Evolution Petroleum Corp 10-Q for FY2026 Q2
Evolution Petroleum Corp (EPM)
About this 10-Q
Evolution Petroleum Corp filed this 10-Q on February 11, 2026, covering the quarter ended December 31, 2025 (FY2026 Q2).
Headline figures
Quarter ended December 31, 2025, as reported in this filing, compared with the same period a year earlier where the filing states it.
- Revenue
- $20.68M
- up 2.0% from $20.28M a year earlier
- Net income
- $1.07M
- compared with a net loss of $1.83M a year earlier
- Diluted EPS
- $0.03
- compared with -$0.06 a year earlier
no
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
For the quarterly period ended
For the transition period from to
Commission File Number
(Exact name of registrant as specified in its charter)
| ||
(State or other jurisdiction of | | (IRS Employer Identification No.) |
(Address of principal executive offices and zip code)
(
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| | | | |
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.
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).
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.
| | | | | | | |
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:
At February 6, 2026,
EVOLUTION PETROLEUM CORPORATION
TABLE OF CONTENTS
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.
1
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; |
2
| ● | 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.
3
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)
| | December 31, 2025 | | June 30, 2025 | ||
Assets | | |
| | |
|
Current assets | | |
| | |
|
Cash and cash equivalents | | $ | | | $ | |
Receivables from crude oil, natural gas, and natural gas liquids revenues | | | | | | |
Derivative contract assets | | | | | | |
Prepaid expenses and other current assets | | | | | | |
Total current assets | | | | | | |
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 | | | | | | |
Oil and natural gas properties, not subject to amortization | | | | | | — |
Total property and equipment, net | | | | | | |
| | | | | | |
Other noncurrent assets | | | | | | |
Derivative contract assets | | | | | | |
Other assets | | | | | | |
Total assets | | $ | | | $ | |
Liabilities and Stockholders' Equity | | |
| | | |
Current liabilities | | |
| | | |
Accounts payable | | $ | | | $ | |
Accrued liabilities and other | | | | | | |
Derivative contract liabilities | | | | | | |
State and federal taxes payable | | | | | | — |
Total current liabilities | | | | | | |
Long term liabilities | | |
| | | |
Senior secured credit facility | | | | | | |
Deferred income taxes | | | | | | |
Asset retirement obligations | | | | | | |
Derivative contract liabilities | | | | | | |
Operating lease liability | | | | | | — |
Total liabilities | | | | | | |
Commitments and contingencies (Note 10) | | | | | | |
Stockholders' equity | | |
| | | |
Common stock; par value $ | | | | | | |
| | | | | | |
and June 30, 2025, respectively | | | | | | |
Additional paid-in capital | | | | | | |
Retained earnings | | | | | | |
Total stockholders' equity | | | | | | |
Total liabilities and stockholders' equity | | $ | | | $ | |
See accompanying notes to unaudited condensed consolidated financial statements.
4
EVOLUTION PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(In thousands, except per share amounts)
| | Three Months Ended | | Six Months Ended | ||||||||
| | December 31, | | December 31, | ||||||||
| | 2025 | | 2024 | | 2025 | | 2024 | ||||
Revenues | | | | | | | | | | | | |
Crude oil | | $ | | | $ | | | $ | | | $ | |
Natural gas | | | | | | | | | | | | |
Natural gas liquids | | | | | | | | | | | | |
Total revenues | | | | | | | | | | | | |
Operating costs | | |
| | |
| | | | | |
|
Lease operating costs | | | | | | | | | | | | |
Depletion, depreciation, and accretion | | | | | | | | | | | | |
General and administrative expenses | | | | | | | | | | | | |
Total operating costs | | | | | | | | | | | | |
Income (loss) from operations | | | | | | ( | | | | | | |
Other income (expense) | | |
| | |
| | | | | |
|
Net gain (loss) on derivative contracts | | | | | | ( | | | | | | |
Interest and other income | | | | | | | | | | | | |
Interest expense | | | ( | | | ( | | | ( | | | ( |
Income (loss) before income taxes | | | | | | ( | | | | | | |
Income tax (expense) benefit | | | ( | | | | | | ( | | | ( |
Net income (loss) | | $ | | | $ | ( | | $ | | | $ | |
Net income (loss) per common share: | | |
| | |
| | |
| | |
|
Basic | | $ | | | $ | ( | | $ | | | $ | — |
Diluted | | $ | | | $ | ( | | $ | | | $ | — |
Weighted average number of common shares outstanding: | | |
| | |
| | |
| | |
|
Basic | | | | | | | | | | | ||
Diluted | | | | | | | | | | | ||
See accompanying notes to unaudited condensed consolidated financial statements.
5
EVOLUTION PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In thousands)
| Six Months Ended December 31, | |||||
| | 2025 | | 2024 | ||
Cash flows from operating activities: | | |
| | |
|
Net income (loss) | | $ | | | $ | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | |
| | | |
Depletion, depreciation, and accretion | | | | | | |
Stock-based compensation | | | | | | |
Settlement of asset retirement obligations | | | ( | | | ( |
Deferred income taxes | | | ( | | | ( |
Unrealized (gain) loss on derivative contracts | | | ( | | | ( |
Accrued settlements on derivative contracts | | | ( | | | ( |
Amortization of debt issuance costs | | | | | | — |
Other | | | ( | | | ( |
Changes in operating assets and liabilities: | | |
| | | |
Receivables from crude oil, natural gas, and natural gas liquids revenues | | | | | | ( |
Prepaid expenses and other current assets | | | | | | |
Accounts payable, accrued liabilities and other | | | ( | | | |
State and federal taxes payable | | | | | | ( |
Net cash provided by operating activities | | | | | | |
Cash flows from investing activities: | | | | | | |
Acquisition of oil and natural gas properties | | | ( | | | ( |
Capital expenditures for oil and natural gas properties | | | ( | | | ( |
Net cash used in investing activities | | | ( | | | ( |
Cash flows from financing activities: | | |
| | |
|
Common stock dividends paid | | | ( | | | ( |
Common stock repurchases, including stock surrendered for tax withholding | | | ( | | | ( |
Borrowings under senior secured credit facility | | | | | | — |
Repayments of senior secured credit facility | | | ( | | | — |
Debt issuance costs | | | ( | | | — |
Issuance of common stock | | | | | | |
Offering costs | | | ( | | | ( |
Net cash provided by (used in) financing activities | | | | | | ( |
Net increase (decrease) in cash and cash equivalents | | | | | | |
Cash and cash equivalents, beginning of period | | | | | | |
Cash and cash equivalents, end of period | | $ | | | $ | |
| | | | | | |
Supplemental disclosures of cash flow information: | | | | | | |
Non-cash investing and financing transactions: | | | | | | |
Increase (decrease) in accrued capital expenditures for oil and natural gas properties | | $ | ( | | $ | ( |
Oil and natural gas property costs attributable to the recognition (derecognition) of asset retirement obligations | | | ( | | | ( |
See accompanying notes to unaudited condensed consolidated financial statements.
6
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 December 31, 2025 | | | | | | | | | | | | | | | | | |
Balances at September 30, 2025 | | | | $ | | | $ | | | $ | | | $ | — | | $ | |
Issuance of restricted common stock | | | | | — | | | — | | | — | | | — | | | — |
Common stock repurchases, including stock surrendered for tax withholding | | — | | | — | | | — | | | — | | | ( | | | ( |
Retirements of treasury stock | | ( | | | — | | | ( | | | — | | | | | | — |
Issuance of common stock | | | | | — | | | | | | — | | | — | | | |
Offering costs | | — | | | — | | | ( | | | — | | | — | | | ( |
Stock-based compensation | | — | | | — | | | | | | — | | | — | | | |
Net income (loss) | | — | | | — | | | — | | | | | | — | | | |
Common stock dividends paid | | — | | | — | | | — | | | ( | | | — | | | ( |
Balances at December 31, 2025 | | | | $ | | | $ | | | $ | | | $ | — | | $ | |
| | | | | | | | | | | | | | | | | |
For the Six Months Ended December 31, 2025 | | | | | | | | | | | | | | | | | |
Balances at June 30, 2025 | | | | $ | | | $ | | | $ | | | $ | — | | $ | |
Issuance of restricted common stock | | | | | | | | ( | | | — | | | — | | | — |
Common stock repurchases, including stock surrendered for tax withholding | | — | | | — | | | — | | | — | | | ( | | | ( |
Retirements of treasury stock | | ( | | | — | | | ( | | | — | | | | | | — |
Issuance of common stock | | | | | — | | | | | | — | | | — | | | |
Offering costs | | — | | | — | | | ( | | | — | | | — | | | ( |
Stock-based compensation | | — | | | — | | | | | | — | | | — | | | |
Net income (loss) | | — | | | — | | | — | | | | | | — | | | |
Common stock dividends paid | | — | | | — | | | — | | | ( | | | — | | | ( |
Balances at December 31, 2025 | | | | $ | | | $ | | | $ | | | $ | — | | $ | |
| | | | | | | | | | | | | | | | | |
For the Three Months Ended December 31, 2024 | | | | | | | | | | | | | | | | | |
Balances at September 30, 2024 | | | | $ | | | $ | | | $ | | | $ | — | | $ | |
Issuance of restricted common stock | | | | | — | | | — | | | — | | | — | | | — |
Forfeitures of restricted stock | | ( | | | — | | | — | | | — | | | — | | | — |
Common stock repurchases, including stock surrendered for tax withholding | | — | | | — | | | — | | | — | | | ( | | | ( |
Retirements of treasury stock | | ( | | | — | | | ( | | | — | | | | | | — |
Issuance of common stock | | | | | — | | | | | | — | | | — | | | |
Offering costs | | — | | | — | | | ( | | | — | | | — | | | ( |
Stock-based compensation | | — | | | — | | | | | | — | | | — | | | |
Net income (loss) | | — | | | — | | | — | | | ( | | | — | | | ( |
Common stock dividends paid | | — | | | — | | | — | | | ( | | | — | | | ( |
Balances at December 31, 2024 | | | | $ | | | $ | | | $ | | | $ | — | | $ | |
| | | | | | | | | | | | | | | | | |
For the Six Months Ended December 31, 2024 | | | | | | | | | | | | | | | | | |
Balances at June 30, 2024 | | | | $ | | | $ | | | $ | | | $ | — | | $ | |
Issuance of restricted common stock | | | | | | | | ( | | | — | | | — | | | — |
Forfeitures of restricted stock | | ( | | | — | | | — | | | — | | | — | | | — |
Common stock repurchases, including stock surrendered for tax withholding | | — | | | — | | | — | | | — | | | ( | | | ( |
Retirements of treasury stock | | ( | | | — | | | ( | | | — | | | | | | — |
Issuance of common stock | | | | | — | | | | | | — | | | — | | | |
Offering costs | | — | | | — | | | ( | | | — | | | — | | | ( |
Stock-based compensation | | — | | | — | | | | | | — | | | — | | | |
Net income (loss) | | — | | | — | | | — | | | | | | — | | | |
Common stock dividends paid | | — | | | — | | | — | | | ( | | | — | | | ( |
Balances at December 31, 2024 | | | | $ | | | $ | | | $ | | | $ | — | | $ | |
See accompanying notes to unaudited condensed consolidated financial statements.
7
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
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
8
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
The accounting policies of the
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.
9
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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
| | Three Months Ended | | Six Months Ended | ||||||||
| | December 31, | | December 31, | ||||||||
| | 2025 | | 2024 | | 2025 | | 2024 | ||||
Revenues | | | | | | | | | | | | |
Crude oil | | $ | | | $ | | | $ | | | $ | |
Natural gas | | | | | | | | | | | | |
Natural gas liquids | | | | | | | | | | | | |
Total revenues | | $ | | | $ | | | $ | | | $ | |
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 to
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 to
10
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 $
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 $
Note 4. Property and Equipment
Property and equipment consisted of the following for the periods presented (in thousands):
| | December 31, 2025 | | June 30, 2025 | ||
Oil and natural gas properties | | |
| | |
|
Property costs subject to amortization | | $ | | | $ | |
Property costs not subject to amortization | | | | | | — |
Less: Accumulated depletion, depreciation, and impairment | | | ( | | | ( |
Oil and natural gas properties, net | | $ | | | $ | |
As of December 31, 2025, $
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.
11
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 $
At December 31, 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 December 31, 2025 of the West Texas Intermediate (“WTI”) crude oil spot price of $
At December 31, 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 December 31, 2024 of the WTI crude oil spot price of $
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 $
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
12
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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
On November 28, 2025, the Company entered into a letter agreement with MidFirst Bank pursuant to which Margined Collateral Value, as defined under the Senior Secured Credit, was modified to $
On August 29, 2025, the Company entered into the first amendment of its Senior Secured Credit Facility with MidFirst Bank pursuant to which it was determined for purposes of the hedge covenant that total crude oil and natural gas volumes from proved developed producing reserves will be combined on a barrels of oil equivalent basis to determine compliance with the required hedging 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 $
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
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 six months ended December 31, 2025, include the OBBBA’s effect for the period beginning July 1, 2025, through 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
13
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 $
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
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 December 31, 2025, the Company did
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
14
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
the difference between the market commodity prices and the hedged prices for the remaining volumes of production hedges as of December 31, 2025 and June 30, 2025 (the “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 | | $ | | | $ | | | Current liabilities - derivative contract liabilities | | $ | | | $ | |
Commodity contracts | | Other noncurrent assets - derivative contract assets | | | | | | | | Long term liabilities - derivative contract liabilities | | | | | | |
Total derivatives not designated as hedging contracts under ASC 815 | | | | $ | | | $ | | | | | $ | | | $ | |
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.
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 | | $ | | | $ | | | $ | | | $ | |
Unrealized gain (loss) on derivative contracts | | Other income and expenses - net gain (loss) on derivative contracts | | | | | | ( | | | | | | |
Total net gain (loss) on derivative contracts | | | | $ | | | $ | ( | | $ | | | $ | |
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 | | | | $ | | | | | | | | | | |
January 2027 - January 2027 | | Crude Oil | | Fixed-Price Swap | | | | | | | | | | | | | | |
January 2026 - December 2026 | | Crude Oil | | Two-Way Collar | | | | | | | | | | $ | | | $ | |
September 2026 - December 2026 | | Crude Oil | | Three-Way Collar | | | | | | | $ | | | | | | | |
January 2026 - December 2026 | | Natural Gas | | Fixed-Price Swap | | | | | | | | | | | | | | |
January 2027 - December 2027 | | Natural Gas | | Fixed-Price Swap | | | | | | | | | | | | | | |
January 2026 - December 2026 | | Natural Gas | | Two-Way Collar | | | | | | | | | | | | | | |
January 2027 - March 2027 | | Natural Gas | | Two-Way Collar | | | | | | | | | | | | | | |
15
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Subsequent to December 31, 2025, the Company entered into the following 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 | | | | $ | | | | | | | | | | |
January 2027 - March 2027 | | Crude Oil | | Fixed-Price Swap | | | | | | | | | | | | | | |
January 2027 - March 2027 | | Crude Oil | | Two-Way Collar | | | | | | | | | | $ | | | $ | |
January 2027 - February 2027 | | Natural Gas | | Two-Way Collar | | | | | | | | | | | | | | |
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 | | December 31, 2025 | | June 30, 2025 | | December 31, 2025 | | June 30, 2025 | ||||
Gross amounts presented in the Consolidated Balance Sheet | | $ | | | $ | | | $ | | | $ | |
Amounts not offset in the Consolidated Balance Sheet | | | ( | | | ( | | | ( | | | ( |
Net amount | | $ | | | $ | | | $ | | | $ | |
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.
16
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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.
| | December 31, 2025 | ||||||||||
| | Level 1 | | Level 2 | | Level 3 | | Total | ||||
Assets | | | | | | | | | | | | |
Derivative contract assets | | $ | — | | $ | | | $ | — | | $ | |
| | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | |
Derivative contract liabilities | | $ | — | | $ | | | $ | — | | $ | |
| | June 30, 2025 | ||||||||||
| | Level 1 | | Level 2 | | Level 3 | | Total | ||||
Assets | | | | | | | | | | | | |
Derivative contract assets | | $ | — | | $ | | | $ | — | | $ | |
| | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | |
Derivative contract liabilities | | $ | — | | $ | | | $ | — | | $ | |
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.
17
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 9. Asset Retirement Obligations
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 capitalizes the cost in “Oil and natural gas properties, subject to amortization, net” during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in “Depletion, depreciation and accretion” expense in the unaudited condensed consolidated statements of operations.
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 | | $ | |
Liabilities settled and divested | | | ( |
Accretion of discount | | | |
Asset retirement obligations — end of period | | | |
Less: current asset retirement obligations | | | ( |
Long-term portion of asset retirement obligations | | $ | |
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 December 31, 2025, the Company had
The Company began paying quarterly cash dividends on common stock in December 2013. As of December 31, 2025, the Company has cumulatively paid over $
The following table reflects the dividends paid per share within the respective three-month periods:
| | Fiscal Year | ||||
| | 2026 | | 2025 | ||
Second fiscal quarter | | $ | | | $ | |
First fiscal quarter | | | | | | |
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 $
18
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
of $
On September 8, 2022, the Board of Directors approved a share repurchase program, under which the Company was authorized to repurchase up to $
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):
| | Six Months Ended | ||||
| | December 31, | ||||
| | 2025 | | 2024 | ||
Number of treasury shares acquired | | | | | | |
Average cost per share | | $ | | | $ | |
Total cost of treasury shares acquired | | $ | | | $ | |
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 December 31, 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
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 December 31, 2025, the Company recognized $
19
EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Time-Vested Restricted Stock Awards
Time-vested restricted stock awards contain service-based vesting conditions and expire after a maximum of
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
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
During the six months ended December 31, 2025, the Company granted a total of
During the six months ended December 31, 2024, the Company granted a total of
For performance-based awards granted during the six months ended December 31, 2025 and 2024, the assumptions used in the Monte Carlo simulation valuations were as follows:
| | Six Months Ended | ||||
| | December 31, | ||||
| | 2025 | | 2024 | ||
Weighted average fair value of performance-based awards granted | | $ | | | $ | |
Risk-free interest rate | | | | | ||
Expected term in years | | | | | ||
Expected volatility | | | | | ||
Dividend yield | | | | | ||
20
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 | | | | $ | |
Performance-based awards | | | | | |
Unvested at December 31, 2025 | | | | $ | |
The following table sets forth the restricted stock award transactions for the six months ended December 31, 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 | | | | $ | | | $ | | | |
Time-vested shares granted | | | | | | | | | | |
Performance-based shares granted | | | | | | | | | | |
Vested | | ( | | | | | | | | |
Unvested at December 31, 2025 | | | | $ | | | $ | | | |
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 | | | | $ | | | $ | | | |
Unvested at December 31, 2025 | | | | $ | | | $ | | | |
21
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 | ||||||||
| | December 31, | | December 31, | ||||||||
| | 2025 | | 2024 | | 2025 | | 2024 | ||||
Numerator | | |
| | |
| | |
| | |
|
Net income (loss) | | $ | | | $ | ( | | $ | | | $ | |
Undistributed earnings allocated to unvested restricted stock | | | ( | | | ( | | | ( | | | ( |
Net income (loss) for earnings per share calculation | | $ | | | $ | ( | | $ | | | $ | |
| | |
| | |
| | |
| | |
|
Denominator | | | | | | | | | | | | |
Weighted average number of common shares outstanding — Basic | | | | | | | | | | | | |
Effect of dilutive securities: | | | | | | | | | | | | |
Unvested restricted stock awards | | | | | | — | | | | | | |
Unvested contingent restricted stock units | | | — | | | — | | | | | | — |
Weighted average number of common shares and dilutive potential common shares used in diluted earnings per share | | | | | | | | | | | | |
| | | | | | | | | | | | |
Net income (loss) per common share — Basic | | $ | | | $ | ( | | $ | | | $ | — |
Net income (loss) per common share — Diluted | | $ | | | $ | ( | | $ | | | $ | — |
Unvested restricted stock awards, totaling
Unvested restricted stock awards, totaling
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
22
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
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 | | $ | | | | $ | | |
Variable lease costs | | | | | | | | |
Total lease costs | | $ | | | | $ | | |
| | | | | | | | |
Statements of Cash Flow: | | | | | | | | |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | | | | |
Operating cash flows from operating leases | | $ | | | | $ | | |
| | | | | | | | |
Other: | | | | | | | | |
ROU assets obtained in exchange for new operating lease liabilities | | $ | | | | $ | — | |
Weighted average remaining lease term in years | | | | | | | ||
Weighted average discount rate | | | | % | | | | % |
The following table presents the Company’s ROU assets and lease liabilities (in thousands):
| | December 31, 2025 | | | June 30, 2025 | ||
Balance Sheets: | | | | | | | |
| $ | | | | $ | | |
| | | | | | | |
Operating lease liability - long-term | | | | | | | — |
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 | | $ | |
2027 | | | |
2028 | | | |
2029 | | | |
2030 | | | |
Thereafter | | | |
Total operating lease payments | | | |
Less: discount to present value | | | ( |
| | | |
Less: current operating lease liabilities | | | |
Non current operating lease liabilities | | $ | |
23
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):
| | December 31, 2025 | | June 30, 2025 | ||
Prepaid expenses and other current assets: | | | | | | |
Other receivables | | $ | | | $ | |
Prepaid insurance | | | | | | |
Prepaid federal and state income taxes | | | | | | |
Advances to operators | | | | | | |
Prepaid other | | | | | | |
Total prepaid expenses and other current assets | | $ | | | $ | |
| | | | | | |
Other assets: | | | | | | |
Deposit | | $ | | | $ | |
Debt issuance costs, net | | | | | | |
| | | | | | |
Total other assets | | $ | | | $ | |
| | | | | | |
Accrued liabilities and other: | | | | | | |
Accrued payables | | $ | | | $ | |
Accrued capital expenditures | | | | | | |
Accrued incentive and other compensation | | | | | | |
Accrued royalties payable(1) | | | | | | |
Accrued taxes other than federal and state income tax | | | | | | |
Accrued settlements on derivative contracts | | | | | | — |
| | | | | | |
Asset retirement obligations due within one year | | | | | | |
Accrued interest and other | | | | | | |
Total accrued liabilities and other | | $ | | | $ | |
| (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 15. Subsequent Events
Dividend Declaration
On
24
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Liquidity and Capital Resources
Commonly Used Terms
“Current quarter” refers to the three months ended December 31, 2025, our second quarter of fiscal year 2026.
“Year-ago quarter” refers to the three months ended December 31, 2024, our 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 six months ended December 31, 2025 is comprised of 54% natural gas, 25% 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 six months ended December 31, 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 six months ended December 31, 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 |
25
| 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 six months ended December 31, 2025 is comprised of 72% crude oil, 17% NGL, and 11% 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 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 six months ended December 31, 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 six months ended December 31, 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 six months ended December 31, 2025 is comprised of 80% crude oil and 20% 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 six months ended December 31, 2025 is comprised of 56% crude oil and 44% natural gas. |
Recent Developments
Dividend Declaration
On February 9, 2026, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable March 31, 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 $16.3 million, which includes $17.0 million paid at closing less interim purchase price adjustments totaling approximately $0.7 million related to net cash flows earned on the properties from the effective date to the
26
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, (including ongoing conflicts between Russia and Ukraine, 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 December 31, 2025, we had $3.8 million in cash and cash equivalents and $54.5 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 six months ended December 31, 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 six months ended December 31, 2025 were cash used to fund our Minerals Acquisition, cash dividend payments to our common stockholders, and development capital expenditures. As of December 31, 2025, working capital was a deficit of $2.0 million. As of June 30, 2025, working capital was a deficit of $4.0 million.
27
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 a percentage of 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 December 31, 2025, we had $54.5 million of indebtedness, $0.8 million of letters of credit outstanding, and available capacity of $9.7 million. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on June 30, 2028.
For the six months ended December 31, 2025 and 2024, the weighted average interest on our borrowings was 6.88% and 7.80%, respectively. Borrowings bear interest, at our option, at either (i) the 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 1.0%, plus, in either case of (i) or (ii), an applicable margin of 2.75%. The Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a 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. 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 Senior 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 $9.7 million as of December 31, 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 six months ended December 31, 2025, we sold a total of approximately 0.3 million shares of our common stock under the ATM Sales Agreement for net proceeds of approximately $1.2 million, net of $46 thousand of offering costs.
Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 49 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, subject to adjustments as appropriate in the Board of Directors’ discretion depending on factors such as commodity prices, other opportunities for uses of capital, and any other factors the Board of Directors deems
28
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 six months ending December 31, 2025, we incurred $2.5 million on development capital expenditures. A majority of our spending occurred at SCOOP/STACK where our operators are actively drilling. Three gross wells were brought online during the first quarter of the year, and three gross wells are currently 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.
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 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.
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 December 31, 2025 were $66.01 per barrel of oil, $3.40 per MMBtu of natural gas and $23.22 per barrel of NGLs. As of December 31, 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 December 31, 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 January and February 2026, which are more reflective of recent prices trends, to calculate a trailing 12-month average price of $64.05 per barrel of oil and $3.80 per MMBtu of natural gas, and keeping all other factors constant, the ceiling test calculation as of the 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
| | Six Months Ended December 31, | | | | ||||
| | 2025 | | 2024 | | Change | |||
Cash flows provided by operating activities | | $ | 13,230 | | $ | 15,333 | | $ | (2,103) |
Cash flows used in investing activities | | | (21,303) | | | (3,829) | | | (17,474) |
Cash flows provided by (used in) financing activities | | | 9,328 | | | (6,283) | | | 15,611 |
Net increase (decrease) in cash and cash equivalents | | $ | 1,255 | | $ | 5,221 | | $ | (3,966) |
Cash provided by operating activities for the six months ended December 31, 2025 decreased $2.1 million compared to the six months ended December 31, 2024 primarily due a decrease in revenues and increases in our interest expense and lease operating costs for the comparable periods partially offset by realized gains on derivative contracts in the current
29
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.
30
Results of Operations
Three Months Ended December 31, 2025 and 2024
We reported net income of $1.1 million and net loss of $1.8 million for the three months ended December 31, 2025 and 2024, respectively. The following table summarizes the comparison of financial information for the periods presented:
| | Three Months Ended | | | | | | | ||||
| | December 31, | | | | | | | ||||
(in thousands, except per unit and per BOE amounts) | | 2025 | | 2024 | | Variance | | Variance % | ||||
Net income (loss) | | $ | 1,065 | | $ | (1,825) | | $ | 2,890 | | (158.4) | % |
Revenues: | | | | | | | | | | | | |
Crude oil | | | 10,696 | | | 11,763 | | | (1,067) | | (9.1) | % |
Natural gas | | | 7,441 | | | 5,793 | | | 1,648 | | 28.4 | % |
Natural gas liquids | | | 2,542 | | | 2,719 | | | (177) | | (6.5) | % |
Total revenues | | | 20,679 | | | 20,275 | | | 404 | | 2.0 | % |
Operating costs: | | | | | | | | | | | | |
Lease operating costs: | | | | | | | | | | | | |
Ad valorem and production taxes | | | 588 | | | 1,441 | | | (853) | | (59.2) | % |
Gathering, transportation, and other costs | | | 2,667 | | | 2,889 | | | (222) | | (7.7) | % |
Other lease operating costs | | | 8,255 | | | 8,463 | | | (208) | | (2.5) | % |
Depletion, depreciation, and accretion: | | | | | | | | | | | | |
Depletion of full cost proved oil and natural gas properties | | | 5,532 | | | 5,024 | | | 508 | | 10.1 | % |
Accretion of asset retirement obligations | | | 387 | | | 409 | | | (22) | | (5.4) | % |
General and administrative expenses: | | | | | | | | | | | | |
General and administrative | | | 1,979 | | | 1,995 | | | (16) | | (0.8) | % |
Stock-based compensation | | | 613 | | | 659 | | | (46) | | (7.0) | % |
Other income (expense): | | | | | | | | | | | | |
Net gain (loss) on derivative contracts | | | 2,235 | | | (1,219) | | | 3,454 | | (283.3) | % |
Interest and other income | | | 12 | | | 52 | | | (40) | | (76.9) | % |
Interest expense | | | (1,003) | | | (764) | | | (239) | | 31.3 | % |
Income tax (expense) benefit | | | (837) | | | 711 | | | (1,548) | | (217.7) | % |
| | | | | | | | | | | | |
Production: | | | | | | | | | | | | |
Crude oil (MBBL) | | | 193 | | | 179 | | | 14 | | 7.8 | % |
Natural gas (MMCF) | | | 2,241 | | | 2,125 | | | 116 | | 5.5 | % |
Natural gas liquids (MBBL) | | | 112 | | | 105 | | | 7 | | 6.7 | % |
Equivalent (MBOE)(1) | | | 679 | | | 638 | | | 41 | | 6.4 | % |
Average daily production (BOEPD)(1) | | | 7,380 | | | 6,935 | | | 445 | | 6.4 | % |
| | | | | | | | | | | | |
Average price per unit(2): | | | | | | | | | | | | |
Crude oil (BBL) | | $ | 55.42 | | $ | 65.72 | | $ | (10.30) | | (15.7) | % |
Natural gas (MCF) | | | 3.32 | | | 2.73 | | | 0.59 | | 21.6 | % |
Natural Gas Liquids (BBL) | | | 22.70 | | | 25.90 | | | (3.20) | | (12.4) | % |
Equivalent (BOE)(1) | | | 30.46 | | | 31.78 | | | (1.32) | | (4.2) | % |
| | | | | | | | | | | | |
Average cost per unit: | | | | | | | | | | | | |
Operating costs: | | | | | | | | | | | | |
Lease operating costs: | | | | | | | | | | | | |
Ad valorem and production taxes | | | 0.87 | | | 2.26 | | | (1.39) | | (61.5) | % |
Gathering, transportation, and other costs | | | 3.93 | | | 4.53 | | | (0.60) | | (13.2) | % |
Other lease operating costs | | | 12.16 | | | 13.26 | | | (1.10) | | (8.3) | % |
Depletion of full cost proved oil and natural gas properties | | | 8.15 | | | 7.87 | | | 0.28 | | 3.6 | % |
General and administrative expenses: | | | | | | | | | | | | |
General and administrative | | | 2.91 | | | 3.13 | | | (0.22) | | (7.0) | % |
Stock-based compensation | | | 0.90 | | | 1.03 | | | (0.13) | | (12.6) | % |
| (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. |
31
Revenues
Crude oil, natural gas and NGL revenues were $20.7 million and $20.3 million for the three months ended December 31, 2025 and 2024, respectively, with the increase in revenues due to an increase in production volumes partially offset by decreases in our average realized price per BOE. Average daily equivalent production increased 6.4% to 7,380 BOEPD in the current year period from 6,935 BOEPD in the prior period primarily as a result 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 December 31, 2025 decreased approximately $1.32 per BOE, or 4.2%, over the prior year period as our realized crude oil decreased 15.7% and realized NGL prices decreased 12.4% from the three months ended December 31, 2024. The overall decrease in our realized crude oil and NGL prices was partially offset by a 21.6% 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 the three months ended December 31, 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 $0.87 per BOE and $2.26 per BOE for the three months ended December 31, 2025 and 2024, respectively.
Gathering, transportation and other costs were $2.7 million for the three months ended December 31, 2025 compared to $2.9 million for the three 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 and Barnett Shale. On a per unit basis, gathering, transportation and other costs were $3.93 per BOE and $4.53 per BOE for the three months ended December 31, 2025 and 2024, respectively.
Other lease operating costs were $8.3 million for the three months ended December 31, 2025 compared to $8.5 million for the three months ended December 31, 2024. Other lease operating costs 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 $1.1 million over the prior year period. On a per unit basis, other lease operating costs decreased to $12.16 per BOE for the three months ended December 31, 2025 from $13.26 per BOE in the three months ended December 31, 2024.
Depletion of Full Cost Proved Oil and Natural Gas Properties
Depletion expense increased from $5.0 million for the three months ended December 31, 2024 to $5.5 million for the three 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 $8.15 per BOE and $7.87 per BOE for the three months ended December 31, 2025 and 2024, respectively.
General and Administrative Expenses
General and administrative expenses were $2.0 million for each of the periods ended December 31, 2025 and 2024. On a per unit basis, general and administrative expenses were $2.91 per BOE and $3.13 per BOE for the three months ended December 31, 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 December 31, 2025 was $0.6 million compared to $0.7 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.
32
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.
| | Three Months Ended | | | | | | | ||||
| | December 31, | | | | | | | ||||
(in thousands, except per unit and per BOE amounts) | | 2025 | | 2024 | | Variance | | Variance % | ||||
Realized gain (loss) on derivative contracts | | $ | 792 | | $ | 149 | | $ | 643 | | 431.5 | % |
Unrealized gain (loss) on derivative contracts | | | 1,443 | | | (1,368) | | | 2,811 | | (205.5) | % |
Total net gain (loss) on derivative contracts | | $ | 2,235 | | $ | (1,219) | | $ | 3,454 | | (283.3) | % |
| | | | | | | | | | | | |
Average realized crude oil price per BBL | | $ | 55.42 | | $ | 65.72 | | $ | (10.30) | | (15.7) | % |
Cash effect of oil derivative contracts per BBL | | | 1.69 | | | 0.83 | | | 0.86 | | 103.6 | % |
Crude oil price per BBL (including impact of realized derivatives) | | $ | 57.11 | | $ | 66.55 | | $ | (9.44) | | (14.2) | % |
| | | | | | | | | | | | |
Average realized natural gas price per MCF | | $ | 3.32 | | $ | 2.73 | | $ | 0.59 | | 21.6 | % |
Cash effect of natural gas derivative contracts per MCF | | | 0.21 | | | — | | | 0.21 | | — | % |
Natural gas price per MCF (including impact of realized derivatives) | | $ | 3.53 | | $ | 2.73 | | $ | 0.80 | | 29.3 | % |
Interest Expense
Interest expense increased $0.2 million for the three 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.
Income Tax (Expense) Benefit
For the three months ended December 31, 2025, we recognized income tax expense of $0.8 million on net income before income taxes of $1.9 million compared to income tax benefit of $0.7 million on net losses before income taxes of $2.5 million for the three months ended December 31, 2024. The effective tax rates were 44.0% and 28.0% for three 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 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.
33
Six Months Ended December 31, 2025 and 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. |
34
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.
35
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.
36
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
37
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 procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. Based on the foregoing, our Principal Executive Officer and Principal Financial Officer concluded that as of December 31, 2025 our disclosure controls and procedures are 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.
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.
38
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 December 31, 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) | ||
October 2025 | | 11,356 | | $ | 4.40 | | — | | $ | — |
November 2025 | | — | | | — | | — | | | — |
December 2025 | | — | | — | | — | | | — | |
| (1) | During the three months ended December 31, 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.
None.
39
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 | | |
3.3 | | |
10.2.2* | | |
31.1** | | |
31.2** | | |
32.1** | | |
32.2** | | |
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.
40
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 | |
Date: February 11, 2026 | | By: | /s/ KELLY W. LOYD |
| | | Kelly W. Loyd President and Chief Executive Officer (Principal Executive Officer) and Director |
| | By: | /s/ RYAN STASH |
| | | Ryan Stash Senior Vice President and Chief Financial Officer (Principal Financial Officer) and Treasurer |
41
EXHIBIT 10.2.2
EVOLUTION PETROLEUM CORPORATION
EVOLUTION PETROLEUM OK, INC.
NGS TECHNOLOGIES, INC.
EVOLUTION ROYALTIES, INC.
EVOLUTION PETROLEUM WEST, INC.
1155 Dairy Ashford Rd. Suite 425
Houston, Texas 77079
Attention: Kelly Loyd
E-mail: kloyd@evolutionpetroleum.com
Re: | Amended and Restated Credit Agreement dated as of June 30, 2025, as amended, by and among EVOLUTION PETROLEUM CORPORATION, a Nevada corporation (“EPC”), EVOLUTION PETROLEUM OK, INC., a Texas corporation (“Evolution Texas”), NGS TECHNOLOGIES, INC., a Delaware corporation (“NGS”), EVOLUTION ROYALTIES, INC., a Delaware corporation (“Evolution Royalties”), EVOLUTION PETROLEUM WEST, INC., a Delaware corporation (“Evolution West”; Evolution West, EPC, Evolution Texas, NGS, and Evolution Royalties are collectively referred to herein as the “Borrowers”), the Lenders from time to time party thereto, and MIDFIRST BANK, a federally chartered savings association, as Administrative Agent and Issuing Bank (the “Credit Agreement”). |
Dear Mr. Loyd:
This letter is in reference to the Credit Agreement described above. Capitalized terms not otherwise defined herein shall be defined as set forth in the Credit Agreement. Your execution below memorializes your acknowledgement and agreement to the following:
First, pursuant to Section 2.9(b) of the Credit Agreement, the Administrative Agent hereby notifies you that the Borrowing Base is reaffirmed at $65,000,000.00 effective as of the date hereof until but not including the next regularly scheduled determination of the Borrowing Base (or the next other adjustment to the Borrowing Base in accordance with the terms of the Credit Agreement, whichever occurs first).
Second, also pursuant to Section 2.9(b) of the Credit Agreement, the Administrative Agent hereby notifies you that the MFB Margined Collateral Value is reduced to $65,000,000.00 effective as of the date hereof until but not including the next regularly scheduled determination of the MFB Margined Collateral Value (or the next other adjustment to the MFB Margined Collateral Value in accordance with the terms of the Credit Agreement, whichever occurs first).
Third, notwithstanding anything to the contrary in the Credit Agreement, the Administrative Agent and Lenders hereby agree that Borrower shall have until December 31, 2025 to satisfy the requirements of Section 7.14(a) for the current hedging requirement level by either entering into additional Commodity Hedging Transactions or making a sufficient payment of principal on the Loans.
The rest and remainder of the Credit Agreement and all other Loan Documents executed in connection therewith shall remain unchanged and in full force and effect, except as amended and changed by this letter agreement.
1
Executed this 28th day of November 2025.
Respectfully submitted,
MIDFIRST BANK, as Administrative Agent
By: | /s/ CHAY KRAMER |
| Chay Kramer |
| 1st Vice President |
ACKNOWLEDGED, AGREED AND ACCEPTED, this 28th day of November 2025.
Lenders:
MIDFIRST BANK
By: | /s/ CHAY KRAMER |
| Chay Kramer |
| 1st Vice President |
Prism Bank
By: | /s/ MICHAEL AHOLT |
| Michael Aholt |
| Senior Vice President |
Borrowers:
EVOLUTION PETROLEUM CORPORATION, a Nevada corporation
By: | /s/ KELLY LOYD |
| Kelly Loyd |
| Chief Executive Officer and President |
EVOLUTION PETROLEUM OK, INC., a Texas corporation
By: | /s/ KELLY LOYD |
| Kelly Loyd |
| Chief Executive Officer and President |
NGS TECHNOLOGIES, INC., a Delaware corporation
By: | /s/ KELLY LOYD |
| Kelly Loyd |
| Chief Executive Officer and President |
2
EVOLUTION ROYALTIES, INC., a Delaware corporation
By: | /s/ KELLY LOYD |
| Kelly Loyd |
| Chief Executive Officer and President |
EVOLUTION PETROLEUM WEST, INC., a Delaware corporation
By: | /s/ KELLY LOYD |
| Kelly Loyd |
| Chief Executive Officer and President |
3
EXHIBIT 31.1
CERTIFICATION
I, Kelly W. Loyd, President and Chief Executive Officer (Principal Executive Officer) and Director, of Evolution Petroleum Corporation, certify that:
| 1. | I have reviewed this quarterly report on Form 10-Q of Evolution Petroleum Corporation; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
| 4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
| a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
| c. | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions): |
| a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
| b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Dated: February 11, 2026 | /s/ KELLY W. LOYD |
| Kelly W. Loyd |
| President and Chief Executive Officer (Principal Executive Officer) and Director |
EXHIBIT 31.2
CERTIFICATION
I, Ryan Stash, Senior Vice President, Chief Financial Officer (Principal Financial Officer) and Treasurer of Evolution Petroleum Corporation, certify that:
| 1. | I have reviewed this quarterly report on Form 10-Q of Evolution Petroleum Corporation; |
| 2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
| 3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
| 4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
| a. | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
| b. | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
| c. | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
| d. | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
| 5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions): |
| a. | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
| b. | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Dated: February 11, 2026 | /s/ RYAN STASH |
| Ryan Stash |
| Senior Vice President, Chief Financial Officer (Principal Financial Officer) and Treasurer |
EXHIBIT 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
The undersigned, Kelly W. Loyd, President and Chief Executive Officer (Principal Executive Officer) and Director of Evolution Petroleum Corporation (the “Company”), certifies in connection with the filing with the Securities and Exchange Commission of the Company’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2025 (the “Report”) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to his knowledge, that:
| 1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
| 2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
IN WITNESS WHEREOF, the undersigned has executed this certification as of February 11, 2026.
| /s/ KELLY W. LOYD |
| Kelly W. Loyd |
| President and Chief Executive Officer (Principal Executive Officer) and Director |
A signed original of this written statement required by Section 906 has been provided to Evolution Petroleum Corporation and will be retained by Evolution Petroleum Corporation and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certificate is being furnished to the Securities and Exchange Commission as an exhibit to this Form 10-Q and shall not be considered filed as part of the Form 10-Q.
EXHIBIT 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
The undersigned, Ryan Stash, Senior Vice President, Chief Financial Officer (Principal Financial Officer) and Treasurer of Evolution Petroleum Corporation (the “Company”), certifies in connection with the filing with the Securities and Exchange Commission of the Company’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2025 (the “Report”) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to his knowledge, that:
| 1. | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
| 2. | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
IN WITNESS WHEREOF, the undersigned has executed this certification as of February 11, 2026.
| /s/ RYAN STASH |
| Ryan Stash |
| Senior Vice President, Chief Financial Officer (Principal Financial Officer) and Treasurer |
A signed original of this written statement required by Section 906 has been provided to Evolution Petroleum Corporation and will be retained by Evolution Petroleum Corporation and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certificate is being furnished to the Securities and Exchange Commission as an exhibit to this Form 10-Q and shall not be considered filed as part of the Form 10-Q.