Evolution Petroleum swings to $2.99M loss in fiscal Q1
After a temporary increase to $73.0 million, EPM’s borrowing base was redetermined at $70.0 million on October 20, 2026.
Sentiment and the balance of points
Rhea-AI Sentiment reads the wording of the document, how positive or negative its language is on a 1 to 5 scale. The balance of points shown with the takes weighs what the document actually discloses, so the two can disagree, for example when a trial that missed its main goal is described in upbeat language.
Rhea-AI Filing Summary
Evolution Petroleum Corporation (EPM) reported first-quarter fiscal 2027 revenue of $22.573 million, versus $21.288 million a year earlier, but a $2.992 million net loss compared with $824,000 net income. Operating income was $1.861 million, versus an $85,000 operating loss; net losses on derivative contracts were $5.365 million, compared with a $2.181 million gain. Cash from operations was $3.288 million, versus $7.805 million.
The company completed a Permian minerals acquisition for $16.0 million, subject to customary post-closing adjustments, for approximately 3,420 net royalty acres. It sold approximately 4.3 million shares at $3.25 per share in a concurrent public offering, receiving approximately $12.5 million net; the proceeds, $3.2 million in facility borrowings and cash on hand funded the purchase. At September 30, 2026, cash was $3.1 million and facility borrowings were $60.0 million.
For fiscal 2027, the company expects capital expenditures of $4.0 million to $6.0 million, excluding the Permian purchase, other potential acquisitions and Chaveroo drilling. Its board declared a $0.12-per-share quarterly cash dividend payable December 31, 2026, to holders of record December 15, 2026.
How this balance works
Rhea-AI gives every point it takes from this document a weight. Minor counts 1, Moderate 3 and Major 9, so one Major point outweighs several Minor ones. The bar adds up the weights on each side, and when neither side holds more than 65% of the total the balance reads Mixed.
It reads the document as published, with the same rules for every company, and it does not look at what the market expected or at how the stock traded, so a point can be objectively good on a day the stock falls.
Rhea-AI Sentiment measures something else, the tone of the wording.
Positive
- Major pointPermian minerals acquisition: $16.0 million purchase price. 11% of market cap
- Moderate pointRevenue: $22.573 million, versus $21.288 million a year earlier.
Negative
- Moderate pointNet loss: $2.992 million, versus $824,000 net income.
- Moderate pointOperating cash flow: $3.288 million, versus $7.805 million.
Filing Explained
After the October twentieth reset, Evolution reported nine point two million dollars of facility capacity, down from twelve point two million at September thirtieth.
As of
The report also says the company may issue up to
Key Figures
Key Terms
full-cost method financial
borrowing base financial
mark-to-market valuation financial
three-way collars technical
non-operated working interests technical
FAQ
AI-generated questions and answers. How Rhea-AI works. Not financial advice.
What were EPM’s revenue and earnings for the first quarter of fiscal 2027?
What did EPM acquire in the Permian Basin?
AI-generated analysis. How Rhea-AI works. Not financial advice.
Table of Contents
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 November 6, 2026,
Table of Contents
EVOLUTION PETROLEUM CORPORATION
TABLE OF CONTENTS
Forward-Looking Statements | 2 | |
PART I. | FINANCIAL INFORMATION | 4 |
Item 1. | Condensed Consolidated Financial Statements (Unaudited) | 4 |
Condensed Consolidated Balance Sheets (Unaudited) as of September 30, 2026 and June 30, 2026 | 4 | |
Condensed Consolidated Statements of Operations (Unaudited) for the three months ended September 30, 2026 and 2025 | 5 | |
Condensed Consolidated Statements of Cash Flows (Unaudited) for the three months ended September 30, 2026 and 2025 | 6 | |
Condensed Consolidated Statements of Changes in Stockholders’ Equity (Unaudited) for the three months ended September 30, 2026 and 2025 | 7 | |
Notes to Unaudited Condensed Consolidated Financial Statements | 8 | |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 25 |
Item 3. | Quantitative and Qualitative Disclosures about Market Risks | 34 |
Item 4. | Controls and Procedures | 34 |
PART II. OTHER INFORMATION | 35 | |
Item 1. | Legal Proceedings | 35 |
Item 1A. | Risk Factors | 35 |
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 35 |
Item 3. | Defaults Upon Senior Securities | 36 |
Item 4. | Mine Safety Disclosures | 36 |
Item 5. | Other Information | 36 |
Item 6. | Exhibits | 37 |
Signatures | 38 | |
We use the terms, “EPM,” “Company,” “we,” “us,” and “our” to refer to Evolution Petroleum Corporation, and unless the context otherwise requires, its wholly-owned subsidiaries.
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FORWARD-LOOKING STATEMENTS
This Form 10-Q and the information referenced herein contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, except for statements of historical fact, are forward-looking statements. The words “plan,” “expect,” “project,” “estimate,” “may,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words or phrases. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors, which may include, but are not limited to, the following:
| ● | our 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 natural gas liquids (“NGLs”) production and commodity mix; |
| ● | oil, natural gas and NGL prices; |
| ● | 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; |
| ● | 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 and local rules and regulations; |
| ● | compliance with current or proposed environmental requirements, including the costs thereof; |
| ● | 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; |
| ● | limitations on our ability to obtain funding based on environmental, social, and corporate governance performance; |
| ● | the impact of greenhouse gas (“GHG”) emissions limitations and renewable energy incentives; |
| ● | staffing levels; |
| ● | payments related to our commitments, obligations and contingencies, and the ability to satisfy the same; and |
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| ● | 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 use our shelf registration statement; |
| ● | 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, 2026, as well as the other disclosures contained herein, therein, and as also may be described from time to time in future reports we file with the Securities and Exchange Commission (“SEC”). Readers should also consider such information in conjunction with our condensed consolidated financial statements and related notes and Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations in this report. There also may be other factors that we cannot anticipate or that are not described in this report, generally because we do not currently perceive them to be material. Such factors could cause results to differ materially from our expectations.
Forward-looking statements speak only as of the date they are made, and we do not undertake to update these statements other than as required by law. Readers are advised, however, to review any further disclosures we make on related subjects in our filings with the SEC.
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Part I. FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited)
EVOLUTION PETROLEUM CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)
(In thousands, except share and per share amounts)
| September 30, 2026 | | June 30, 2026 | |||
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 | | — | ||||
Other property and equipment, net | | — | ||||
Total property and equipment, net | | | ||||
Other noncurrent assets | ||||||
Derivative contract assets | | | ||||
Other assets, net | | | ||||
Total assets | $ | | $ | | ||
Liabilities and Stockholders' Equity |
| |||||
Current liabilities |
| |||||
Accounts payable | $ | | $ | | ||
Accrued liabilities and other | | | ||||
Derivative contract liabilities | | | ||||
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, 2026, respectively | | | ||||
Additional paid-in capital | | | ||||
Retained earnings (Accumulated deficit) | ( | | ||||
Total stockholders' equity | | | ||||
Total liabilities and stockholders' equity | $ | | $ | | ||
See accompanying notes to unaudited condensed consolidated financial statements.
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EVOLUTION PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)
(In thousands, except per share amounts)
| Three Months Ended | |||||
September 30, | ||||||
| 2026 | | 2025 | |||
Revenues | ||||||
Oil, natural gas, and natural gas liquids revenues: | ||||||
Crude oil | $ | | $ | | ||
Natural gas | | | ||||
Natural gas liquids | | | ||||
Total oil, natural gas, and natural gas liquids revenues | | | ||||
Other | | — | ||||
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.
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EVOLUTION PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
(In thousands)
Three Months Ended September 30, | ||||||
| | 2026 | | 2025 | ||
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 | | | ||||
Tenant improvement allowance | | — | ||||
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 | ( | ( | ||||
Proceeds from the sale of oil and natural gas properties | | — | ||||
Capital expenditures for oil and natural gas properties | ( | ( | ||||
Capital expenditures for other property and equipment | ( | — | ||||
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 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 | $ | ( | $ | ( | ||
See accompanying notes to unaudited condensed consolidated financial statements.
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EVOLUTION PETROLEUM CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (Unaudited)
(In thousands)
| Retained |
| |||||||||||||||
Additional | Earnings | Total | |||||||||||||||
| Common Stock | Paid-in | (Accumulated | Treasury | Stockholders' | ||||||||||||
| Shares | | Par Value | | Capital | | Deficit) | | Stock | | Equity | ||||||
For the Three Months Ended September 30, 2026 | |||||||||||||||||
Balances at June 30, 2026 | | $ | | $ | | $ | | $ | — | $ | | ||||||
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 September 30, 2026 | | $ | | $ | | $ | ( | $ | — | $ | | ||||||
For the Three Months Ended September 30, 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 September 30, 2025 | | $ | | $ | | $ | | $ | — | $ | | ||||||
See accompanying notes to unaudited condensed consolidated financial statements.
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EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Financial Statement Presentation
Nature of Operations. Evolution Petroleum Corporation (“Evolution,” and together with its consolidated subsidiaries, the “Company”) is an independent energy company focused on acquiring and developing long-lived oil and natural gas properties in the United States. The Company’s diversified portfolio consists primarily of non-operated working interest and mineral and royalty interests across several leading producing basins. The Company’s non-operated model allows it to invest alongside experienced operators, participate in a broad range of development opportunities and maintain flexibility in the timing and allocation of capital. The Company’s mineral and royalty interests provide additional exposure to production and future development, generally without associated lifting expenses or drilling and completions costs.
The geographic, commodity, operator and ownership diversity of the Company’s asset base reduces its reliance on any single property, basin or development program. It also provides multiple avenues for allocating capital, including acquiring producing working and mineral interests, participating in and benefiting from attractive operator-led projects and pursuing development opportunities within our existing assets.
The Company seeks to maximize total shareholder value through disciplined acquisitions, selective participation in attractive development projects, a conservative balance sheet and the return of capital to shareholders.
The Company’s oil and natural gas properties consist of non-operated working interests and mineral and royalty interests in the following areas: the Midland Basin in the Permian Basin in Texas; the Haynesville/Bossier Shale in Louisiana; 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; and the TexMex interests located in New Mexico and Texas.
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 2026 Annual Report on Form 10-K for the fiscal year ended June 30, 2026, as filed with the SEC on September 16, 2026. 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.
Risks 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 interest.
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
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EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 the full-cost pool and 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. As of September 30, 2026, approximately $
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 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 adopted ASU 2025-05 prospectively, effective July 1, 2026. The adoption did not have a material impact 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
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EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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.
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 Midland Basin in the Permian Basin in Texas; the Haynesville/Bossier Shale in Louisiana; 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 New Mexico and Texas.
| Three Months Ended | |||||
September 30, | ||||||
| 2026 | | 2025 | |||
Revenues | ||||||
Oil, natural gas, and natural gas liquids revenues: | ||||||
Crude oil | $ | | $ | | ||
Natural gas | | | ||||
Natural gas liquids | | | ||||
Total oil, natural gas, and natural gas liquids revenues | | | ||||
Other (1) | | — | ||||
Total revenues | $ | | $ | | ||
| (1) | Other revenues represent lease bonus revenue received. |
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.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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
Note 3. Acquisitions and Divestitures
Purchase of Permian Minerals
On August 20, 2026, the Company completed the acquisition of mineral and royalty interests in the core Midland Basin of the Permian Basin from a non-affiliated private seller for a total purchase price of $
Purchase of Louisiana Minerals
From December 2025 through June 2026, the Company acquired mineral and royalty interests in multiple parishes across Louisiana from various private sellers for an aggregate cash consideration totaling $
SCOOP/STACK Minerals Transactions
On August 4, 2025, the Company completed the acquisition of certain mineral and royalty interests in the SCOOP and STACK plays in Oklahoma from a non-affiliated private seller (the “SCOOP/STACK Minerals Acquisition”) in a cash transaction valued at approximately $
On June 30, 2026, the Company completed the divestiture of a portion of its non-core, non-producing net mineral acres in the SCOOP/STACK with a private buyer. The total sale price for the acreage was approximately $
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 4. Property and Equipment
Property and equipment consisted of the following for the periods presented (in thousands):
| September 30, 2026 | | June 30, 2026 | |||
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 | $ | | $ | | ||
Other property and equipment |
|
| ||||
Furniture, fixtures, leasehold improvements and office equipment, at cost | $ | | $ | | ||
Less: Accumulated depreciation | ( | ( | ||||
Other property and equipment, net | $ | | $ | — | ||
As of September 30, 2026, $
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.
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 September 30, 2026, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended September 30, 2026 of the West Texas Intermediate (“WTI”) crude oil spot price of $
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
At September 30, 2025, the ceiling test value of the Company’s reserves was calculated based on the first-day-of the month average for the 12-months ended September 30, 2025 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 $
million in accordance with the semi-annual redetermination as provided in the credit agreement. The borrowing base will be redetermined semiannually, with the lenders and the Company each having the right 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 complementary 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 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 August 20, 2026, the Company entered into a letter agreement with MidFirst Bank pursuant to which the borrowing base on its Senior Secured Credit Facility was temporarily increased from $
As of September 30, 2026, the Company was in compliance with all covenants under the Senior Secured Credit Facility.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 three months ended September 30, 2026, 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 in a timely manner.
There were
For the three months ended September 30, 2026, the Company recognized an income tax benefit of $
On July 4, 2025, President Trump signed into law the One Big Beautiful Bill Act (“OBBBA”). The OBBBA makes permanent key elements of the Tax Cuts and Jobs Act of 2017, including 100% bonus depreciation and the business interest expense limitation, as well as other provisions. The Company’s consolidated financial statements for the three months ended September 30, 2025, include the OBBBA’s effect for the period beginning July 1, 2025, through September 30, 2025. Some of the provisions in the OBBBA were effective for periods before July 1, 2025, and thus when the Company filed its June 30, 2025 tax return on April 15, 2026, the Company was able to reduce its fiscal year tax liability and defer current cash taxes owed, due to the 100% bonus depreciation allowed in the OBBBA. The tax effects related to fiscal year 2025 were recorded in the financial statements as a return to provision adjustment during the quarter ended March 31, 2026, once the effects were identified and quantifiable.
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, and Texas, due to percentage depletion in excess of basis, and other permanent differences, including federal tax credits expected from production on marginal natural gas wells. 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 as of each reporting date with the changes in the fair value included in the unaudited condensed consolidated statements of operations for the period in which the change
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
occurs. The Company’s hedge strategies and objectives may change significantly as its operational profile changes or as required under the Senior Secured Credit Facility. The Company does not enter into derivative contracts for speculative trading purposes.
It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of September 30, 2026, 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. The significant increase in forward commodity prices as of September 30, 2026, as compared to June 30, 2026, resulted in an unrealized loss on the mark-to-market of our hedges. Accordingly, at each reporting date, the Company records the net change in the mark-to-market valuation of the derivative contracts and all payments and receipts on settled derivative contracts in “Net gain (loss) on derivative contracts” on the unaudited condensed consolidated statements of operations.
All derivative contracts are recorded at fair market value in accordance with ASC 815, Derivatives and Hedging (“ASC 815”) and ASC 820, Fair Value Measurement (“ASC 820”) and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The “Derivative contract assets” and “Derivative contract liabilities” represent the difference between the market commodity prices and the hedged prices for the remaining volumes of production hedges as of September 30, 2026 and June 30, 2026 (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 September 30, 2026 and June 30, 2026 (in thousands):
Derivatives not designated | ||||||||||||||||
as hedging contracts | Balance sheet | Derivative Contract Assets | Balance sheet | Derivative Contract Liabilities | ||||||||||||
under ASC 815 | | location | | September 30, 2026 | | June 30, 2026 | | location | | September 30, 2026 | | June 30, 2026 | ||||
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 | $ | | $ | | $ | | $ | | ||||||||
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s unaudited condensed consolidated statements of operations for the three months ended September 30, 2026 and 2025 (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 | ||||||
as hedging contracts | recognized in income on | September 30, | ||||||
under ASC 815 | | derivative contracts | 2026 | | 2025 | |||
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 September 30, 2026, 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 2027 - December 2027 | Crude Oil | Fixed-Price Swap | | $ | | |||||||||||||
October 2026 - December 2026 | Crude Oil | Two-Way Collar | | $ | | $ | | |||||||||||
January 2027 - December 2027 | Crude Oil | Two-Way Collar | | | | |||||||||||||
October 2026 - December 2026 | Crude Oil | Three-Way Collar | | $ | | | | |||||||||||
October 2026 - December 2026 | Natural Gas | Fixed-Price Swap | | | ||||||||||||||
January 2027 - December 2027 | Natural Gas | Fixed-Price Swap | | | ||||||||||||||
January 2027 - March 2028 | Natural Gas | Fixed-Price Swap | | | ||||||||||||||
October 2026 - December 2026 | Natural Gas | Two-Way Collar | | | | |||||||||||||
January 2027 - September 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 | | September 30, 2026 | | June 30, 2026 | | September 30, 2026 | | June 30, 2026 | ||||
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.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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.
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.
September 30, 2026 | ||||||||||||
| Level 1 | | Level 2 | | Level 3 | | Total | |||||
Assets | ||||||||||||
Derivative contract assets | $ | — | $ | | $ | — | $ | | ||||
Liabilities | ||||||||||||
Derivative contract liabilities | $ | — | $ | | $ | — | $ | | ||||
June 30, 2026 | ||||||||||||
| 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.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The Company’s derivative contracts are with large utilities with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not expect such nonperformance.
Other Fair Value Measurements. The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company’s Senior Secured Credit Facility approximates carrying value because the interest rates approximate current market rates.
The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. These provisions apply to the Company’s initial measurement and any subsequent revision of asset retirement obligations (“ARO”) for which fair value is calculated using discounted future cash flows derived from historical costs and management’s expectations of future cost environments. Significant Level 3 inputs used in the calculation of ARO include the costs of plugging and abandoning wells, surface restoration, and reserve lives. Subsequent to initial recognition, revisions to estimated asset retirement obligations are made when changes occur for input values. See Note 9, “Asset Retirement Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s ARO.
Note 9. Asset Retirement Obligations
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 September 30, 2026 (in thousands):
| | September 30, 2026 | |
Asset retirement obligations — beginning of period | $ | | |
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.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 11. Stockholders’ Equity
Common Stock
At September 30, 2026, the Company had
The Company began paying quarterly cash dividends on common stock in December 2013. As of September 30, 2026, the Company has cumulatively paid over $
The following table reflects the dividends paid per share within the respective three-month periods:
Fiscal Year | ||||||
| 2027 | | 2026 | |||
First fiscal quarter | $ | | $ | | ||
On August 20, 2026, the Company completed a public offering of approximately
On October 21, 2024, the Company entered into an At-the-Market (“ATM”) equity 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 $
During the three months ended September 30, 2026 and 2025, the Company acquired treasury stock upon the ordinary course of scheduled vestings of employee stock-based awards to fund payroll tax withholding obligations. These treasury shares were subsequently cancelled. Such shares were valued at fair market value on the date of vesting.
The following table summarizes all treasury stock purchases during the periods presented (in thousands, except per share amounts):
Three Months Ended | ||||||
September 30, | ||||||
| 2026 | 2025 | ||||
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, 2026, 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, 2027, the Company expects all common stock dividends for such period to be treated as qualified dividend income to the recipients. Such projections are based on the Company’s reasonable expectations as of September 30, 2026 and are subject to change based on the Company’s final tax calculations at the end of the fiscal year.
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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 each of the three months ended September 30, 2026 and 2025, the Company recognized $
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 three months ended September 30, 2026, the Company granted a total of
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
During the three months ended September 30, 2025, the Company granted a total of
For performance-based awards granted during the three months ended September 30, 2026 and 2025, the assumptions used in the Monte Carlo simulation valuations were as follows:
Three Months Ended | ||||||
September 30, | ||||||
| 2026 | | 2025 | |||
Weighted average fair value of performance-based awards granted | $ | | $ | | ||
Risk-free interest rate | ||||||
Expected term in years | ||||||
Expected volatility | ||||||
Dividend yield | ||||||
Unvested restricted stock awards as of September 30, 2026 consisted of the following:
Weighted | |||||
Number of | Average | ||||
Restricted | Grant-Date | ||||
Award Type | | Shares | | Fair Value | |
Time-vested awards | | $ | | ||
Performance-based awards | | | |||
Unvested at September 30, 2026 | | $ | | ||
The following table sets forth the restricted stock award transactions for the three months ended September 30, 2026:
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, 2026 | | $ | | $ | | |||||
Time-vested shares granted | | | ||||||||
Performance-based shares granted | | | ||||||||
Vested | ( | | ||||||||
Unvested at September 30, 2026 | | $ | | $ | | |||||
The following table sets forth contingent restricted stock unit transactions for the three months ended September 30, 2026:
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, 2026 | | $ | | $ | | |||||
Performance-based awards granted | | | ||||||||
Unvested at September 30, 2026 | | $ | | $ | | |||||
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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 | |||||
September 30, | ||||||
| 2026 | | 2025 | |||
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
The table below summarized the Company’s leases for the three months ended September 30, 2026 and 2025 (in thousands, except years and discount rate):
Three Months Ended September 30, | ||||||||
| | 2026 | | 2025 | ||||
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 | | % | | % | ||||
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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the Company’s ROU assets and lease liabilities (in thousands):
September 30, 2026 | June 30, 2026 | ||||||
Balance Sheets: | |||||||
$ | | $ | | ||||
| | ||||||
Operating lease liability - long-term | | | |||||
As of September 30, 2026, the future minimum lease payments associated with the Company’s non-cancellable operating lease for office space are as follows (in thousands):
Fiscal Year | | September 30, 2026 | |
Remaining in 2027 | $ | | |
2028 | | ||
2029 | | ||
2030 | | ||
2031 | | ||
Thereafter | — | ||
Total operating lease payments | | ||
Less: discount to present value | | ||
| |||
Less: current operating lease liabilities | | ||
Noncurrent operating lease liabilities | $ | | |
Note 14. Additional Financial Statement Information
Certain amounts on the unaudited condensed consolidated balance sheets are comprised of the following (in thousands):
| | September 30, 2026 | | June 30, 2026 | ||
Prepaid expenses and other current assets: | ||||||
State and federal taxes receivable | $ | | $ | | ||
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 | | | ||||
Right of use asset under operating lease | | | ||||
Total other assets, net | $ | | $ | | ||
Accrued liabilities and other: | ||||||
Accrued payables | $ | | $ | | ||
Accrued incentive and other compensation | | | ||||
Accrued royalties payable(1) | | | ||||
Accrued taxes other than federal and state income tax | | | ||||
Accrued settlements on derivative contracts | | | ||||
Operating lease liability | | | ||||
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. |
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EVOLUTION PETROLEUM CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 15. Subsequent Events
Dividend Declaration
On , the Company declared a quarterly cash dividend of $
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Commonly Used Terms
“Current quarter” refers to the three months ended September 30, 2026, our first quarter of fiscal year 2027.
“Year-ago quarter” refers to the three months ended September 30, 2025, our first quarter of fiscal year 2026.
Executive Overview
General
Evolution Petroleum Corporation is an independent energy company focused on acquiring and developing long-lived oil and natural gas properties in the United States. Our diversified portfolio consists primarily of non-operated working interests and mineral and royalty interests across several leading producing basins.
Our non-operated model allows us to invest alongside experienced operators, participate in a broad range of development opportunities and maintain flexibility in the timing and allocation of capital. Our mineral and royalty interests provide additional exposure to production and future development, generally without associated lifting expenses or drilling and completions costs.
The geographic, commodity, operator and ownership diversity of our asset base reduces our reliance on any single property, basin or development program. It also provides multiple avenues for allocating capital, including acquiring producing working and mineral interests, participating in and benefiting from attractive operator-led projects and pursuing development opportunities within our existing assets.
We seek to maximize total shareholder value through disciplined acquisitions, selective participation in attractive development projects, a conservative balance sheet and the return of capital to shareholders.
Our oil and natural gas properties consist primarily of non-operated working and mineral interests in the following areas:
| ● | Our mineral and royalty interests in the Midland Basin of the Permian Basin, consist of a mix of proved producing wells, drilled but not yet producing wells, and undeveloped acreage with an approximate average 0.3% net royalty interest. Our mineral and royalty interest span across 3,420 net royalty acres in Glasscock, Martin, Midland, Reagan and Upton Counties, Texas. |
| ● | Our mineral and royalty interest in the Haynesville/Bossier Shale, consists of a mix of natural gas producing wells, drilled but not yet producing wells, and proved undeveloped acreage with an approximate average 0.2% net royalty interest. Our mineral and royalty interest span across an approximate 3,700 gross (498 net) acres located in Bossier, Caddo, DeSoto, Red River and Sabine parishes in Louisiana. |
| ● | Our non-operated working 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 2.6% average net working interest with an associated 2.0% average net revenue interest located on approximately 101,100 gross (4,000 net) acres (all held by production) and a separate approximate 0.6% average net royalty interests located on approximately 8,600 gross (1,800 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., Flywheel Energy, Validus Energy, and Camino Natural Resources LLC with approximately 49% of wells operated by other operators. |
| ● | Our non-operated working 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”). |
| ● | Our non-operated working 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 |
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| revenue interest located on approximately 5,300 gross (950 net) acres all held by production. The properties are operated by Jonah Energy. |
| ● | Our non-operated working interests in the Williston Basin, an oil and natural gas producing property, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 133,800 gross (40,100 net) acres (approximately 99% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy Management. |
| ● | 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 Eagleridge Operating, LLC, with approximately 19% of wells operated by five other operators. |
| ● | Our non-operated working 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. |
| ● | Our non-operated working 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 Delhi Field is comprised of 13,600 gross unitized acres, of which we hold approximately 3,200 net acres, and is located in northeast Louisiana in Franklin, Madison, and Richland Parishes. |
| ● | Our non-operated working interest 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. |
Recent Developments
Dividend Declaration
On November 9, 2026, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable December 31, 2026.
Purchase of Louisiana Minerals
During the three months ended September 30, 2026, the Company acquired additional Louisiana mineral and royalty interests for approximately $0.3 million, including capitalized direct transaction costs. These acquired mineral and royalty interests are in multiple parishes across Louisiana from private sellers. The mineral acreage in Louisiana primarily consists of proved undeveloped acreage targeting the Bossier/Haynesville Shales and is currently being actively developed by operators in the area. These acquisitions were each considered asset acquisitions and funded with cash on hand and sales from the Company’s ATM Sales Agreements.
Senior Secured Credit Facility
On August 20, 2026, we entered into a letter agreement with MidFirst Bank pursuant to which the borrowing base on our Senior Secured Credit Facility was temporarily increased from $65.0 million to $73.0 million from August 20, 2026
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until October 20, 2026 to provide additional capacity for the Permian Mineral Acquisition, defined below. On October 20. 2026, under the terms of our Senior Secured Credit Facility, the borrowing base was redetermined at $70.0 million based on the semi-annual review of all of our properties.
Purchase of Permian Minerals
On August 20, 2026, we completed the acquisition of mineral and royalty interests in the core Midland Basin of the Permian Basin from a non-affiliated private seller for a total purchase price of $16.0 million (the “Permian Minerals Acquisition”), subject to customary post-closing adjustments. The Permian Minerals Acquisition has an effective date of August 1, 2026. We funded the purchase price for the Permian Minerals Acquisition with a combination of net proceeds from our concurrent public equity offering and $3.2 million in borrowings under our Senior Secured Credit Facility. The acquired assets include approximately 3,420 net royalty acres across Glasscock, Martin, Midland, Reagan, and Upton Counties, Texas.
Common Stock Offering
On August 20, 2026, we completed a public offering of approximately 4.3 million shares of our common stock, at an offering price of $3.25 per share (the “Offering”). We received net proceeds of approximately $12.5 million from the Offering, after deducting underwriting discounts and commissions and offering costs. Net proceeds from the Offering, together with borrowings under our Senior Secured Credit Facility and cash on hand, were used to fund the Permian Minerals Acquisition.
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. In March 2026, WTI oil prices reached their highest levels since 2022 due to crude oil disruptions at key oil shipping routes in the Middle East, including the Strait of Hormuz. During the three months ended September 30, 2026, oil and NGL prices remained elevated compared to the prior-year period, supported by global demand for U.S. production and continued geopolitical tensions in the Middle East, while natural gas prices declined compared to the prior-year period, primarily due to continued growth in U.S. natural gas production, mild weather and uncertainty regarding winter heating demand. 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. During the fiscal year June 30, 2026, crude oil spot prices for WTI dropped below $56 per barrel in December 2025 then rose to more than $100 per barrel in March 2026. During the three months ended September 30, 2026, crude oil spot prices averaged approximately $87.22 per barrel and NYMEX Henry Hub natural gas spot prices averaged approximately $2.87 per MMBtu, compared to approximately $65.74 per barrel and $3.03 per MMBtu, respectively, during the three months ended September 30, 2025. Lower oil and natural gas prices not only decrease our revenues, partially offset by applicable hedges, 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. Increases in crude oil and natural gas prices are partially offset to the extent that these prices exceed the Company’s applicable derivative contract swap and collar prices.
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 as well as commodity pricing. Any related significant declines in crude oil, natural gas, and NGL prices could lead to proved property impairments in the future. Per the terms of our Senior Secured Credit Facility, we are required to hedge a portion of our anticipated crude oil and natural gas production from proved developed producing reserves based on the utilization of the borrowing base then in effect, currently up to 75% of
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anticipated proved developed producing production on a per BOE basis, for a rolling twelve-months period of time. Any significant increases in commodity prices could lead to further losses on our derivative contacts that partially offset the realized price increases. As of September 30, 2026, the significant increase in current and forward commodity prices specifically for crude oil as compared to June 30, 2026, resulted in $1.3 million and $4.1 million of realized and unrealized losses, respectively. Impairments of proved properties and gains and losses on derivative contracts are difficult to predict, especially in a volatile price environment. Certain of our costs, including costs incurred by our third-party operators that are passed through to us, are affected by commodity prices, general inflation and tariffs, including tariffs on steel and other materials.
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. Inflation in the United States has remained persistently above the Federal Reserve’s 2% target, and in September 2026 the Federal Reserve responded by raising interest rates by 25 basis points, its first increase since 2023. The timing, size, and communication of future Federal Reserve actions are difficult to predict and depend on economic factors outside of our control and it is uncertain how these actions will impact inflation and the economy.
Currently, our oil and natural gas properties are operated by third-party operators and involve other third-party working interest owners. As a result, we have limited ability to influence the operation or future development of such properties. Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review the management of capital expenditures.
Liquidity and Capital Resources
As of September 30, 2026, we had $3.1 million in cash and cash equivalents and $60.0 million outstanding borrowings on our Senior Secured Credit Facility compared to $6.1 million in cash and cash equivalents and $56.5 million outstanding borrowings on our Senior Secured Credit Facility at June 30, 2026. Our primary sources of liquidity and capital resources during the three months ended September 30, 2026 were net proceeds from the Offering, cash provided by operations, and net borrowings under our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the three months ended September 30, 2026 were cash used to fund our Permian Minerals Acquisition, cash dividend payments to our common stockholders, and development capital expenditures. As of September 30, 2026, working capital was a deficit of $3.5 million primarily due to our current derivative contracts, which vary quarter-to-quarter based on forecasted commodity prices at the end of each quarter. As of June 30, 2026, working capital was a deficit of $1.8 million.
The syndicated Senior Secured Credit Facility has a maximum capacity of $200.0 million subject to a borrowing base determined by the lenders based on a percentage of the value of our oil and natural gas properties. The Senior Secured Credit Facility had an interim borrowing base of $73.0 million at September 30, 2026 which was redetermined at $70.0 million as of October 20, 2026 in accordance with the semi-annual redetermination as provided in the credit agreement. As of September 30, 2026, we had $60.0 million of indebtedness, $0.8 million of letters of credit outstanding, and available capacity of $12.2 million. As of October 20, 2026, our available capacity is $9.2 million. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on June 30, 2028.
For the three months ended September 30, 2026 and 2025, the weighted average interest rate on our borrowings was 6.48% and 7.12%, 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
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negative covenants, including a hedging covenant discussed below, and events of default. As of September 30, 2026, 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 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.
On October 21, 2024, we entered into an ATM equity 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. On February 11, 2026, we executed a new ATM equity Sales Agreement, substantially consistent with the original October 2024 agreement restoring the $30.0 million common stock sales capacity. We did not sell any shares of our common stock under the ATM Sales Agreements during the three months ended September 30, 2026.
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 Agreements.
Consistent with our business strategy, we are constantly pursuing new growth opportunities and other transactions to maximize shareholder value and will do so using a targeted mix of capital sourcing. We will continue to pursue acquisitions of oil and natural gas properties, including long-life producing properties with substantial upside potential as well as acquisitions of minerals and royalty interests. 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 $9.2 million as of October 20, 2026. We also have an effective shelf registration statement with the SEC under which we may issue up to $475.9 million of debt or equity securities. We believe that our cash on hand, cash flows from operations and available borrowings will be sufficient to fund our operations, capital expenditures and dividends for at least the next 12 months and in the longer term.
Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 52 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 maintain or 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 relevant. On November 9, 2026, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on December 15, 2026 and payable on December 31, 2026.
Capital Expenditures
During the three months ended September 30, 2026, we incurred $0.7 million on development capital expenditures. A majority of our spending occurred at SCOOP/STACK where two gross wells were brought online during the three months ended September 30, 2026 and eight gross wells are currently in progress. Remaining capital spending related to capital workover projects across our portfolio of assets. 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 2027, we expect budgeted capital expenditures to be in the range of $4.0 million to $6.0 million, which excludes the recent purchase of Permian Minerals, any other potential acquisitions, and drilling at Chaveroo Field.
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Our expected capital expenditures for fiscal year 2027 include bringing approximately eight gross wells online at SCOOP/STACK in addition to the two gross wells brought online during the period. Additionally, as our third-party operators continue to be active around our acreage, we would expect additional wells to be drilled and/or completed.
Full Cost Pool Ceiling Test
Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion, depreciation, and amortization and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test as of September 30, 2026 were $76.93 per barrel of oil, $3.60 per MMBtu of natural gas and $28.93 per barrel of NGLs. As of September 30, 2026, our capitalized costs of oil and natural gas properties, subject to amortization, were below the full cost valuation ceiling. If commodity price levels were to substantially decline from the 12-month average first day of the month pricing levels as of September 30, 2026 and remain down for a prolonged period of time, our valuation ceiling over our capitalized costs may be reduced and adversely impact our ceiling test results in future quarters and the effect could be material to our net earnings. Using first day of the month prices for October and November 2026, which are more reflective of recent price trends, to calculate trailing 12-month average price of $86.46 per barrel of crude oil and $3.36 per MMBtu of natural gas, and keeping all other factors constant, the ceiling test calculation as of the second quarter of fiscal year 2027 would not have generated a ceiling test impairment. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required at some point in the future as commodity prices are volatile and unpredictable. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties to our full cost pool, capital spending and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.
Overview of Cash Flow Activities
Three Months Ended September 30, | |||||||||
| 2026 | | 2025 | | Change | ||||
Cash flows provided by operating activities | $ | 3,288 | $ | 7,805 | $ | (4,517) | |||
Cash flows used in investing activities | (17,297) | (20,686) | 3,389 | ||||||
Cash flows provided by financing activities | 11,003 | 11,088 | (85) | ||||||
Net increase (decrease) in cash and cash equivalents | $ | (3,006) | $ | (1,793) | $ | (1,213) | |||
Cash provided by operating activities for the three months ended September 30, 2026 decreased $4.5 million compared to the three months ended September 30, 2025 primarily due to timing of working capital and realized losses on derivative contracts. We had net derivative realized losses of $1.3 million compared to realized gains of $0.9 million in the prior period. Refer to “Results of Operations” below for further information.
Cash used in investing activities for the three months ended September 30, 2026 decreased $3.4 million compared to the three months ended September 30, 2025. In the prior period we spent $16.9 million on the SCOOP/STACK Minerals Acquisition and $3.8 million on development capital expenditures. During the current quarter, we spent approximately $16.0 million on the Permian Minerals Acquisition and $0.3 million on mineral and royalty interests targeting the Haynesville/Bossier Shale.
Cash flows provided by financing activities for the three months ended September 30, 2026 decreased $0.1 million compared to the three months ended September 30, 2025. For the three months ended September 30, 2026, we received approximately $12.5 million in net proceeds from our Offering, after deducting $0.5 million of offering costs, and net borrowings of $3.5 million under our Senior Secured Credit Facility, which funded our Permian Minerals Acquisition. During the quarter, we also paid $4.9 million in cash dividends to our common stockholders. For the three months ended September 30, 2025, we received $15.5 million in net borrowings under our Senior Secured Credit Facility to finance our Minerals Acquisition, and paid $4.2 million in cash dividends to our common stockholders.
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Results of Operations
Three Months Ended September 30, 2026 and 2025
We reported net losses of $3.0 million and net income of $0.8 million for the three months ended September 30, 2026 and 2025, respectively. The following table summarizes the comparison of financial information for the periods presented:
| Three Months Ended | |||||||||||
September 30, | ||||||||||||
(in thousands, except per unit and per BOE amounts) | | 2026 | | 2025 | | Variance | | Variance % | ||||
Net income (loss) | $ | (2,992) | $ | 824 | $ | (3,816) | N.M. | |||||
Revenues: | ||||||||||||
Crude oil | 13,895 | 12,872 | 1,023 | 7.9 | % | |||||||
Natural gas | 5,476 | 5,900 | (424) | (7.2) | % | |||||||
Natural gas liquids | 3,183 | 2,516 | 667 | 26.5 | % | |||||||
Total oil, natural gas, and natural gas liquids revenues | 22,554 | 21,288 | 1,266 | 5.9 | % | |||||||
Other | 19 | — | 19 | N.M. | ||||||||
Total revenues | 22,573 | 21,288 | 1,285 | 6.0 | % | |||||||
Operating costs: | ||||||||||||
Lease operating costs: | ||||||||||||
Ad valorem and production taxes | 1,376 | 1,420 | (44) | (3.1) | % | |||||||
Gathering, transportation, and other costs | 2,742 | 2,892 | (150) | (5.2) | % | |||||||
Other lease operating costs | 8,242 | 8,775 | (533) | (6.1) | % | |||||||
Depletion, depreciation, and accretion: | ||||||||||||
Depletion of full cost proved oil and natural gas properties | 5,339 | 5,560 | (221) | (4.0) | % | |||||||
Depreciation of other property and equipment | 1 | — | 1 | N.M. | ||||||||
Accretion of asset retirement obligations | 404 | 401 | 3 | 0.7 | % | |||||||
General and administrative expenses: | ||||||||||||
General and administrative | 2,070 | 1,788 | 282 | 15.8 | % | |||||||
Stock-based compensation | 538 | 537 | 1 | 0.2 | % | |||||||
Other income (expense): | ||||||||||||
Net gain (loss) on derivative contracts | (5,365) | 2,181 | (7,546) | N.M. | ||||||||
Interest and other income | 12 | 10 | 2 | 20.0 | % | |||||||
Interest expense | (1,031) | (917) | (114) | 12.4 | % | |||||||
Income tax (expense) benefit | 1,531 | (365) | 1,896 | N.M. | ||||||||
Production: | ||||||||||||
Crude oil (MBBL) | 170 | 207 | (37) | (17.9) | % | |||||||
Natural gas (MMCF) | 2,182 | 2,150 | 32 | 1.5 | % | |||||||
Natural gas liquids (MBBL) | 108 | 108 | — | — | % | |||||||
Equivalent (MBOE)(1) | 642 | 673 | (31) | (4.6) | % | |||||||
Average daily production (BOEPD)(1) | 6,978 | 7,315 | (337) | (4.6) | % | |||||||
Average price per unit(2): | ||||||||||||
Crude oil (BBL) | $ | 81.74 | $ | 62.18 | $ | 19.56 | 31.5 | % | ||||
Natural gas (MCF) | 2.51 | 2.74 | (0.23) | (8.4) | % | |||||||
Natural Gas Liquids (BBL) | 29.47 | 23.30 | 6.17 | 26.5 | % | |||||||
Equivalent (BOE)(1) | 35.13 | 31.63 | 3.50 | 11.1 | % | |||||||
Average cost per unit: | ||||||||||||
Operating costs: | ||||||||||||
Lease operating costs: | ||||||||||||
Ad valorem and production taxes | $ | 2.14 | $ | 2.11 | $ | 0.03 | 1.4 | % | ||||
Gathering, transportation, and other costs | 4.27 | 4.30 | (0.03) | (0.7) | % | |||||||
Other lease operating costs | 12.84 | 13.04 | (0.20) | (1.5) | % | |||||||
Depletion of full cost proved oil and natural gas properties | 8.32 | 8.26 | 0.06 | 0.7 | % | |||||||
General and administrative expenses: | ||||||||||||
General and administrative | 3.22 | 2.66 | 0.56 | 21.1 | % | |||||||
Stock-based compensation | 0.84 | 0.80 | 0.04 | 5.0 | % | |||||||
“N.M.” means “Not Meaningful.”
| (1) | Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil. |
| (2) | Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting. |
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Revenues
Crude oil, natural gas and NGL revenues were $22.6 million and $21.3 million for the three months ended September 30, 2026 and 2025, respectively, with the increase in revenues due to increases in our average realized price per BOE partially offset by decreases in production volumes. Our average realized commodity price (excluding the impact of derivative contracts) for the three months ended September 30, 2026 increased approximately $3.50 per BOE, or 11.1%, over the prior year period as our realized crude oil prices increased 31.5% and realized NGL prices increased 26.5% partially offset by natural gas prices which decreased 8.4% from the three months ended September 30, 2025. Average daily equivalent production decreased 4.6% from 7,315 BOEPD in the prior year period to 6,978 BOEPD in the current period primarily as a result of a reduction in crude oil production. Production is down due to the natural decline across the portfolio. In addition, the prior year period includes flush production from wells brought online at Chaveroo Field which was 100% crude oil.
Lease Operating Costs
Ad valorem and production taxes were $1.4 million for each of the three months ended September 30, 2026 and 2025. On a per unit basis, ad valorem and production taxes were $2.14 per BOE and $2.11 per BOE for the three months ended September 30, 2026 and 2025, respectively. The increase on a per unit basis is due to the overall decrease in production.
Gathering, transportation and other costs were $2.7 million for the three months ended September 30, 2026 compared to $2.9 million for the three months ended September 30, 2025. 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 $4.27 per BOE and $4.30 per BOE for the three months ended September 30, 2026 and 2025, respectively.
Other lease operating costs were $8.2 million for the three months ended September 30, 2026 compared to $8.8 million for the three months ended September 30, 2025. Other lease operating costs decreased primarily due to a decrease in workover repairs at SCOOP/STACK and lower operating costs at TexMex due to a change of operatorship. On a per unit basis, other lease operating costs decreased to $12.84 per BOE for the three months ended September 30, 2026 from $13.04 per BOE in the three months ended September 30, 2025.
Depletion of Full Cost Proved Oil and Natural Gas Properties
Depletion expense decreased from $5.6 million for the three months ended September 30, 2025 to $5.3 million for the three months ended September 30, 2026 primarily due to a decrease in production from the prior year period. On a per unit basis, depletion expense was $8.32 per BOE and $8.26 per BOE for the three months ended September 30, 2026 and 2025, respectively.
General and Administrative Expenses
General and administrative expenses for the three months ended September 30, 2026 and 2025 were $2.1 million and $1.8 million, respectively. The increase in the current period is primarily due to an increase in salaries and benefits and professional fees. On a per unit basis, general and administrative expenses were $3.22 per BOE and $2.66 per BOE for the three months ended September 30, 2026 and 2025, respectively.
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Net Gain (Loss) on Derivative Contracts
We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. Financial hedges are a requirement under our Senior Secured Credit Facility and help establish commodity price floors, contributing to stable cash flows when derivative contracts are settled. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the unaudited condensed consolidated statements of operations. The amounts recorded on the unaudited condensed consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized gains (losses) on our average realized prices for the periods presented. As a result of our recent acquisitions and the corresponding borrowings on our Senior Secured Credit Facility, we are required by terms in our Senior Secured Credit Facility to hedge 75% of our crude oil and natural gas production (excluding NGLs). In March 2026, WTI oil prices reached their highest levels since 2022 due to crude oil disruptions at key oil shipping routes in the Middle East, contributing to considerable commodity price fluctuations and realized losses on our crude oil derivative contracts since. The significant increase in forward commodity prices as of September 30, 2026, resulted in an unrealized loss on the mark-to-market of our hedges. As of September 30, 2026, we had $3.0 million derivative assets, $2.7 million of which was classified as current, and $7.5 million derivative liabilities, $7.0 million of which was classified as current. We expect to see continued volatility in the fair value of our derivative contracts as commodity prices fluctuate.
Three Months Ended | ||||||||||||
September 30, | ||||||||||||
(in thousands, except per unit and per BOE amounts) | | 2026 | | 2025 | | Variance | | Variance % | ||||
Realized gain (loss) on derivative contracts | $ | (1,311) | $ | 878 | $ | (2,189) | N.M. | |||||
Unrealized gain (loss) on derivative contracts | (4,054) | 1,303 | (5,357) | N.M. | ||||||||
Total net gain (loss) on derivative contracts | $ | (5,365) | $ | 2,181 | $ | (7,546) | N.M. | |||||
Average realized crude oil price per BBL | $ | 81.74 | $ | 62.18 | $ | 19.56 | 31.5 | % | ||||
Cash effect of oil derivative contracts per BBL | (13.17) | 1.10 | (14.27) | N.M. | ||||||||
Crude oil price per BBL (including impact of realized derivatives) | $ | 68.57 | $ | 63.28 | $ | 5.29 | 8.4 | % | ||||
Average realized natural gas price per MCF | $ | 2.51 | $ | 2.74 | $ | (0.23) | (8.4) | % | ||||
Cash effect of natural gas derivative contracts per MCF | 0.43 | 0.30 | 0.13 | 43.3 | % | |||||||
Natural gas price per MCF (including impact of realized derivatives) | $ | 2.94 | $ | 3.04 | $ | (0.10) | (3.3) | % | ||||
“N.M.” means “Not Meaningful.”
Interest Expense
Interest expense increased $0.1 million for the three months ended September 30, 2026 compared to the prior year period primarily due to additional borrowings drawn on our Senior Secured Credit Facility to finance our Permian Minerals Acquisition in August 2026. The weighted average interest rate on our borrowings decreased to 6.48% for the three months ended September 30, 2026 compared to 7.12% for the three months ended September 30, 2025 partially offsetting the increase in interest expense due to increased borrowings.
Income Tax (Expense) Benefit
For the three months ended September 30, 2026, we recognized income tax benefit of $1.5 million on net losses before income taxes of $4.5 million compared to income tax expense of $0.4 million on net income before income taxes of $1.2 million for the three months ended September 30, 2025. The effective tax rates were 33.8% and 30.7% for three months ended September 30, 2026 and 2025, respectively. We continue to evaluate our tax provision on a quarterly basis and adjust our effective tax rate for any given changes in facts and circumstances that are expected in the future.
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Critical Accounting 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 estimates from those described in our Annual Report on Form 10-K for the fiscal year ended June 30, 2026.
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 years 2027 and 2026, we did not post collateral. We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivatives” to our unaudited condensed consolidated financial statements for more details.
Interest Rate Risk
We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents. Additionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either (i) SOFR, subject to a minimum SOFR of 3.25%, plus a credit spread adjustment of 0.05%, or (ii) the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%, plus, in either case of (i) or (ii), an applicable margin of 2.75%. SOFR rates are sensitive to the period of contract and market volatility, as well as changes in forward interest rate yields. Under our current practices, we do not use interest rate derivative instruments to manage exposure to interest rate changes.
Item 4. Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s (“SEC”) rules and forms. This information is accumulated and communicated to
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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(e) and 15d-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 September 30, 2026 our disclosure controls and procedures were 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 September 30, 2026, 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
We are not currently a party to any material pending legal proceedings. See Note 10, “Commitments and Contingencies” to our unaudited condensed consolidated financial statements in Item 1. Condensed Consolidated Financial Statements (Unaudited) for additional information, which is incorporated herein by reference.
Item 1A. Risk Factors
There have been no material changes to the risk factors disclosed in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended June 30, 2026.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
The table below summarizes information about the Company's purchases of its equity securities during the three months ended September 30, 2026.
(c) Total number | (d) Maximum dollar value | |||||||||
(a) Total number | of shares | of shares that may yet be | ||||||||
of shares | purchased as part | purchased under the | ||||||||
purchased and | (b) Average price | of public announced | plans or programs | |||||||
Period | received (1) | paid per share (1) | plans or programs | (in thousands) | ||||||
July 2026 | — | $ | — | — | $ | — | ||||
August 2026 | — | — | — | — | ||||||
September 2026 | 32,617 | 3.69 | — | — | ||||||
| (1) | During the three months ended September 30, 2026, all of the shares received were surrendered by employees in exchange for the payment of tax withholding upon the vesting of restricted stock awards. |
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Item 3. Defaults Upon Senior Securities
Not Applicable.
Item 4. Mine Safety Disclosures
Not Applicable.
Item 5.
During the quarter ended September 30, 2026, none of our directors or officers adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.
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Item 6. Exhibits
The following documents are included as exhibits to the Quarterly Report on Form 10-Q. Those exhibits incorporated by reference are so indicated by the information supplied with respect thereto. Those exhibits which are not incorporated by reference are attached hereto.
3.1 | Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q filed February 8, 2023) | |
3.3 | Amended and Restated Bylaws (incorporated by reference to Exhibit 3.3 of our Annual Report on Form 10-K filed September 13, 2023) | |
10.2.5* | Amended Interim Commitment Modification and Supplement to Amended and Restated Credit Agreement, dated October 20, 2026 | |
10.17* | Purchase and Sale Agreement dated August 18, 2026, between Evolution Petroleum Corporation, Evolution Minerals, LLC, and non-affiliated private seller | |
31.1** | Certification of Principal Executive Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as Amended as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
31.2** | Certification of Principal Financial Officer Pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934, as Amended as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
32.1** | Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
32.2** | Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
101.INS* | Inline XBRL Instance Document | |
101.SCH* | Inline XBRL Taxonomy Extension Schema Document | |
101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document | |
101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document | |
101.LAB* | Inline XBRL Taxonomy Extension Label Linkbase Document | |
101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document | |
104* | Cover Page Interactive Data File (embedded within the Inline XBRL document) |
* Filed herewith.
** Furnished herewith.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| | Evolution Petroleum Corporation | |
Date: November 10, 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 | |||
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