its Senior Secured Credit Facility ~~and~~with ~~amortizes~~MidFirst ~~these~~Bank ~~costs~~pursuant ~~over~~to ~~the~~which ~~life~~it ofwas ~~the~~determined ~~facility.~~for ~~For~~purposes ~~the~~of ~~three months ended September 30, 2025,~~ the ~~Company~~hedge ~~amortized~~covenant ~~less~~that ~~than~~total ~~$0.1~~crude ~~million~~oil and ~~capitalized~~natural ~~$0.1 million~~gas ofvolumes ~~debt~~from ~~issuance~~proved ~~costs~~developed inproducing ~~conjunction~~reserves ~~with~~will ~~amending~~be ~~and~~combined ~~restating~~on ~~the~~a ~~Senior~~barrels ~~Secured~~of ~~Credit~~oil ~~Facility.~~equivalent ~~The~~basis ~~debt~~to ~~issuance~~determine ~~costs~~compliance ~~are~~with ~~presented in "Other Assets" on~~ the ~~unaudited~~required ~~condensed~~hedging ~~consolidated balance sheets~~covenant.

As of December 31, 2025, the Company is in compliance with all covenants under the Senior Secured Credit Facility.

The Company capitalizes certain direct costs associated with its Senior Secured Credit Facility and amortizes these costs over the life of the facility. For the six months ended December 31, 2025, the Company amortized less than $0.1 million and capitalized $0.1 million of debt issuance costs in conjunction with amending and restating the Senior Secured Credit Facility. The debt issuance costs are presented in "Other assets" on the unaudited condensed consolidated balance sheets.

Note 6. Income Taxes

The Company files a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.

There were no unrecognized tax benefits, nor any accrued interest or penalties associated with unrecognized tax benefits during the periods presented in the unaudited condensed consolidated financial statements. The Company believes that it has appropriate support for the income tax positions taken and to be taken on the Company’s tax returns and that the accruals for tax liabilities are adequate for all open years based on its assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations for the fiscal years ended June 30, 2021 through June 30, 2024 for federal tax purposes and for the fiscal years ended June 30, 2020 through June 30, 2024 for state tax purposes. To the extent the Company utilizes net operating losses (“NOLs”) generated in earlier years, such earlier years may also be subject to audit.

On July 4, 2025, President Trump signed into law the One Big Beautiful Bill Act ("OBBBA"). The OBBBA makes permanent key elements of the Tax Cuts and Jobs Act of 2017, including 100% bonus depreciation and the business interest expense limitation, as well as other provisions. The Company’s consolidated financial statements for the ~~three~~six months ended ~~September 30~~December 31, 2025, include the OBBBA’s effect for the period beginning July 1, 2025, through ~~September 30~~December 31, 2025. Some of the provisions in the OBBBA are effective for periods before July 1, 2025. The Company plans to file its June 30, 2025 tax return on or before April 15, 2026, and thus any tax effects related to prior periods will be recorded in the financial statements as a return to provision adjustment once identified and quantifiable. While the ~~Company does not expect the OBBBA to have a material impact on its results of operations, it does expect the OBBBA to provide a benefit to its cash flows from operating activities.~~

For the three months ended September 30, 2025, the Company recognized an income tax expense of $0.4 million and had an effective tax rate of 30.7% compared to income tax expense of $0.8 million and an effective tax rate of 28.4% for the three months ended September 30, 2024.

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Company does not expect the OBBBA to have a material impact on its results of operations, it does expect the OBBBA to provide a benefit to its cash flows from operating activities.

For the six months ended December 31, 2025, the Company recognized an income tax expense of $1.2 million and had an effective tax rate of 38.9% compared to income tax expense of $0.1 million and an effective tax rate of 31.4% for the six months ended December 31, 2024. The increase in the effective tax rate from the prior year period is due to projected higher state income taxes in Oklahoma associated with the Minerals Acquisition in August 2025. The Company evaluates its tax provision on a quarterly basis and adjusts it effective tax rate given changes in facts and circumstances expected in the future.

The Company’s effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the states of Louisiana, North Dakota, Oklahoma and Texas, due to percentage depletion in excess of basis, and other permanent differences. For both periods, the respective statutory federal tax rate was 21%.

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

Note 7. Derivatives

The Company is exposed to certain risks relating to its ongoing business operations, including commodity price risk and interest rate risk. In accordance with the Company’s strategy and the requirements under the Senior Secured Credit Facility (as discussed in Note 5, “Senior Secured Credit Facility”), it may hedge or may be required to hedge a varying portion of anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the unaudited condensed consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the unaudited condensed consolidated statements of operations for the period in which the change occurs. The Company’s hedge strategies and objectives may change significantly as its operational profile changes or as required under the Senior Secured Credit Facility. The Company does not enter into derivative contracts for speculative trading purposes.

It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of ~~September~~December 3031, 2025, the Company did not post collateral under any of its derivative contracts during the periods in which contracts were open as they were secured under the Company’s Senior Secured Credit Facility.

When the Company utilizes commodity derivative contracts, it expects to enter into deferred premium puts, costless put/call collars including two-way and three-way collars, fixed-price swaps, and/or basis swaps to hedge a portion of its anticipated future production. A two-way costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract, and a purchased put that establishes a minimum price. Three-way collars are designed to establish a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) for the volumes under contract. Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for the volumes under contract. Basis swaps effectively lock in a price differential between regional prices (i.e., Inside FERC’s Northwest Pipeline Corp Rocky Mountains) where the product is sold and the relevant pricing index under which the natural gas production is hedged (i.e., NYMEX Henry Hub). The Company may, from time to time, restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts. The Company has elected not to designate its open derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of the derivative contracts and all payments and receipts on settled derivative contracts in “Net gain (loss) on derivative contracts” on the unaudited condensed consolidated statements of operations.

All derivative contracts are recorded at fair market value in accordance with ASC 815, Derivatives and Hedging (“ASC 815”) and ASC 820, Fair Value Measurement (“ASC 820”) and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The “Derivative contract assets” and “Derivative contract liabilities” represent the difference between the market commodity prices and the hedged prices for the remaining volumes of production hedges as of September 30, 2025 and June 30, 2025 (the “mark-to-market valuation”).

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~~The~~the ~~following~~difference ~~table~~between ~~summarizes~~ the ~~location~~market ~~and~~commodity ~~fair~~prices ~~value~~and ~~amounts~~the ofhedged ~~all~~prices ~~derivative~~for ~~contracts in~~ the ~~unaudited~~remaining ~~condensed~~volumes ~~consolidated~~of ~~balance~~production ~~sheets~~hedges as of ~~September~~December 3031, 2025 and June 30, 2025 (inthe ~~thousands):~~“mark-to-market valuation”).

The following table summarizes the location and fair value amounts of all derivative contracts in the unaudited condensed consolidated balance sheets as of December 31, 2025 and June 30, 2025 (in thousands):


Derivatives not designated
as hedging contracts	Balance sheet	Derivative Contract Assets				Balance sheet	Derivative Contract Liabilities
under ASC 815	location	December 31, 2025		June 30, 2025		location	December 31, 2025		June 30, 2025
Commodity contracts	Current assets - derivative contract assets	$	3,196	$	1,777	Current liabilities - derivative contract liabilities	$	1,505	$	1,577
Commodity contracts	Other noncurrent assets - derivative contract assets		135		198	Long term liabilities - derivative contract liabilities		465		1,783
Total derivatives not designated as hedging contracts under ASC 815		$	3,331	$	1,975		$	1,970	$	3,360


Derivatives not designated
as hedging contracts	Balance sheet	Derivative Contract Assets				Balance sheet	Derivative Contract Liabilities
under ASC 815	location	September 30, 2025		June 30, 2025		location	September 30, 2025		June 30, 2025
Commodity contracts	Current assets - derivative contract assets	$	2,075	$	1,777	Current liabilities - derivative contract liabilities	$	1,216	$	1,577
Commodity contracts	Other noncurrent assets - derivative contract assets		402		198	Long term liabilities - derivative contract liabilities		1,343		1,783
Total derivatives not designated as hedging contracts under ASC 815		$	2,477	$	1,975		$	2,559	$	3,360

The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s unaudited condensed consolidated statements of operations for the three and six months ended December 31, 2025 and 2024 (in thousands). “Realized gain (loss) on derivative contracts” represents all receipts (payments) on derivative contracts settled during the period. “Unrealized gain (loss) on derivative contracts” represents the net change in the mark-to-market valuation of the derivative contracts.

The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s unaudited condensed consolidated statements of operations for the three months ended September 30, 2025 and 2024 (in thousands). “Realized gain (loss) on derivative contracts” represents all receipts (payments) on derivative contracts settled during the period. “Unrealized gain (loss) on derivative contracts” represents the net change in the mark-to-market valuation of the derivative contracts.


Derivatives not designated	Location of gain (loss)	Three Months Ended				Six Months Ended
as hedging contracts	recognized in income on	December 31,				December 31,
under ASC 815	derivative contracts	2025		2024		2025		2024
Commodity contracts:
Realized gain (loss) on derivative contracts	Other income and expenses - net gain (loss) on derivative contracts	$	792	$	149	$	1,670	$	79
Unrealized gain (loss) on derivative contracts	Other income and expenses - net gain (loss) on derivative contracts		1,443		(1,368)		2,746		500
Total net gain (loss) on derivative contracts		$	2,235	$	(1,219)	$	4,416	$	579


Derivatives not designated	Location of gain (loss)	Three Months Ended
as hedging contracts	recognized in income on	September 30,
under ASC 815	derivative contracts	2025		2024
Commodity contracts:
Realized gain (loss) on derivative contracts	Other income and expenses - net gain (loss) on derivative contracts	$	878	$	(70)
Unrealized gain (loss) on derivative contracts	Other income and expenses - net gain (loss) on derivative contracts		1,303		1,868
Total net gain (loss) on derivative contracts		$	2,181	$	1,798

As of December 31, 2025, the Company had the following open crude oil and natural gas derivative contracts:


			Volumes in	Weighted Average Price per MMBTU/BBL
Period	Commodity	Instrument	MMBTU/BBL	Swap		Sub Floor		Floor		Ceiling
January 2026 - September 2026	Crude Oil	Fixed-Price Swap	186,513	$	60.27
January 2027 - January 2027	Crude Oil	Fixed-Price Swap	14,375		57.05
January 2026 - December 2026	Crude Oil	Two-Way Collar	177,762					$	57.62	$	67.12
September 2026 - December 2026	Crude Oil	Three-Way Collar	67,002			$	50.00		58.83		70.36
January 2026 - December 2026	Natural Gas	Fixed-Price Swap	2,954,267		3.62
January 2027 - December 2027	Natural Gas	Fixed-Price Swap	1,430,858		3.57
January 2026 - December 2026	Natural Gas	Two-Way Collar	2,857,522						3.58		4.83
January 2027 - March 2027	Natural Gas	Two-Way Collar	234,698						3.75		6.07

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

AsSubsequent ofto ~~September 30~~December 31, 2025, the Company ~~had~~entered into the following ~~open~~new crude oil and natural gas derivative contracts:

Volumes in

Weighted Average Price per MMBTU/BBL

Period

Commodity

Instrument

MMBTU/BBL

Swap

Sub Floor

Floor

Ceiling

February 2026 - March 2026

Crude Oil

Fixed-Price Swap

9,323

60.35

January 2027 - March 2027

Crude Oil

Fixed-Price Swap

35,262

60.88

January 2027 - March 2027

Crude Oil

Two-Way Collar

41,364

53.26

63.27

January 2027 - February 2027

Natural Gas

Two-Way Collar

509,946

3.69

5.82


				Swap Price		Sub Floor		Floor Price		Ceiling Price
			Volumes in		per	Price per		per		per
Period	Commodity	Instrument	MMBTU/BBL	MMBTU/BBL		MMBTU/BBL		MMBTU/BBL		MMBTU/BBL
October 2025 - December 2025	Crude Oil	Fixed-Price Swap	5,895	$	72.00
October 2025 - December 2025	Crude Oil	Fixed-Price Swap	39,893		71.40
October 2025 - December 2025	Crude Oil	Fixed-Price Swap	9,157		61.02
October 2025 - June 2026	Crude Oil	Fixed-Price Swap	43,656		61.00
April 2026 - June 2026	Crude Oil	Fixed-Price Swap	17,106		60.40
April 2026 - September 2026	Crude Oil	Fixed-Price Swap	25,412		62.00
October 2025 - December 2025	Crude Oil	Two-Way Collar	10,258					$	60.00	$	63.00
October 2025 - December 2025	Crude Oil	Two-Way Collar	2,404						60.00		63.50
October 2025 - August 2026	Crude Oil	Two-Way Collar	69,646						60.00		65.55
January 2026 - March 2026	Crude Oil	Two-Way Collar	43,493						60.00		75.80
September 2026 - December 2026	Crude Oil	Three-Way Collar	40,872			$	50.00		60.00		70.45
October 2025 - December 2026	Natural Gas	Fixed-Price Swap	2,090,828		3.60
October 2025 - December 2027	Natural Gas	Fixed-Price Swap	2,921,728		3.57
July 2026 - December 2026	Natural Gas	Fixed-Price Swap	207,366		3.98
October 2025 - December 2025	Natural Gas	Two-Way Collar	222,725						4.00		4.95
October 2025 - December 2025	Natural Gas	Two-Way Collar	25,028						2.90		3.50
January 2026 - March 2026	Natural Gas	Two-Way Collar	213,251						4.00		5.39
January 2026 - March 2026	Natural Gas	Two-Way Collar	375,481						3.60		5.00
January 2026 - March 2026	Natural Gas	Two-Way Collar	76,177						3.50		4.66
April 2026 - October 2026	Natural Gas	Two-Way Collar	952,588						3.50		4.55
September 2026 - December 2026	Natural Gas	Two-Way Collar	318,964						3.75		4.94

Subsequent to September 30, 2025, the Company entered into the following new crude oil and natural gas derivative contracts:

Swap Price

Sub Floor

Floor Price

Ceiling Price

Volumes in

per

Price per

per

Period

Commodity

Instrument

MMBTU/BBL

January 2026 - September 2026

Crude Oil

Fixed-Price Swap

83,498

60.00

April 2026 - December 2026

Crude Oil

Two-Way Collar

49,215

55.00

63.65

July 2026 - December 2026

Crude Oil

Two-Way Collar

35,427

55.00

63.50

October 2026 - December 2026

Crude Oil

Three-Way Collar

26,130

50.00

57.00

70.22

January 2026 - December 2026

Natural Gas

Two-Way Collar

578,214

3.50

4.44

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Company presents the fair value of its derivative contracts at the gross amounts in the unaudited condensed consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts for the periods presented (in thousands):


	Derivative Contracts Assets				Derivative Contracts Liabilities
Offsetting of Derivative Assets and Liabilities	~~September~~December 3031, 2025		June 30, 2025		~~September~~December 3031, 2025		June 30, 2025
Gross amounts presented in the Consolidated Balance Sheet	$	23,~~477~~331	$	1,975	$	21,~~559~~970	$	3,360
Amounts not offset in the Consolidated Balance Sheet		(1,~~619~~640)		(1,774)		(1,~~619~~640)		(1,774)
Net amount	$	~~858~~1,691	$	201	$	~~940~~330	$	1,586

The Company enters into an International Swap Dealers Association Master Agreements (“ISDA”) with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

Note 8. Fair Value Measurement

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.

The three levels are defined as follows:

Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2—Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3—Unobservable inputs for which there are little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Fair Value of Derivative Instruments. The Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s unaudited condensed consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable (Level 1) market corroborated (Level 2), or generally unobservable (Level 3). The Company classifies fair value balances based on observability of those inputs.

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

any period presented in this report. The following table, set forth by level within the fair value hierarchy, shows the Company’s financial assets and liabilities that were accounted for at fair value for the periods presented (in thousands).


	September 30, 2025
	Level 1		Level 2		Level 3		Total
Assets
Derivative contract assets	$	—	$	2,477	$	—	$	2,477

Liabilities
Derivative contract liabilities	$	—	$	2,559	$	—	$	2,559

As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgement and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented in this report. The following table, set forth by level within the fair value hierarchy, shows the Company’s financial assets and liabilities that were accounted for at fair value for the periods presented (in thousands).

~~June~~December 3031, 2025

Level 1

Level 2

Level 3

Total

Assets

Derivative contract assets

—

13,~~975~~331

—

13,~~975~~331

Liabilities

Derivative contract liabilities

—

31,~~360~~970

—

31,~~360~~970


	June 30, 2025
	Level 1		Level 2		Level 3		Total
Assets
Derivative contract assets	$	—	$	1,975	$	—	$	1,975

Liabilities
Derivative contract liabilities	$	—	$	3,360	$	—	$	3,360

Derivative contracts listed above as Level 2 include fixed-price swaps and costless put/call collars that are carried at fair value. The Company records the net change in fair value of these positions in “Net gain (loss) on derivative contracts” in the Company’s unaudited condensed consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 7, “Derivatives,” for additional discussion of derivatives.

The Company’s derivative contracts are with large utilities with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not expect such nonperformance.

Other Fair Value Measurements. The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s Senior Secured Credit Facility approximates carrying value because the interest rates approximate current market rates.

The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial measurement and any subsequent revision of asset retirement obligations (“ARO”) for which fair value is calculated using discounted future cash flows derived from historical costs and management’s expectations of future cost environments. Significant Level 3 inputs used in the calculation of ARO include the costs of plugging and abandoning wells, surface restoration, and reserve lives. Subsequent to initial recognition, revisions to estimated asset retirement obligations are made when changes occur for input values. See Note 9, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s ARO.

~~Note 9. Asset Retirement Obligations~~17

The Company’s ARO represents the estimated present value of the amount expected to be incurred to plug, abandon, and remediate its oil and natural gas properties at the end of their productive lives in accordance with applicable laws and regulations. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~capitalizes the cost in “Oil and natural gas properties, subject to amortization, net” during the period in which the obligation is incurred~~Note 9. ~~The~~Asset ~~Company~~Retirement ~~records the accretion of its ARO liabilities in “Depletion, depreciation and accretion” expense in the unaudited condensed consolidated statements of operations.~~ Obligations

The ~~following~~Company’s isARO arepresents ~~reconciliation~~the estimated present value of the ~~activity~~amount ~~related~~expected to be incurred to plug, abandon, and remediate its oil and natural gas properties at the end of their productive lives in accordance with applicable laws and regulations. The Company’s records the ARO liability ~~(inclusive~~on ofthe unaudited condensed consolidated balance sheets and capitalizes the ~~current~~cost ~~portion)~~in ~~for~~“Oil and natural gas properties, subject to amortization, net” during the period ~~ended~~in ~~September 30~~which the obligation is incurred. The Company records the accretion of its ARO liabilities in “Depletion, ~~2025~~ (depreciation and accretion” expense in ~~thousands):~~the unaudited condensed consolidated statements of operations.


	September 30, 2025
Asset retirement obligations — beginning of period	$	21,830
Liabilities settled and divested		(41)
Accretion of discount		401
Asset retirement obligations — end of period		22,190
Less: current asset retirement obligations		(262)
Long-term portion of asset retirement obligations	$	21,928

The following is a reconciliation of the activity related to the Company’s ARO liability (inclusive of the current portion) for the period ended December 31, 2025 (in thousands):


		December 31, 2025
Asset retirement obligations — beginning of period		$	21,830
Liabilities settled and divested			(178)
Accretion of discount			788
Asset retirement obligations — end of period			22,440
Less: current asset retirement obligations			(131)
Long-term portion of asset retirement obligations		$	22,309

Note 10. Commitments and Contingencies

The Company is subject to various claims and contingencies in the normal course of business. In addition, from time to time, the Company receives communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdictions in which the Company operates. The Company discloses such matters if it believes there is a reasonable possibility that a future event or events will confirm a material loss through impairment of an asset or the incurrence of a material liability. The Company accrues a material loss if it believes it probable that a future event or events will confirm a loss and the loss is reasonably subject to estimation. Furthermore, the Company will disclose any matter that is unasserted if it considers it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable and material in amount. The Company expenses legal defense costs as they are incurred.

Note 11. Stockholders’ Equity

Common Stock

As of ~~September~~December 3031, 2025, the Company had 3435,~~647~~003,~~751~~844 shares of common stock outstanding.

The Company began paying quarterly cash dividends on common stock in December 2013. As of ~~September~~December 3031, 2025, the Company has cumulatively paid over $~~139~~143.01 million in cash dividends. The Company paid dividends of $48.24 million and $48.01 million to its common stockholders during the ~~three~~six months ended ~~September~~December 3031, 2025 and 2024, respectively.

The following table reflects the dividends paid per share within the respective three-month periods:


	Fiscal Year
	2026		2025
First fiscal quarter	$	0.120	$	0.120
Second fiscal quarter	$	0.120	$	0.120
First fiscal quarter		0.120		0.120

On October 21, 2024, the Company entered into an At-the-Market (“ATM”) equity Sales Agreement (the “ATM Sales Agreement”) with Roth Capital Partners, LLC (the “Lead Agent”), Northland Securities Inc., and A.G.P./Alliance Global Partners pursuant to which the Company may issue and sell, from time to time, up to $30.0 million of shares of common stock through or to the Lead Agent, acting as agent or principal to facilitate acquisitions and other general corporate purposes. During the ~~three~~six months ended ~~September~~December 3031, 2025, the Company sold a total of approximately 570.3 ~~thousand~~million shares of its common stock under the ATM Sales Agreement for net proceeds of approximately $~~246~~1.2 ~~thousand~~million, net ~~of $20 thousand of offering costs. The Company intends to use the net proceeds from sales of common stock for general corporate purposes, including to repay outstanding indebtedness.~~

On September 8, 2022, the Board of Directors approved a share repurchase program, under which the Company was authorized to repurchase up to $25.0 million of its common stock in the open market through December 31, 2024. The Company funded repurchases from working capital and cash provided by operating activities. The share repurchase 18

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~program~~of ~~was~~$46 ~~complimentary~~thousand toof ~~the~~offering ~~existing dividend policy and was a tax efficient means to further improve shareholder return~~costs. The ~~shares were repurchased in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The~~ Company ~~did~~intends ~~not~~to ~~repurchase~~use ~~any shares of common stock under~~ the ~~plan~~net ~~during~~proceeds ~~the~~from ~~three~~sales ~~months ended September 30, 2024. While the plan was in effect, a total~~ of ~~0.8 million shares of the Company’s~~ common stock ~~were~~for ~~repurchased~~general ~~under~~corporate ~~the program at a total cost of approximately $4.6 million~~purposes, including ~~incremental~~to ~~direct~~repay ~~transaction~~outstanding ~~costs~~indebtedness.

~~During~~On September 8, 2022, the ~~three~~Board ~~months~~of ~~ended~~Directors ~~September 30, 2025~~approved ~~and~~a ~~2024~~share repurchase program, under which the Company ~~acquired~~was ~~treasury~~authorized to repurchase up to $25.0 million of its common stock ~~upon~~in the ~~ordinary~~open ~~course~~market ofthrough ~~scheduled~~December ~~vestings~~31, of2024. ~~employee~~The ~~stock-based~~Company ~~awards~~funded repurchases from working capital and cash provided by operating activities. The share repurchase program was complimentary to ~~fund~~the ~~payroll~~existing dividend policy and was a tax ~~withholding~~efficient ~~obligations.~~means ~~These~~to ~~treasury~~further improve shareholder return. The shares were ~~subsequently~~repurchased ~~cancelled~~in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. ~~Such~~The Company did not repurchase any shares ~~were~~of ~~valued~~common atstock ~~fair~~under ~~market~~the ~~value~~plan onduring the ~~date~~six months ended December 31, 2024. While the plan was in effect, a total of ~~vesting~~0.8 million shares of the Company’s common stock were repurchased under the program at a total cost of approximately $4.6 million, including incremental direct transaction costs.

During the six months ended December 31, 2025 and 2024, the Company acquired treasury stock upon the ordinary course of scheduled vestings of employee stock-based awards to fund payroll tax withholding obligations. These treasury shares were subsequently cancelled. Such shares were valued at fair market value on the date of vesting.

The following table summarizes all treasury stock purchases during the periods presented (in thousands, except per share amounts):


	~~Three~~Six Months Ended
	~~September~~December 3031,
	2025		2024
Number of treasury shares acquired		2637		1736
Average cost per share	$	54.1693	$	5.1532
Total cost of treasury shares acquired	$	~~132~~182	$	88191

Expected Tax Treatment of Dividends

For the fiscal year ended June 30, 2025, all common stock dividends for that fiscal year were treated for tax purposes as qualified dividend income to the recipients. Based on its current projections for the fiscal year ended June 30, 2026, the Company expects all common stock dividends for such period to be treated as qualified dividend income to the recipients. Such projections are based on the Company’s reasonable expectations as of ~~September~~December 3031, 2025 and are subject to change based on the Company’s final tax calculations at the end of the fiscal year.

Stock-Based Incentive Plan

The Evolution Petroleum Corporation 2016 Equity Incentive Plan (as amended the “2016 Plan”) authorizes the issuance of 3.6 million shares of common stock prior to its expiration on December 8, 2026. On December 5, 2024 shareholders approved and adopted the amendment and restatement of the 2016 Plan (hereinafter the “Amended and Restated Plan”), which increased the shares authorized for issuance under the 2016 Plan by 2.1 million shares to a maximum of 5.7 million shares. The duration of the Amended and Restated Plan is indefinite, provided that no new awards shall be made under the Amended and Restated Plan on or after the tenth anniversary of the date the stockholders approved the Amended and Restated Plan. Incentives under the Amended and Restated Plan may be granted to employees, directors, and consultants of the Company in any one or a combination of the following forms: incentive stock options, non-qualified stock options, stock appreciation rights, restricted awards, and performance share awards. As of ~~September~~December 3031, 2025 and June 30, 2025, approximately 2.21 million shares and 2.5 million shares, respectively, remained available for grant under the Amended and Restated Plan.

The Company estimates the fair value of stock-based compensation awards on the grant date to provide the basis for future compensation expense. During the three and six months ended ~~September~~December 3031, 2025, the Company recognized $0.6 million and $1.2 million, respectively, related to stock-based compensation. During the three and six months ended December 31, 2024, the Company recognized $0.57 million and $01.62 million, respectively, related to stock-based compensation. Stock-based compensation expense is recorded as a component of “General and administrative expenses” on the unaudited condensed consolidated statements of operations.

~~Time-Vested Restricted Stock Awards~~19

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~generally have one~~Time-~~year~~Vested ~~cliff~~Restricted ~~vesting.~~Stock For such awards, grant date fair value is based on market value of the Company’s common stock at the time of grant. This value is then amortized ratably over the service period. Previously recognized amortization expense subsequent to the last vesting date of an award is reversed in the event that the holder has no longer rendered service to the Company resulting in forfeiture of the award.Awards

Time-vested restricted stock awards contain service-based vesting conditions and expire after a maximum of four years from the date of grant if unvested. The common shares underlying these awards are issued on the date of grant and participate in dividends paid by the Company. These service-based awards vest with continuous employment by the Company, generally in annual installments over terms of three to four years. Awards to the Company’s directors generally have one-year cliff vesting. For such awards, grant date fair value is based on market value of the Company’s common stock at the time of grant. This value is then amortized ratably over the service period. Previously recognized amortization expense subsequent to the last vesting date of an award is reversed in the event that the holder has no longer rendered service to the Company resulting in forfeiture of the award.

Performance-Based Restricted Stock Awards and Performance-Based Contingent Stock Units

Performance-based restricted stock awards and performance-based contingent stock units contain market-based vesting conditions based on the price of the Company’s common stock compared to the performance of the common stock of its peers. The common shares underlying the Company’s performance-based restricted stock awards are issued on the date of grant and participate in dividends paid by the Company and expire after a maximum of three years from the date of grant if unvested. Performance-based contingent share units do not participate in dividends and shares are only issued in part or in full upon the attainment of vesting conditions, generally have a lower probability of achievement and expire after a maximum of three years from the date of grant if unvested. Shares underlying performance-based contingent share units are reserved from the Amended and Restated Plan. Performance-based restricted stock awards and contingent restricted stock units are valued using a Monte Carlo simulation and geometric Brownian motion techniques applied to the historical volatility of the Company’s total stock return compared to the historical volatilities of other companies or indices to which the Company compares its performance. Stock-based compensation is recognized ratably over the expected vesting period, so long as the award holder remains an employee of the Company. Previously recognized compensation expense is only reversed for the awards with market-based vesting conditions if the requisite service period is not rendered by the holder resulting in forfeiture of the award or as a result of regulatory required clawback.

Vesting of grants with performance-based vesting conditions is dependent on the future price of the Company’s common stock. Such awards vest in part or in full if the trailing total returns on the Company’s common stock for a specified three-year period exceed the corresponding total returns of various quartiles of indices consisting of peer companies.

During the ~~three~~six months ended ~~September~~December 3031, 2025, the Company granted a total of 0.34 million equity awards that included 0.12 million time-vested restricted stock awards and 0.2 million performance-based restricted stock awards.

During the ~~three~~six months ended ~~September~~December 3031, 2024, the Company granted a total of 0.45 million equity awards that included 0.12 million time-vested restricted stock awards, 0.2 million performance-based restricted stock awards, and 0.1 million of performance-based contingent stock units.

For performance-based awards granted during the ~~three~~six months ended ~~September~~December 3031, 2025 and 2024, the assumptions used in the Monte Carlo simulation valuations were as follows:


	~~Three~~Six Months Ended
	~~September~~December 3031,
	2025		2024
Weighted average fair value of performance-based awards granted	$	4.36	$	3.90
Risk-free interest rate		3.55%		3.45%
Expected term in years		2.78		2.78
Expected volatility		40.6%		50.2%
Dividend yield		8.8%		8.4%

~~Unvested restricted stock awards as of September 30, 2025 consisted of the following:~~20


		Weighted
	Number of	Average
	Restricted	Grant-Date
Award Type	Shares	Fair Value
Time-vested awards	370,009	$	6.06
Performance-based awards	508,851		4.65
Unvested at September 30, 2025	878,860	$	5.24

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Unvested restricted stock awards as of December 31, 2025 consisted of the following:


		Weighted
	Number of	Average
	Restricted	Grant-Date
Award Type	Shares	Fair Value
Time-vested awards	371,997	$	5.40
Performance-based awards	508,851		4.65
Unvested at December 31, 2025	880,848	$	4.97

The following table sets forth the restricted stock award transactions for the three months ended September 30, 2025:


						Weighted
		Weighted		Unamortized		Average
	Number of	Average		Compensation		Remaining
	Restricted	Grant-Date		Expense		Amortization
	Shares	Fair Value		(In thousands)		Period (Years)
Unvested at June 30, 2025	670,285	$	5.58	$	2,196	1.6
Time-vested shares granted	93,353		5.47
Performance-based shares granted	186,709		4.36
Vested	(71,487)		6.41
Unvested at September 30, 2025	878,860	$	5.24	$	3,035	2.0

The following table sets forth the restricted stock award transactions for the six months ended December 31, 2025:

The following table sets forth contingent restricted stock unit transactions for the three months ended September 30, 2025:


						Weighted
		Weighted		Unamortized		Average
	Number of	Average		Compensation		Remaining
	Restricted	Grant-Date		Expense		Amortization
	Shares	Fair Value		(In thousands)		Period (Years)
Unvested at June 30, 2025	670,285	$	5.58	$	2,196	1.6
Time-vested shares granted	214,423		4.75
Performance-based shares granted	186,709		4.36
Vested	(190,569)		6.30
Unvested at December 31, 2025	880,848	$	4.97	$	2,982	1.7


						Weighted
				Unamortized		Average
	Number of	Weighted Average		Compensation		Remaining
	Restricted	Grant-Date		Expense		Amortization
	Stock Units	Fair Value		(In thousands)		Period (Years)
Unvested at June 30, 2025	241,613	$	2.37	$	340	1.8
Unvested at September 30, 2025	241,613	$	2.37	$	288	1.6

The following table sets forth contingent restricted stock unit transactions for the six months ended December 31, 2025:


							Weighted
					Unamortized		Average
		Number of	Weighted Average		Compensation		Remaining
		Restricted	Grant-Date		Expense		Amortization
		Stock Units	Fair Value		(In thousands)		Period (Years)
Unvested at June 30, 2025		241,613	$	2.37	$	340	1.8
Unvested at December 31, 2025		241,613	$	2.37	$	236	1.3

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 12. Earnings (Loss) per Common Share

The following table sets forth the computation of basic and diluted earnings (loss) per common share, reflecting the application of the two-class method (in thousands, except per share amounts):


	Three Months Ended				Six Months Ended
	~~September~~December 3031,				December 31,
	2025		2024
	2025		2024		2025		2024
Numerator
Net income (loss)	$	~~824~~1,065	$	2(1,~~065~~825)	$	1,889	$	240
Undistributed earnings allocated to unvested restricted stock		(82104)		(40100)		(186)		(178)
Net income (loss) for earnings per share calculation	$	~~742~~961	$	2(1,~~025~~925)	$	1,703	$	62

Denominator
Weighted average number of common shares outstanding — Basic		33,~~725~~904		32,~~722~~934		33,815		32,828
Effect of dilutive securities:
Unvested restricted stock awards		~~162~~121		~~146~~—		141		166
Unvested contingent restricted stock units		90—		—		45		—
Weighted average number of common shares and dilutive potential common shares used in diluted earnings per share		3334,~~977~~025		32,~~868~~934		34,001		32,994

Net income (loss) per common share — Basic	$	0.0203	$	(0.06)	$	0.05	$	—
Net income (loss) per common share — Diluted	$	0.0203	$	(0.06)	$	0.05	$	—

Unvested restricted stock awards, totaling ~~less than~~ 0.12 million and 0.1 million for the three and six months ended ~~September~~December 3031, 2025 ~~and 2024~~, respectively, were not included in the computation of diluted earnings per common share because the effect would have been anti-dilutive.

Unvested restricted stock awards, totaling 0.8 million for the three months ended December 31, 2024, were not included in the computation of diluted earnings per common share because the effect would have been anti-dilutive due to the net loss. Unvested restricted stock awards, totaling 0.1 million for the six months ended December 31, 2024, were not included in the computation of diluted earnings per common share because the effect would have been anti-dilutive.

In addition, unvested performance-based restricted stock awards and unvested contingent restricted stock units that would not meet the performance criteria as of the period end are excluded from the computation of diluted earnings per common share.

Note 13. Leases

Operating leases are reflected as an operating lease right of use (“ROU”) asset included in “Other assets”, and as a ROU liability in “Accrued liabilities and other” and “Operating lease liability” on the Company’s unaudited condensed consolidated balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset would also include any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred, if any. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term and are presented as “General and administrative expenses” in the unaudited condensed consolidated statements of operations. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. For all operating leases, lease and non-lease components are accounted for as a single lease component.

As a non-operator and having adequate liquidity, the Company has generally not entered into lease transactions. The Company’s only operating lease is for corporate office space in Houston, Texas, effective May 1, 2019 and amended

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

most recently November 30, 2025 and set to expire June 30, 2031. The Company does not have any leases that meet the criteria for classification as a finance lease or a short-term lease.

The Company makes certain assumptions and judgments when evaluating a contract that meets the definition of a lease under ASC 842, Leases. As the Company’s operating lease did not provide an implicit rate, an incremental borrowing rate was calculated using information available at the commencement and modification dates of the lease. The incremental borrowing rate for a lease is the rate of interest for which the Company would pay on a collateralized basis to borrow an amount equal to the lease payments under similar terms. The lease term was determined by considering any option available to extend or to early terminate the lease which the Company believed was reasonably certain to be exercised.

The table below summarized the Company’s leases for the six months ended December 31, 2025 and 2024 (in thousands, except years and discount rate):


		Six Months Ended December 31,
		2025			2024
Statements of Operations:
Operating lease costs		$	46		$	45
Variable lease costs			21			33
Total lease costs		$	67		$	78

Statements of Cash Flow:
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases		$	41		$	57

Other:
ROU assets obtained in exchange for new operating lease liabilities		$	455		$	—
Weighted average remaining lease term in years			5.50			1.16
Weighted average discount rate			6.09	%		7.40	%

~~Note 13.~~The ~~Additional~~following ~~Financial~~table ~~Statement~~presents ~~Information~~the Company’s ROU assets and lease liabilities (in thousands):


	December 31, 2025		June 30, 2025
Balance Sheets:
Operating lease ROU asset (included in other assets)	$	449	$	58
Accrued liabilities and other - current		63		66
Operating lease liability - long-term		386		—

As of December 31, 2025, the future minimum lease payments associated with the Company’s non-cancellable operating lease for office space are as follows (in thousands):


Fiscal Year		December 31, 2025
Remaining in 2026		$	17
2027			97
2028			100
2029			103
2030			107
Thereafter			110
Total operating lease payments			534
Less: discount to present value			(85)
Total operating lease liabilities			449
Less: current operating lease liabilities			63
Non current operating lease liabilities		$	386

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EVOLUTION PETROLEUM CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 14. Additional Financial Statement Information

Certain amounts on the unaudited condensed consolidated balance sheets are comprised of the following (in thousands):


	September 30, 2025		June 30, 2025
	December 31, 2025		June 30, 2025
Prepaid expenses and other current assets:
Other receivables	$	~~376~~156	$	227
Prepaid insurance		~~528~~396		701
Prepaid federal and state income taxes		—56		706
Advances to operators		1831		316
Prepaid other		~~313~~220		337
Total prepaid expenses and other current assets	$	~~1,235~~859	$	2,287

Other assets:
Deposit	$	8	$	8
Debt issuance costs, net		~~429~~390		365
Right of use asset under operating lease		37449		58
Total other assets	$	~~474~~847	$	431

Accrued liabilities and other:
Accrued payables	$	2,~~470~~475	$	2,937
Accrued capital expenditures		~~149~~600		421
Accrued incentive and other compensation		~~432~~777		1,472
Accrued royalties payable(1)		~~476~~625		417
Accrued taxes other than federal and state income tax		~~1,585~~452		1,283
Operating lease liability		42		66
Accrued settlements on derivative contracts		170		—
Asset retirement obligations due within one year		262		295
Operating lease liability		63		66
Accrued interest and other		27		18
Asset retirement obligations due within one year		131		295
Total accrued liabilities and other	$	5,443	$	6,909
Accrued interest and other		15		18
Total accrued liabilities and other	$	5,308	$	6,909

(1)	Accrued royalties payable relate to royalty and owner payments in the Jonah Field as the Company takes its natural gas and NGL working interest production in-kind. See Note 2, “Revenue Recognition” for a further discussion.

Note 1415. Subsequent Events

Dividend Declaration

On ~~November~~February 109, ~~2025~~2026, the Company declared a quarterly cash dividend of $0.120 per share of common stock to shareholders of record on ~~December~~March 1516, ~~2025~~2026 and payable on ~~December~~March 31, ~~2025~~2026.

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

Executive Overview

Liquidity and Capital Resources

Results of Operations

Critical Accounting Policies

Commonly Used Terms

“Current quarter” refers to the three months ended ~~September~~December 3031, 2025, our ~~first~~second quarter of fiscal year 2026.

“Year-ago quarter” refers to the three months ended ~~September~~December 3031, 2024, our ~~first~~second quarter of fiscal year 2025.

Executive Overview

General

Evolution Petroleum Corporation is an independent energy company focused on maximizing total returns to its shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States. In support of that objective, our long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisitions and through selective development opportunities, production enhancements, and other exploitation efforts on our oil and natural gas properties.

Our oil and natural gas properties consist primarily of non-operated working and mineral interests in the following areas (as well as small overriding royalty interests in four onshore central Texas wells):

● Our non-operated working interests and mineral interests in the SCOOP and STACK plays consist of oil and natural gas producing properties in the Anadarko basin, where we hold an approximate 2.7% average net working interest with an associated 2.0% average net revenue interest located on approximately 103,700 gross (4,200 net) acres (approximately 97% held by production) and a separate approximate 0.6% average net royalty interests located on approximately 5,500 net royalty acres across Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties in Oklahoma. The oil and natural gas properties are primarily operated by Continental Resources, Inc., Ovintiv USA Inc. and EOG Resources, Inc. with approximately 40% of wells operated by other operators. Production from our SCOOP/STACK properties for the ~~three~~six months ended ~~September~~December 3031, 2025 is comprised of 5254% natural gas, 2725% crude oil, and 21% NGLs.

● Our non-operated interests in the Chaveroo Field consist of a 50% net working interest, with an average associated 41% average net revenue interest, in approximately 4,500 gross (2,300 net) acres all held by production, associated with six development blocks, with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price. The field is operated by PEDEVCO Corp. (“PEDEVCO”). Production from our Chaveroo Field properties for the ~~three~~six months ended ~~September~~December 3031, 2025 is comprised of 100% crude oil.

● Our non-operated interests in the Jonah Field, a natural gas and NGL property in Sublette County, Wyoming, consist of approximately 20% average net working interest and approximately 15% average net revenue interest located on approximately 5,300 gross (950 net) acres all held by production. The properties are operated by Jonah Energy. Production from our Jonah Field properties for the ~~three~~six months ended ~~September~~December 3031, 2025 is comprised of 89% natural gas, 6% NGLs, and 5% crude oil.

● Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 138,200 gross (41,300 net) acres (approximately 97% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy

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on approximately 138,200 gross (41,300 net) acres (approximately 97% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy Management. Production from our Williston Basin properties for the ~~three~~six months ended ~~September~~December 3031, 2025 is comprised of 7372% crude oil, 17% NGL, and 1011% natural gas.

● Our non-operated working interests and overriding royalty interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately 17% average net working interest and approximately 14% average net revenue interest (inclusive of ~~small~~the overriding royalty interests). The approximately 123,800 gross (21,000 net) acres are held by production across nine North Texas counties. The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other operators. Production from our Barnett Shale properties for the ~~three~~six months ended ~~September~~December 3031, 2025 is comprised of 73% natural gas, 26% NGLs, and 1% crude oil.

● Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consist of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest). The 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company, who owns the majority of the remaining working interest in the Hamilton Dome Field. The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming. Production from our Hamilton Dome Field properties for the ~~three~~six months ended ~~September~~December 3031, 2025 is comprised of 100% crude oil.

● Our non-operated working interests and overriding royalty interests in the Delhi Field, a CO2-EOR project, consist of approximately 24% average net working interest, with an associated 19% average net revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC, a subsidiary of Exxon Mobil Corporation. The 13,600 gross acre unitized Delhi Field, of which we hold approximately 3,200 net acres, is located in northeast Louisiana in Franklin, Madison, and Richland Parishes. Production from our Delhi Field properties for the ~~three~~six months ended ~~September~~December 3031, 2025 is comprised of 8180% crude oil and 1920% NGLs.

● Our non-operated working interests in TexMex consists of oil and natural gas producing properties where we hold an approximate 42% net working interest and 35% average net revenue interest located on approximately 27,800 gross (11,200 net) acres (all held by production) primarily in Lea, Eddy and Chaves Counties, New Mexico and Stephens County, Texas. The oil and natural gas properties are operated by Texian Operating Company. Production from our TexMex properties for the ~~three~~six months ended ~~September~~December 3031, 2025 is comprised of 6656% crude oil and 3444% natural gas.

Recent Developments

Dividend Declaration

On ~~November~~February 109, ~~2025~~2026, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable ~~December~~March 31, ~~2025~~2026.

Senior Secured Credit Facility

On November 28, 2025, we entered into a letter agreement with MidFirst Bank pursuant to which Margined Collateral Value, as defined under the Senior Secured Credit, was modified to $65.0 million and allowed us until December 31, 2025 to enter into additional commodity hedge transactions to satisfy the level of hedging requirements.

Purchase of SCOOP/STACK Minerals

On August 4, 2025, we completed the acquisition of certain mineral and royalty interests in the SCOOP and STACK plays in Oklahoma from a non-affiliated private seller (the “Minerals Acquisition”) in a cash transaction valued at approximately $16.93 million, which includes $17.0 million paid at closing less interim purchase price adjustments totaling approximately $0.17 million related to net cash flows earned on the properties from the effective date to the closing date. We expect to receive the remaining net cash flows from the properties between the effective date of May 1, 2025 and the closing date, at the final post-closing settlement process expected to occur during the second quarter of fiscal 2026. We accounted for the transaction as an asset acquisition and the allocation of the purchase price was $11.1 million to proved oil and natural gas properties, subject to amortization, and $5.8 million to unproved properties. We funded the purchase price for the Minerals Acquisition with a combination of $15.0 million in borrowings under our

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closing date. We expect to receive the remaining net cash flows from the properties between the effective date of May 1, 2025 and the closing date, at the final post-closing settlement process expected to occur during the third quarter of fiscal 2026. We accounted for the transaction as an asset acquisition and the allocation of the purchase price was $11.7 million to proved oil and natural gas properties, subject to amortization, and $4.6 million to unproved properties. We funded the purchase price for the Minerals Acquisition with a combination of $15.0 million in borrowings under our Senior Secured Credit Facility and cash on hand. The acquired assets include an average royalty interest of 0.6% across approximately 5,500 net royalty acres located primarily in Grady and Canadian Counties, Oklahoma.

Risks and uncertainties

The oil and natural gas industry is a global market impacted by many factors, such as government regulations, particularly in the areas of tariffs, trade sanctions, taxation, energy, climate change and the environment, geopolitical instability, ~~and~~(including ~~armed~~ongoing conflicts ~~(including~~ between Russia and Ukraine, ~~and~~ in the Middle East and Venezuela), demand in Asian and European markets, and the extent to which members of OPEC and other oil exporting nations manage oil supply through export quotas. Natural gas prices are generally determined by North American supply and demand and are also affected by imports and exports of liquefied natural gas. Weather also has a significant impact on demand for natural gas since it is a primary heating source.

Oil, natural gas, and NGL prices have been, and we expect may continue to be, volatile. Lower oil and natural gas prices not only decrease our revenues, but an extended decline in oil or natural gas prices may affect planned capital expenditures and the oil and natural gas reserves that we can economically produce. Lower oil and natural gas prices may also reduce the amount of our borrowing base under our Senior Secured Credit Facility, which is determined at the discretion of the lenders based on various factors including the collateral value of our proved reserves.

At times, we do maintain cash balances in excess of the U.S. Federal Deposit Insurance Corporation (“FDIC”); however, we believe our bank counterparty to be financially sound. We also utilize insured cash sweep deposits to maximize the amount of our cash that is protected by FDIC insurance. We also rely heavily on our third-party operators who manage their own liquidity with various financial institutions. In 2022, the Federal Reserve took actions to raise interest rates in an attempt to constrain inflation and slow the economy. In 2024 and 2025, the Federal Reserve has taken action to slowly drop interest rates as inflationary pressures in the United States economy have begun to subside, but it is uncertain how recent trade policies and tariffs by the United States and foreign governments will impact inflation and the economy.

Given the dynamic nature of these factors and events, we cannot reasonably estimate the period of time that certain market conditions will persist. Continuing volatility in political, trade, regulatory and economic conditions could impact supply and demand fundamentals, and any related significant declines in crude oil, natural gas, and NGL prices could lead to proved property impairments in the future. Future impairments of proved properties are difficult to predict, especially in a volatile price environment.

Currently, our oil and natural gas properties are operated by third-party operators and involve other third-party working interest owners. As a result, we have limited ability to influence the operation or future development of such properties. Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review the management of capital expenditures.

Liquidity and Capital Resources

As of ~~September~~December 3031, 2025, we had $03.78 million in cash and cash equivalents and $5354.05 million outstanding borrowings on our Senior Secured Credit Facility compared to $2.5 million in cash and cash equivalents and $37.5 million outstanding borrowings on our Senior Secured Credit Facility at June 30, 2025. Our primary sources of liquidity and capital resources during the ~~three~~six months ended ~~September~~December 3031, 2025 were cash provided by operations and net borrowings under our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the ~~three~~six months ended ~~September~~December 3031, 2025 were cash used to fund our Minerals Acquisition, cash dividend payments to our common stockholders, and development capital expenditures. As of ~~September~~December 3031, 2025, working capital was a deficit of $52.40 million. As of June 30, 2025, working capital was a deficit of $4.0 million.

The syndicated Senior Secured Credit Facility has a maximum capacity of $200.0 million subject to a borrowing base determined by the lenders based on the value of our oil and natural gas properties. The Senior Secured Credit Facility has a current borrowing base of $65.0 million. As of September 30, 2025, we had $53.0 million of indebtedness, $0.8 million of letters of credit outstanding, and available capacity of $11.2 million. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on June 30, 2028.27

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~~Borrowings~~The ~~bear~~syndicated ~~interest,~~Senior atSecured ~~our~~Credit ~~option,~~Facility athas ~~either (i) the SOFR, subject to~~ a ~~minimum~~maximum ~~SOFR~~capacity of 3$200.~~25%,~~0 ~~plus~~million asubject ~~credit~~to ~~spread~~a ~~adjustment~~borrowing ofbase ~~0.05%,~~determined orby the ~~Prime~~lenders ~~Rate,~~based ason ~~defined~~a ~~under~~percentage ~~the Senior Secured Credit Facility, plus 1.0%, plus, in either case~~ of ~~(i)~~the orvalue ~~(ii), an applicable margin~~ of ~~2.75%. For~~our ~~the~~oil ~~three months ended September 30, 2025~~ and ~~2024,~~natural ~~the~~gas ~~weighted average interest on our borrowings was 7~~properties.~~12%~~ ~~and 8.09%, respectively.~~ The Senior Secured Credit Facility ~~contains~~has ~~covenants requiring the maintenance of (i)~~ a ~~total~~current ~~leverage~~borrowing ~~ratio~~base of ~~not more than 3~~$65.000 ~~to 1~~million.~~00,~~ ~~(ii) a~~As ~~current ratio~~ of ~~not less than 1.00 to 1.00~~December 31, ~~and (iii)~~ a2025, ~~consolidated~~we ~~tangible~~had ~~net~~$54.5 ~~worth~~million of ~~not~~indebtedness, ~~less than~~ $~~40.~~0.8 million, ~~each~~of asletters ~~defined~~of incredit ~~the Senior Secured Credit Facility. In addition~~outstanding, ~~the~~and ~~Senior~~available ~~Secured~~capacity ~~Credit Facility contains hedging requirements that apply when utilization is greater than 25%~~ of ~~(x)~~$9.7 ~~the~~million. ~~Margined~~The ~~Collateral Value, as defined under the~~ Senior Secured Credit Facility, ~~at any time when the leverage ratio~~ is ~~less~~secured ~~than~~by ~~2.25~~substantially toall ~~1.00,~~of orour ~~(y)~~oil ~~the borrowing base, at any time when the leverage ratio is greater than or equal to 2.25 to 1.00. It also contains other customary affirmative~~ and ~~negative~~natural ~~covenants,~~gas ~~including~~properties ~~a hedging covenant discussed below,~~ and ~~events~~matures ofon ~~default.~~June ~~As of September~~ 30, ~~2025,~~ ~~we were in compliance with all covenants under the Senior Secured Credit Facility~~2028.

~~The~~For ~~Senior~~the ~~Secured~~six ~~Credit~~months ~~Facility~~ended ~~requires~~December 31, 2025 ~~redeterminations~~and of2024, the ~~borrowing~~weighted ~~base~~average tointerest ~~occur~~on ~~semi-annually~~our borrowings was 6.88% Atand ~~each~~7.80%, ~~redetermination~~respectively. Borrowings bear interest, at our option, at either (i) the ~~Margined~~SOFR, ~~Collateral~~subject ~~Value~~to isa ~~updated~~minimum ~~based~~SOFR onof ~~the~~3.25%, ~~estimated~~plus ~~value~~a credit spread adjustment of ~~our~~0.05%, ~~oil~~or ~~and~~(ii) ~~natural~~the ~~gas~~Prime ~~properties~~Rate, ~~which~~as ~~includes~~defined ~~our~~under ~~proved~~the ~~developed~~Senior ~~reserves~~Secured Credit Facility, ~~proved~~plus ~~undeveloped~~1.0%, ~~reserves~~plus, ~~and~~in ~~other~~either ~~relevant~~case ~~factors~~of ~~consistent~~(i) ~~with~~or ~~customary~~(ii), ~~oil~~an ~~and~~applicable ~~natural~~margin ~~gas~~of ~~lending~~2.75%. The ~~criteria~~Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not more than 3. On00 ~~August~~to 291.00, ~~2025,~~(ii) a wecurrent ~~entered~~ratio ~~into~~of annot ~~amendment~~less than 1.00 to ~~our~~1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. ~~with~~In ~~MidFirst Bank~~addition, ~~whereas~~the itSenior ~~was~~Secured ~~determined~~Credit ~~for~~Facility ~~purposes~~contains hedging requirements that apply when utilization is greater than 25% of (x) the ~~hedge~~Margined ~~covenant~~Collateral ~~that~~Value, ~~total~~as ~~crude~~defined ~~oil~~under ~~and~~the ~~natural~~Senior ~~gas~~Secured ~~production~~Credit ~~volumes~~Facility, ~~from~~at ~~proved~~any ~~developed~~time ~~producing~~when ~~reserves~~the ~~will~~leverage beratio ~~combined~~is onless athan ~~barrels~~2.25 ofto ~~oil~~1.00, ~~equivalent~~or (~~“BOE”~~y) ~~basis~~the borrowing base, at any time when the leverage ratio is greater than or equal to ~~determine~~2.25 to 1.00. It also contains other customary affirmative and negative covenants, including a hedging covenant discussed below, and events of default. As of December 31, 2025, we were in compliance with all covenants under the ~~hedging~~Senior ~~covenant~~Secured Credit Facility.

The Senior Secured Credit Facility requires redeterminations of the borrowing base to occur semi-annually. At each redetermination, the Margined Collateral Value is updated based on the estimated value of our oil and natural gas properties, which includes our proved developed reserves, proved undeveloped reserves, and other relevant factors consistent with customary oil and natural gas lending criteria. On November 28, 2025, we entered into a letter agreement with MidFirst Bank pursuant to which Margined Collateral Value, as defined under the Senior Secured Credit, was modified to $65.0 million and allowed us until December 31, 2025 to enter into additional commodity hedge transactions to satisfy the level of hedging requirements. On August 29, 2025, we entered into the first amendment to our Senior Secured Credit Facility with MidFirst Bank, whereas it was determined for purposes of the hedge covenant that total crude oil and natural gas production volumes from proved developed producing reserves will be combined on a barrels of oil equivalent (“BOE”) basis to determine compliance with the hedging covenant.

We have historically funded operations through cash from operations and working capital. Our primary source of cash is the sale of produced crude oil, natural gas, and NGLs. A portion of these cash flows is used to fund capital expenditures and pay cash dividends to shareholders. We expect to fund near-future capital development activities for our properties with cash flows from operating activities, and, as needed, borrowings under our Senior Secured Credit Facility and proceeds from the ATM Sales Agreement.

We are pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, we have access to the undrawn portion of the borrowing base available under our Senior Secured Credit Facility, totaling $119.27 million as of ~~September~~December 3031, 2025. We also have an effective shelf registration statement with the SEC under which we may issue up to $500.0 million of new debt or equity securities.

On October 21, 2024, we entered into an ATM Sales Agreement with Roth Capital Partners, LLC as our Lead Agent, Northland Securities Inc., and A.G.P./Alliance Global Partners pursuant to which we may issue and sell, from time to time, up to $30.0 million of shares of common stock through or to the Lead Agent, acting as agent or principal to facilitate acquisitions and other general corporate purposes. During the ~~three~~six months ended ~~September~~December 3031, 2025, we sold a total of approximately 570.3 ~~thousand~~million shares of our common stock under the ATM Sales Agreement for net proceeds of approximately $~~246~~1.2 ~~thousand~~million, net of $2046 thousand of offering costs.

Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 4849 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to increase dividends over time, assubject ~~appropriate.~~to Onadjustments ~~November~~as ~~10,~~appropriate ~~2025,~~in the Board of Directors’ ~~declared~~discretion adepending ~~quarterly~~on ~~cash~~factors ~~dividend~~such ofas ~~$0.12~~commodity ~~per~~prices, ~~share~~other ofopportunities ~~common~~for ~~stock~~uses ~~to shareholders~~ of ~~record~~capital, onand ~~December~~any ~~15,~~other ~~2025~~factors ~~and~~the ~~payable~~Board onof ~~December~~Directors ~~31,~~deems ~~2025.~~

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relevant. On February 9, 2026, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on March 16, 2026 and payable on March 31, 2026.

Capital Expenditures

During the ~~three~~six months ending ~~September~~December 3031, 2025, we incurred $12.95 million on development capital expenditures. A majority of our spending occurred at SCOOP/STACK where our operators are actively drilling. ~~and~~Three ~~completing three~~ gross wells were brought online during the first quarter of the year, and ~~capital~~three ~~workover~~gross ~~projects~~wells ~~across~~are ~~our~~currently ~~assets~~in progress. Based on discussions with our operators, we expect capital workover projects to continue in most of our fields throughout the remainder of the year as well as further drilling at SCOOP/STACK.

27Overall, for fiscal year 2026, we expect budgeted capital expenditures to be in the range of $4.0 million to $6.0 million, which excludes any potential acquisitions. Our expected capital expenditures for fiscal year 2026 include bringing approximately nine gross wells online, including the six gross wells described above, at our SCOOP/STACK properties. Additionally, as our third-party operators continue to be active around our acreage, we would expect additional wells to be drilled and/or completed. At Chaveroo Field, we anticipate securing permits for the next six wells before the end of the fiscal year 2026. The final decision, made jointly with our partner, on when to spud these wells will depend on prevailing oil prices and completed well costs at that time.

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Overall, for fiscal year 2026, we expect budgeted capital expenditures to be in the range of $4.0 million to $6.0 million, which excludes any potential acquisitions. Our expected capital expenditures for fiscal year 2026 include bringing approximately five gross wells online at our SCOOP/STACK properties. Additionally, as our third-party operators continue to be active around our acreage, we would expect additional wells to be drilled and/or completed. At Chaveroo Field, we expect to have drilling permits in hand for the next round of six wells before the end of the fiscal year 2026 and the final decision by us and our partner as to timing for spudding these wells will be made based on oil prices and completed well costs at that time.

Full Cost Pool Ceiling Test

Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion, depreciation, and amortization and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test as of ~~September~~December 3031, 2025 were $6866.0701 per barrel of oil, $3.1140 per MMBtu of natural gas and $23.8922 per barrel of NGLs. As of ~~September~~December 3031, 2025, our capitalized costs of oil and natural gas properties, subject to amortization, were below the full cost valuation ceiling. If commodity price levels were to substantially decline from the 12-month average first day of the month pricing levels as of ~~September~~December 3031, 2025 and remain down for a prolonged period of time, our valuation ceiling over our capitalized costs may be reduced and adversely impact our ceiling test results in future quarters and the effect could be material to our net earnings. Using first day of the month prices for ~~October~~January and ~~November~~February ~~2025~~2026, which are more reflective of recent prices trends, to calculate a trailing 12-month average price of $6664.9805 per barrel of oil and $3.1880 per MMBtu of natural gas, and keeping all other factors constant, the ceiling test calculation as of the ~~first~~second quarter of fiscal year 2026 would not have generated a ceiling test impairment. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required at some point in the future as commodity prices are volatile and unpredictable. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Overview of Cash Flow Activities


	~~Three~~Six Months Ended ~~September~~December 3031,
	2025		2024		Change
Cash flows provided by operating activities	$	713,~~805~~230	$	715,~~614~~333	$	~~191~~(2,103)
Cash flows used in investing activities		(2021,~~686~~303)		(3,~~002~~829)		(17,~~684~~474)
Cash flows provided by (used in) financing activities		119,~~088~~328		(46,~~121~~283)		15,~~209~~611
Net increase (decrease) in cash and cash equivalents	$	(1,~~793)~~255	$	~~491~~5,221	$	(23,~~284~~966)

Cash provided by operating activities for the ~~three~~six months ended ~~September~~December 3031, 2025 ~~increased~~decreased $0.2.1 million compared to the ~~three~~six months ended ~~September~~December 3031, 2024 primarily due to changes in the timing of our working capital. Cash flows provided by operating activities before changes in working capital for the three months ended September 30, 2025 decreased $0.8 million compared to the three months ended September 30, 2024, primarily due to a decrease in revenues and anincreases ~~increase~~ in our interest expense and lease operating costs for the comparable periods partially offset by realized gains on derivative contracts in the current ~~period of $0.9 million compared to realized losses on derivative contracts in the prior year period of $0.1 million. Refer to “Results of Operations” below for further information.~~

Cash used in investing activities for the three months ended September 30, 2025 increased $17.7 million compared to the three months ended September 30, 2024 primarily due to the closing of the Minerals Acquisition in August 2025.29

Net cash flows provided by financing activities for the three months ended September 30, 2025 were $11.1 million compared to net cash flows used in financing activities of $4.1 million for the three months ended September 30, 2024. For the three months ended September 30, 2025, we received net borrowings of $15.5 million under our Senior Secured Credit Facility to finance our Minerals Acquisition and paid $4.2 million in cash dividends to our common stockholders. For the three months ended September 30, 2024, we paid $4.0 million in cash dividends to our common stockholders.

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period of $1.7 million compared to $0.1 million in the prior period. Refer to “Results of Operations” below for further information.

Cash used in investing activities for the six months ended December 31, 2025 increased $17.5 million compared to the six months ended December 31, 2024 primarily due to the closing of the Minerals Acquisition in August 2025.

Net cash flows provided by financing activities for the six months ended December 31, 2025 were $9.3 million compared to net cash flows used in financing activities of $6.3 million for the six months ended December 31, 2024. For the six months ended December 31, 2025, we received net borrowings of $17.0 million under our Senior Secured Credit Facility primarily to finance our Minerals Acquisition, received net proceeds from the sale of common stock under the ATM Sales agreement of approximately $1.2 million, after deducting issuance fees, and paid $8.4 million in cash dividends to our common stockholders. For the six months ended December 31, 2024, we paid $8.1 million in cash dividends to our common stockholders and received net proceeds from the sale of common stock under the ATM Sales Agreement of approximately $2.0 million, after deducting $0.2 million of fees for due diligence incurred with the offering.

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Results of Operations

Three Months Ended ~~September~~December 3031, 2025 and 2024

We reported net income of $01.81 million and net loss of $2.1.8 million for the three months ended ~~September~~December 3031, 2025 and 2024, respectively. The following table summarizes the comparison of financial information for the periods presented:


	Three Months Ended
	~~September~~December 3031,
(in thousands, except per unit and per BOE amounts)	2025		2024		Variance		Variance %
Net income (loss)	$	~~824~~1,065	$	2(1,~~065~~825)	$	(12,~~241)~~890	(60158.14)	%
Revenues:
Crude oil		1210,~~872~~696		1411,~~737~~763		(1,~~865~~067)	(129.71)	%
Natural gas		57,~~900~~441		45,~~285~~793		1,~~615~~648	3728.74	%
Natural gas liquids		2,~~516~~542		2,~~874~~719		(~~358~~177)	(126.5)	%
Total revenues		2120,~~288~~679		2120,~~896~~275		~~(608)~~404	(2.8)0	%
Operating costs:
Lease operating costs:
Ad valorem and production taxes		~~1,420~~588		1,~~414~~441		6(853)	0(59.42)	%
Gathering, transportation, and other costs		2,~~892~~667		2,~~790~~889		~~102~~(222)	3(7.7)	%
Other lease operating costs		8,~~775~~255		78,~~586~~463		~~1,189~~(208)	15(2.75)	%
Depletion, depreciation, and accretion:
Depletion of full cost proved oil and natural gas properties		5,~~560~~532		5,~~325~~024		~~235~~508	410.41	%
Accretion of asset retirement obligations		~~401~~387		~~400~~409		1(22)	0(5.34)	%
General and administrative expenses:
General and administrative		1,~~788~~979		1,~~968~~995		(~~180~~16)	(90.18)	%
Stock-based compensation		~~537~~613		~~559~~659		(2246)	(37.90)	%
Other income (expense):
Net gain (loss) on derivative contracts		2,~~181~~235		(1,~~798~~219)		~~383~~3,454	21(283.3)	%
Interest and other income		1012		5752		(4740)	(8276.59)	%
Interest expense		(~~917~~1,003)		(~~823~~764)		(94239)	1131.43	%
Income tax (expense) benefit		(~~365~~837)		~~(821)~~711		~~456~~(1,548)	(55217.57)	%

Production:
Crude oil (MBBL)		~~207~~193		~~204~~179		314	17.58	%
Natural gas (MMCF)		2,~~150~~241		2,~~228~~125		~~(78)~~116	(35.5)	%
Natural gas liquids (MBBL)		~~108~~112		~~113~~105		~~(5)~~7	(46.4)7	%
Equivalent (MBOE)(1)		~~673~~679		~~688~~638		~~(15)~~41	(26.2)4	%
Average daily production (BOEPD)(1)		7,~~315~~380		76,~~478~~935		~~(163)~~445	(26.2)4	%

Average price per unit(2):
Crude oil (BBL)	$	6255.1842	$	7265.2472	$	(10.0630)	(1315.97)	%
Natural gas (MCF)		23.7432		12.9273		0.8259	4221.76	%
Natural Gas Liquids (BBL)		2322.3070		25.4390		(23.1320)	(812.4)	%
Equivalent (BOE)(1)		3130.6346		31.8378		(01.2032)	(04.62)	%

Average cost per unit:
Operating costs:
Lease operating costs:
Ad valorem and production taxes	$	20.1187	$	2.0626	$	0(1.0539)	2(61.45)	%
Gathering, transportation, and other costs		43.3093		4.0653		(0.2460)	5(13.92)	%
Other lease operating costs		1312.0416		1113.0326		2(1.0110)	18(8.23)	%
Depletion of full cost proved oil and natural gas properties		8.2615		7.7487		0.5228	63.76	%
General and administrative expenses:
General and administrative		2.6691		23.8613		(0.2022)	(7.0)	%
Stock-based compensation		0.8090		01.8103		(0.0113)	(112.26)	%

(1)	Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.

(2)	Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting.

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Revenues

Crude oil, natural gas and NGL revenues were $2120.37 million and $2120.93 million for the three months ended ~~September~~December 3031, 2025 and 2024, respectively, with the ~~decrease~~increase in revenues due to ~~decreases~~an increase in production volumes ~~and~~partially offset by decreases in our average realized price per BOE. Average daily equivalent production ~~decreased~~increased 26.24% ~~from~~to 7,~~478~~380 BOEPD in the ~~prior~~current year period tofrom 76,~~315~~935 BOEPD in the ~~current~~prior period primarily as a result ~~of downtime at the Delhi NGL plant for the replacement of a turbine and natural~~ production ~~declines. Our overall decrease in production was partially offset by production~~ from our Minerals Acquisition in August 2025 and TexMex Acquisition in April 2025. Our average realized commodity price (excluding the impact of derivative contracts) for the three months ended ~~September~~December 3031, 2025 decreased approximately $01.2032 per BOE, or 04.62%, over the prior year period as our realized crude oil decreased 1315.97% and realized NGL prices decreased 812.4% from the three months ended ~~September 30~~December 31, 2024. The overall decrease in our realized crude oil and NGL prices was partially offset by a 4221.76% increase in our realized natural gas prices over the prior period.

Lease Operating Costs

Ad valorem and production taxes were $0.6 million and $1.4 million, respectively, for ~~each of~~ the three months ended ~~September~~December 3031, 2025 and 2024. The $0.8 million decrease is directly related to a reduction of calendar years 2024 and 2025 ad valorem taxes which were passed along from the operator of our Barnett Shale natural gas properties. On a per unit basis, ad valorem and production taxes were $20.1187 per BOE and $2.0626 per BOE for the three months ended ~~September~~December 3031, 2025 and 2024, respectively. ~~The increase on a per unit basis is primarily the result of the decrease in production for the current year period.~~

Gathering, transportation and other costs were $2.97 million for the three months ended ~~September~~December 3031, 2025 compared to $2.89 million for the three months ended ~~September~~December 3031, 2024. These costs are gathering, transportation and processing fees we incur primarily for our natural gas producing properties. The ~~increase~~decrease is primarily due to ~~increased~~decreased natural gas sales at Jonah Field and Barnett Shale. On a per unit basis, gathering, transportation and other costs were $43.3093 per BOE and $4.0653 per BOE for the three months ended ~~September~~December 3031, 2025 and 2024, respectively.

Other lease operating costs were $8.83 million for the three months ended ~~September 30~~December 31, 2025 compared to $78.65 million for the three months ended ~~September 30~~December 31, 2024. Other lease operating costs ~~increased~~decreased primarily due to the cessation of CO2 purchases at Delhi late during the third quarter of fiscal 2025. For the three months ended December 31, 2024, we had net CO2 purchases of $1.1 million. Partially offsetting the overall decrease in other lease operating costs were increases due to the TexMex Acquisition in April 2025, which increased other lease operating costs by $1.31 million over the prior year period. On a per unit basis, other lease operating costs ~~increased~~decreased to $1312.0416 per BOE for the three months ended ~~September~~December 3031, 2025 from $1113.0326 per BOE in the three months ended ~~September 30~~December 31, 2024.

Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased from $5.30 million for the three months ended ~~September 30~~December 31, 2024 to $5.65 million for the three months ended ~~September~~December 3031, 2025 primarily due to an increase in the depletion rate and decrease in reserves volumes. On a per unit basis, depletion expense was $8.2615 per BOE and $7.7487 per BOE for the three months ended ~~September~~December 3031, 2025 and 2024, respectively.

General and Administrative Expenses

General and administrative expenses ~~for the three months ended September 30, 2025 and 2024~~ were $~~1.8 million and $~~2.0 million, ~~respectively.~~for ~~The~~each ~~decrease~~of in the ~~current~~periods ~~period~~ended isDecember ~~primarily~~31, ~~due~~2025 toand ~~a decrease in professional fees~~2024. On a per unit basis, general and administrative expenses were $2.6691 per BOE and $23.8613 per BOE for the three months ended ~~September~~December 3031, 2025 and 2024, respectively. The decrease on a per unit basis is primarily the result of the increase in production for the current year period.

Stock-based Compensation Expense

Stock-based compensation expense for the three months ended ~~September~~December 3031, 2025 was $0.56 million compared to $0.67 million for the year-ago period. The decrease is due to a decrease in the awards granted in the current fiscal period compared to the year-ago period.

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Net Gain (Loss) on Derivative Contracts

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. Financial hedges are a requirement under our Senior Secured Credit Facility and help establish commodity price floors, contributing to stable cash flows when derivative contracts are settled. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized gains (losses) on our average realized prices for the periods presented. As a result of our recent acquisitions and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms in our Senior Secured Credit Facility to hedge a portion of our production. As of ~~September~~December 3031, 2025, we had $23.53 million derivative assets, $23.12 million of which was classified as current, and $2.60 million derivative liabilities, $1.25 million of which was classified as current. Subsequent to the end of the quarter through ~~November~~February ~~2025~~2026, we have seen increased volatility in the crude oil and natural gas commodity markets, and we expect to see continued volatility in the fair value of our derivative contracts.


	Three Months Ended
	~~September~~December 3031,
(in thousands, except per unit and per BOE amounts)	2025		2024		Variance		Variance %
Realized gain (loss) on derivative contracts	$	~~878~~792	$	~~(70)~~149	$	~~948~~643	~~(1,354~~431.3)5	%
Unrealized gain (loss) on derivative contracts		1,~~303~~443		(1,~~868~~368)		~~(565)~~2,811	(30205.25)	%
Total net gain (loss) on derivative contracts	$	2,~~181~~235	$	(1,~~798~~219)	$	~~383~~3,454	21(283.3)	%

Average realized crude oil price per BBL	$	6255.1842	$	7265.2472	$	(10.0630)	(1315.97)	%
Cash effect of oil derivative contracts per BBL		1.1069		(0.~~34)~~83		10.4486	~~(423~~103.5)6	%
Crude oil price per BBL (including impact of realized derivatives)	$	6357.2811	$	7166.9055	$	(89.6244)	(1214.02)	%

Average realized natural gas price per MCF	$	23.7432	$	12.9273	$	0.8259	4221.76	%
Cash effect of natural gas derivative contracts per MCF		0.3021		—		0.3021	—	%
Natural gas price per MCF (including impact of realized derivatives)	$	3.0453	$	12.9273	$	10.1280	5829.3	%

Interest Expense

Interest expense increased $0.12 million for the three months ended ~~September~~December 3031, 2025 compared to the prior year period primarily due to additional borrowings drawn on our Senior Secured Credit Facility to finance our Minerals Acquisition in August 2025. ~~The weighted average interest rate on our borrowings was 7.12% for the three months ended September 30, 2025 compared to 8.09% for the three months ended September 30, 2024.~~

Income Tax (Expense) Benefit

For the three months ended ~~September~~December 3031, 2025, we recognized income tax expense of $0.48 million on net income before income taxes of $1.29 million compared to income tax ~~expense~~benefit of $0.87 million on net ~~income~~losses before income taxes of $2.95 million for the three months ended ~~September~~December 3031, 2024. The effective tax rates were 3044.70% and 28.40% for three months ended ~~September~~December 3031, 2025 and 2024, respectively. The increase in the effective tax rate from the prior year period is due to projected higher state income taxes ~~projected~~in ~~for~~ Oklahoma ~~due~~associated towith the Minerals Acquisition in August 2025. We continue to evaluate our tax provision on a quarterly basis and adjust our effective tax rate for any given changes in facts and circumstances that are expected in the future.

~~Critical Accounting Policies and Estimates~~

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~~and~~Six ~~liabilities~~Months asEnded ofDecember 31, 2025 ~~the date of the balance sheet as well as the reported amounts of revenues~~ and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our unaudited condensed consolidated financial statements. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended June 30, 2025.2024

We reported net income of $1.9 million and $0.2 million for the six months ended December 31, 2025 and 2024, respectively. The following table summarizes the comparison of financial information for the periods presented:


	Six Months Ended
	December 31,
(in thousands, except per unit and per BOE amounts)	2025		2024		Variance		Variance %
Net income (loss)	$	1,889	$	240	$	1,649	687.1	%
Revenues:
Crude oil		23,568		26,500		(2,932)	(11.1)	%
Natural gas		13,341		10,078		3,263	32.4	%
Natural gas liquids		5,058		5,593		(535)	(9.6)	%
Total revenues		41,967		42,171		(204)	(0.5)	%
Operating costs:
Lease operating costs:
Ad valorem and production taxes		2,008		2,855		(847)	(29.7)	%
Gathering, transportation, and other costs		5,559		5,679		(120)	(2.1)	%
Other lease operating costs		17,030		16,049		981	6.1	%
Depletion, depreciation, and accretion:
Depletion of full cost proved oil and natural gas properties		11,092		10,349		743	7.2	%
Accretion of asset retirement obligations		788		809		(21)	(2.6)	%
General and administrative expenses:
General and administrative		3,767		3,963		(196)	(4.9)	%
Stock-based compensation		1,150		1,218		(68)	(5.6)	%
Other income (expense):
Net gain (loss) on derivative contracts		4,416		579		3,837	662.7	%
Interest and other income		22		109		(87)	(79.8)	%
Interest expense		(1,920)		(1,587)		(333)	21.0	%
Income tax (expense) benefit		(1,202)		(110)		(1,092)	992.7	%

Production:
Crude oil (MBBL)		400		383		17	4.4	%
Natural gas (MMCF)		4,391		4,353		38	0.9	%
Natural gas liquids (MBBL)		220		218		2	0.9	%
Equivalent (MBOE)⁽¹⁾		1,352		1,327		25	1.9	%
Average daily production (BOEPD)⁽¹⁾		7,348		7,212		136	1.9	%

Average price per unit⁽²⁾:
Crude oil (BBL)	$	58.92	$	69.19	$	(10.27)	(14.8)	%
Natural gas (MCF)		3.04		2.32		0.72	31.0	%
Natural Gas Liquids (BBL)		22.99		25.66		(2.67)	(10.4)	%
Equivalent (BOE)⁽¹⁾		31.04		31.78		(0.74)	(2.3)	%

Average cost per unit:
Operating costs:
Lease operating costs:
Ad valorem and production taxes	$	1.49	$	2.15	$	(0.66)	(30.7)	%
Gathering, transportation, and other costs		4.11		4.28		(0.17)	(4.0)	%
Other lease operating costs		12.60		12.09		0.51	4.2	%
Depletion of full cost proved oil and natural gas properties		8.20		7.80		0.40	5.1	%
General and administrative expenses:
General and administrative		2.79		2.99		(0.20)	(6.7)	%
Stock-based compensation		0.85		0.92		(0.07)	(7.6)	%

(1)	Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.

(2)	Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting.

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Revenues

Crude oil, natural gas and NGL revenues were $42.0 million and $42.2 million for the six months ended December 31, 2025 and 2024, respectively, with the decrease in revenues due to decreases in our average realized price per BOE partially offset by increases in production volumes. Average daily equivalent production increased 1.9% from 7,212 BOEPD in the prior year period to 7,348 BOEPD in the current period primarily as a result of production from our Minerals Acquisition in August 2025 and TexMex Acquisition in April 2025. Our average realized commodity price (excluding the impact of derivative contracts) for the six months ended December 31, 2025 decreased approximately $0.74 per BOE, or 2.3%, over the prior year period as our realized crude oil decreased 14.8% and realized NGL prices decreased 10.4% from the six months ended December 31, 2024. The overall decrease in our crude oil and NGL realized prices was partially offset by a 31.0% increase in our realized natural gas prices over the prior period.

Lease Operating Costs

Ad valorem and production taxes were $2.0 million and $2.9 million for the six months ended December 31, 2025 and 2024, respectively. The decrease is primarily related to a reduction of calendar years 2024 and 2025 ad valorem taxes which were passed along from the operator of our Barnett Shale natural gas properties. On a per unit basis, ad valorem and production taxes were $1.49 per BOE and $2.15 per BOE for the six months ended December 31, 2025 and 2024, respectively.

Gathering, transportation and other costs were $5.6 million for the six months ended December 31, 2025 compared to $5.7 million for the six months ended December 31, 2024. These costs are gathering, transportation and processing fees we incur primarily for our natural gas producing properties. The decrease is primarily due to decreased natural gas sales at Jonah Field partially offset by increased natural gas sales at Barnett Shale. On a per unit basis, gathering, transportation and other costs were $4.11 per BOE and $4.28 per BOE for the six months ended December 31, 2025 and 2024, respectively.

Other lease operating costs were $17.0 million for the six months ended December 31, 2025 compared to $16.0 million for the six months ended December 31, 2024. Other lease operating costs increased primarily due to the TexMex Acquisition in April 2025, which increased other lease operating costs by $2.4 million over the prior year period. Partially offsetting the overall increase in other lease operating costs is the cessation of CO₂ purchases at Delhi late during the third quarter of fiscal 2025. For the six months ended December 31, 2024, we had net CO₂ purchases of $1.1 million. On a per unit basis, other lease operating costs increased to $12.60 per BOE for the six months ended December 31, 2025 from $12.09 per BOE in the six months ended December 31, 2024.

Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased from $10.3 million for the six months ended December 31, 2024 to $11.1 million for the six months ended December 31, 2025 primarily due to an increase in the depletion rate and decrease in reserves volumes. On a per unit basis, depletion expense was $8.20 per BOE and $7.80 per BOE for the six months ended December 31, 2025 and 2024, respectively.

General and Administrative Expenses

General and administrative expenses for the six months ended December 31, 2025 and 2024 were $3.8 million and $4.0 million, respectively. The decrease in the current period is primarily due to a decrease in professional fees. On a per unit basis, general and administrative expenses were $2.79 per BOE and $2.99 per BOE for the six months ended December 31, 2025 and 2024, respectively.

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Net Gain (Loss) on Derivative Contracts

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. Financial hedges are a requirement under our Senior Secured Credit Facility and help establish commodity price floors, contributing to stable cash flows when derivative contracts are settled. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized gains (losses) on our average realized prices for the periods presented. As a result of our recent acquisitions and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms in our Senior Secured Credit Facility to hedge a portion of our production. As of December 31, 2025, we had $3.3 million derivative assets, $3.2 million of which was classified as current, and $2.0 million derivative liabilities, $1.5 million of which was classified as current. Subsequent to the end of the quarter through February 2026, we have seen increased volatility in the crude oil and natural gas commodity markets, and we expect to see continued volatility in the fair value of our derivative contracts.


	Six Months Ended
	December 31,
(in thousands, except per unit and per BOE amounts)	2025		2024		Variance		Variance %
Realized gain (loss) on derivative contracts	$	1,670	$	79	$	1,591	2,013.9	%
Unrealized gain (loss) on derivative contracts		2,746		500		2,246	449.2	%
Total net gain (loss) on derivative contracts	$	4,416	$	579	$	3,837	662.7	%

Average realized crude oil price per BBL	$	58.92	$	69.19	$	(10.27)	(14.8)	%
Cash effect of oil derivative contracts per BBL		1.39		0.21		1.18	561.9	%
Crude oil price per BBL (including impact of realized derivatives)	$	60.31	$	69.40	$	(9.09)	(13.1)	%

Average realized natural gas price per MCF	$	3.04	$	2.32	$	0.72	31.0	%
Cash effect of natural gas derivative contracts per MCF		0.25		—		0.25	—	%
Natural gas price per MCF (including impact of realized derivatives)	$	3.29	$	2.32	$	0.97	41.8	%

Interest Expense

Interest expense increased $0.3 million for the six months ended December 31, 2025 compared to the prior year period primarily due to additional borrowings drawn on our Senior Secured Credit Facility to finance our Minerals Acquisition in August 2025. The weighted average interest rate on our borrowings was 6.88% for the six months ended December 31, 2025 compared to 7.80% for the six months ended December 31, 2024.

Income Tax (Expense) Benefit

For the six months ended December 31, 2025, we recognized income tax expense of $1.2 million on net income before income taxes of $3.1 million compared to income tax expense of $0.1 million on net income before income taxes of $0.4 million for the six months ended December 31, 2024. The effective tax rates were 38.9% and 31.4% for six months ended December 31, 2025 and 2024, respectively. The increase in the effective tax rate from the prior year period is due to projected higher state income taxes in Oklahoma associated with the Minerals Acquisition. We continue to evaluate our tax provision on a quarterly basis and adjust our effective tax rate for any given changes in facts and circumstances that are expected in the future.

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Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon the unaudited condensed consolidated financial statements. The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our unaudited condensed consolidated financial statements. There have been no material changes to our critical accounting policies from those described in our Annual Report on Form 10-K for the fiscal year ended June 30, 2025.

Item 3. Quantitative and Qualitative Disclosures About Market Risks

Derivative Instruments and Hedging Activity

We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is sold. When oil, natural gas, and NGL prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain volatile and unpredictable, therefore we monitor commodity prices to identify the potential need for the use of derivative financial instruments to provide partial protection against declines in oil and natural gas prices. We do not enter into derivative contracts for speculative trading purposes. In accordance with our Senior Secured Credit Facility, we have been and may be required in the future to enter into hedges if we meet certain utilization levels of the borrowing base under the credit facility. We intend to remain in compliance with these covenants and will enter into derivative contracts from time to time to meet the requirements. As a result of our recent acquisitions and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms in our Senior Secured Credit Facility to hedge a portion of our production. Additionally, depending on market conditions, financial and other considerations we may enter into additional hedges to meet our objectives of increasing value to shareholders. We may also, from time to time, restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts.

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. For the derivative contracts settled during fiscal 2026 and 2025, we did not post collateral. We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivatives” to our unaudited condensed consolidated financial statements for more details.

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents. Additionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either (i) SOFR, subject to a minimum SOFR of 3.25%, plus a credit spread adjustment of 0.05%, or (ii) the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%, plus, in either case of (i) or (ii), an applicable margin of 2.75%. SOFR rates are sensitive to the period of contract and market volatility, as well as changes in forward interest rate yields. Under our current practices, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

Item 4. Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s (“SEC”) rules and forms. This information is accumulated and communicated to our management, including our Principal Executive Officer and Principal Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure.

As required by SEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15(d)-15(e)) as of the end of the quarter covered by this report. In designing and evaluating our disclosure controls and 37

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~~procedures,~~Securities ~~our~~and ~~management~~Exchange ~~recognizes~~Commission’s ~~that~~(“SEC”) ~~controls~~rules and ~~procedures,~~forms. noThis ~~matter~~information ~~how~~is ~~well~~accumulated ~~designed~~ and ~~operated,~~communicated ~~can~~to ~~provide~~our ~~only reasonable assurance of achieving desired control objectives. Based on the foregoing~~management, including our Principal Executive Officer and Principal Financial Officer, ~~concluded that~~ as ~~of September 30~~appropriate, ~~2025~~ ~~our~~to ~~disclosure~~allow ~~controls~~for ~~and~~timely ~~procedures~~decisions ~~are~~regarding ~~effective in ensuring that the information~~ required ~~to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms~~disclosure.

~~Under~~As required by SEC Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, ~~during~~of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15(d)-15(e)) as of the end of the quarter ~~ended~~covered ~~September 30~~by this report. In designing and evaluating our disclosure controls and procedures, ~~2025,~~ weour ~~have~~management ~~determined~~recognizes that ~~there~~controls ~~have~~and ~~been~~procedures, no ~~changes~~matter inhow ~~our~~well ~~internal~~designed and operated, can provide only reasonable assurance of achieving desired control ~~over~~objectives. ~~financial~~Based ~~reporting~~on the foregoing, our Principal Executive Officer and Principal Financial Officer concluded that ~~have~~as ~~materially~~of ~~affected~~December 31, 2025 orour disclosure controls and procedures are ~~reasonably~~effective ~~likely~~in ensuring that the information required to ~~materially~~be ~~affect,~~disclosed in our ~~internal~~reports ~~control~~filed ~~over~~or ~~financial~~submitted ~~reporting~~under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms.

Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, during the quarter ended December 31, 2025, we have determined that there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

See Note 10, “Commitments and Contingencies” to our unaudited condensed consolidated financial statements in Item 1. Condensed Consolidated Financial Statements (Unaudited) for a description of any legal proceedings, which is incorporated herein by reference.

Item 1A. Risk Factors

Our Annual Report on Form 10-K for the year ended June 30, 2025 includes a detailed description of our risk factors.

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

Issuer Purchases of Equity Securities

The table below summarizes information about the Company's purchases of its equity securities during the three months ended ~~September~~December 3031, 2025.


				(c) Total number	(d) Maximum dollar value
	(a) Total number			of shares	of shares that may yet be
	of shares			purchased as part	purchased under the
	purchased and	(b) Average price		of public announced	plans or programs
Period	received (1)	paid per share (1)		plans or programs	(in thousands)
July 2025	—	$	—	—	$	—
October 2025	11,356	$	4.40	—	$	—
August 2025	25,645		5.16	—		—
November 2025	—		—	—		—
September 2025	—		—	—		—
December 2025	—		—	—		—

(1) During the three months ended ~~September~~December 3031, 2025, all of the shares received were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards.

Item 3. Defaults Upon Senior Securities

Not Applicable.

Item 4. Mine Safety Disclosures

Not Applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

The following documents are included as exhibits to the Quarterly Report on Form 10-Q. Those exhibits incorporated by reference are so indicated by the information supplied with respect thereto. Those exhibits which are not incorporated by reference are attached hereto.









3.1		Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q filed February 8, 2023).
3.3		Amended and Restated Bylaws (incorporated by reference to Exhibit 3.3 of our Annual Report on Form 10- filed September 13, 2023)
10.2.2*		Letter Agreement to the Credit Agreement dated November 28, 2025 between Evolution Petroleum and MidFirst Bank
31.1**		Certification of Principal Executive Officer Pursuant to Rule 15D-14 of the Securities Exchange Act of 1934, as Amended as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2**		Certification of Principal Financial Officer Pursuant to Rule 15D-14 of the Securities Exchange Act of 1934, as Amended as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**		Certification of Principal 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**		Certification of Principal 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
101.SCH*		Inline XBRL Taxonomy Extension Schema Document
101.CAL*		Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*		Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*		Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*		Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*		Cover Page Interactive Data File (embedded within the Inline XBRL document)

* Attached hereto.

** Furnished herewith.

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SIGNATURES

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

	Evolution Petroleum Corporation
	Evolution Petroleum Corporation
Date: November 12, 2025	By:	/s/ KELLY W. LOYD
Date: February 11, 2026	By:	/s/ KELLY W. LOYD
		Kelly W. LoydPresident and Chief Executive Officer (Principal Executive Officer) and Director
	By:	/s/ RYAN STASH
		Ryan StashSenior Vice President and Chief Financial Officer (Principal Financial Officer) and Treasurer

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