EVOLUTION PETROLEUM CORP

Note 1. Financial Statement Presentation

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

The Company’s oil and natural gas properties consist of non-operated working and mineral interests inthe following areas: the SCOOP and STACK plays of the Anadarko Basin located in central Oklahoma; the Chaveroo Field in Chaves and Roosevelt Counties of New Mexico; the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field located in Hot Springs County, Wyoming, a secondary oil recovery field utilizing water injection wells to pressurize the reservoir; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO 2 enhanced oil recovery project; the TexMex interests located in Lea, Eddy and Chaves Counties, New Mexico and Stephens County, Texas; as well as small overriding royalty interests infour onshore Texas wells.

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

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

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

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

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

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

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

Recently Issued Accounting Pronouncements

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

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

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

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 fromthe SCOOP and STACK plays in central Oklahoma; the Chaveroo Field in Chaves and Roosevelt Counties of New Mexico; the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field in Wyoming; the Delhi Field in Northeast Louisiana; and the TexMex interests located in Lea, Eddy and Chaves Counties, New Mexico and Stephens County, Texas. Additionally, an overriding royalty interest retained in a past divestiture of Texas properties provides de minimis revenue. The following table disaggregates the Company’s revenues by major product for the three and six months ended December 31, 2025 and 2024 (in thousands):

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 productionone totwo months after delivery.

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

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

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

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

Note 3. Acquisitions

Purchase of SCOOP/STACK Minerals

On August 4, 2025, the Company completed the acquisition of certain mineral and royalty interests in the SCOOP and STACK plays in of Oklahoma from a non-affiliated private seller (the “Minerals Acquisition”) in a cash transaction valued at approximately$16.3 million, subject to customary post-closing adjustments. The Minerals Acquisition has an effective date of May 1, 2025. The Company accounted for the transaction as an asset acquisition, allocating$11.7 million of the purchase price to proved oil and natural gas properties, subject to amortization, and$4.6 million to unproved properties. The Company funded the purchase price for the Minerals Acquisition with a combination of$15.0 million in borrowings under its Senior Secured Credit Facility and cash on hand. The acquired assets include an average royalty interest of 0.6% across approximately 5,500 net royalty acres located primarily in Grady and Canadian Counties, Oklahoma.

TexMex Acquisition

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

Note 4. Property and Equipment

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

As of December 31, 2025, $4.6 million of oil and natural gas property costs were not subject to amortization. These costs related to mineral and royalty interests acquired as part of the Company’s Minerals Acquisition described in Note 3, “Acquisitions” above. The mineral and royalty interests include approximately 3,600 net royalty acres for unproved locations. Property costs identified at the Minerals Acquisition associated with proved reserves were recorded to evaluated oil and natural gas properties and subject to amortization.

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

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 $11.1 million and $10.3 million for the six months ended December 31, 2025 and 2024, respectively. During the six months ended December 31, 2025 and 2024, the Company incurred development capital expenditures of $2.5 million and $2.2 million, respectively.

At December 31, 2025, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended December 31, 2025 of the West Texas Intermediate (“WTI”) crude oil spot price of $66.01 per barrel and Henry Hub natural gas spot price of $3.40 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $23.22, which was based on historical differentials to WTI as NGLs do not have any single comparable reference index price. Using these prices, at December 31, 2025 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, subject to amortization, and, as a result, no write-down was applicable.

At December 31, 2024, the ceiling test value of the Company’s reserves was calculated based on the first-day-of the month average for the 12-months ended December 31, 2024 of the WTI crude oil spot price of $76.32 per barrel and Henry Hub natural gas spot price of $2.13 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $22.60, which was based on historical prices received as NGLs do not have any single comparable reference index price. Using these prices, at December 31, 2024 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties, subject to amortization, and, as a result, no write-down was applicable.

Note 5. Senior Secured Credit Facility

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

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

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

bankruptcy; judgments and change in control. The Senior Secured Credit Facility also contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (i) a maximum total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. In addition, the Senior Secured Credit Facility contains hedging requirements that apply when utilization is greater than 25% of (x) the Margined Collateral Value, as defined under the Senior Secured Credit Facility, at any time when the leverage ratio is less than 2.25 to 1.00, or (y) the borrowing base, at any time when the leverage ratio is greater than or equal to 2.25 to 1.00. As of December 31, 2025, the Company had $54.5 million borrowings outstanding and $0.8 million of letters of credit outstanding under its Senior Secured Credit Facility, resulting in $9.7 million of available borrowing capacity. For the six months ended December 31, 2025 and 2024, the weighted average interest on borrowings under the Senior Secured Credit Facility was 6.88% and 7.80%, respectively.

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

On August 29, 2025, the Company entered into the first amendment of its Senior Secured Credit Facility with MidFirst Bank pursuant to which it was determined for purposes of the hedge covenant that total crude oil and natural gas volumes from proved developed producing reserves will be combined on a barrels of oil equivalent basis to determine compliance with the required hedging covenant.

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

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

Note 6. Income Taxes

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

There wereno unrecognized tax benefits, nor any accrued interest or penalties associated with unrecognized tax benefits during the periods presented in the unaudited condensed consolidated financial statements. The Company believes that it has appropriate support for the income tax positions taken and to be taken on the Company’s tax returns and that the accruals for tax liabilities are adequate for all open years based on its assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations for the fiscal years ended June 30, 2021 through June 30, 2024 for federal tax purposes and for the fiscal years ended June 30, 2020 through June 30, 2024 for state tax purposes. To the extent the Company utilizes net operating losses (“NOLs”) generated in earlier years, such earlier years may also be subject to audit.

On July 4, 2025, President Trump signed into law the One Big Beautiful Bill Act ("OBBBA"). The OBBBA makes permanent key elements of the Tax Cuts and Jobs Act of 2017, including 100% bonus depreciation and the business interest expense limitation, as well as other provisions. The Company’s consolidated financial statements for the six months ended December 31, 2025, include the OBBBA’s effect for the period beginning July 1, 2025, through December 31, 2025. Some of the provisions in the OBBBA are effective for periods before July 1, 2025. The Company plans to file its June 30, 2025 tax return on or before April 15, 2026, and thus any tax effects related to prior periods will be recorded in the financial statements as a return to provision adjustment once identified and quantifiable. While the

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

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

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

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

Note 7. Derivatives

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

It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of December 31, 2025, the Company didnot post collateral under any of its derivative contracts during the periods in which contracts were open as they were secured under the Company’s Senior Secured Credit Facility.

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

All derivative contracts are recorded at fair market value in accordance with ASC 815,Derivatives and Hedging (“ASC 815”) and ASC 820,Fair Value Measurement (“ASC 820”) and included in the unaudited condensed consolidated balance sheets as assets or liabilities. The*“Derivative contract assets”* and*“Derivative contract liabilities”* represent

the difference between the market commodity prices and the hedged prices for the remaining volumes of production hedges as of December 31, 2025 and June 30, 2025 (the “mark-to-market valuation”).

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

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

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

Subsequent to December 31, 2025, the Company entered into the following new crude oil and natural gas derivative contracts:

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):

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

Note 8. Fair Value Measurement

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

The three levels are defined as follows:

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

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

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

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

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

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

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

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

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

Note 9. Asset Retirement Obligations

The Company’s ARO represents the estimated present value of the amount expected to be incurred to plug, abandon, and remediate its oil and natural gas properties at the end of their productive lives in accordance with applicable laws and regulations. The Company records the ARO liability on the unaudited condensed consolidated balance sheets and capitalizes the cost in*“Oil and natural gas properties, subject to amortization, net”during the period in which the obligation is incurred. The Company records the accretion of its ARO liabilities in“Depletion, depreciation and accretion”*expense in the unaudited condensed consolidated statements of operations.

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

Note 10. Commitments and Contingencies

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

Note 11. Stockholders’ Equity

Common Stock

As of December 31, 2025, the Company had 35,003,844 shares of common stock outstanding.

The Company began paying quarterly cash dividends on common stock in December 2013. As of December 31, 2025, the Company has cumulatively paid over $143.1 million in cash dividends. The Company paid dividends of $8.4 million and $8.1 million to its common stockholders during the six months ended December 31, 2025 and 2024, respectively.

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

On October 21, 2024, the Company entered into an At-the-Market (“ATM”) equity Sales Agreement (the “ATM Sales Agreement”) with Roth Capital Partners, LLC (the “Lead Agent”), Northland Securities Inc., and A.G.P./Alliance Global Partners pursuant to which the Company may issue and sell, from time to time, up to$30.0 million of shares of common stock through or to the Lead Agent, acting as agent or principal to facilitate acquisitions and other general corporate purposes. During the six months ended December 31, 2025, the Company sold a total of approximately 0.3 million shares of its common stock under the ATM Sales Agreement for net proceeds of approximately$1.2 million, net

of$46 thousand of offering costs. The Company intends to use the net proceeds from sales of common stock for general corporate purposes, including to repay outstanding indebtedness.

On September 8, 2022, the Board of Directors approved a share repurchase program, under which the Company was authorized to repurchase up to $25.0 million of its common stock in the open market through December 31, 2024. The Company funded repurchases from working capital and cash provided by operating activities. The share repurchase program was complimentary to the existing dividend policy and was a tax efficient means to further improve shareholder return. The shares were repurchased in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The Company did not repurchase any shares of common stock under the plan during the six months ended December 31, 2024. While the plan was in effect, a total of 0.8 million shares of the Company’s common stock were repurchased under the program at a total cost of approximately $4.6 million, including incremental direct transaction costs.

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

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

Expected Tax Treatment of Dividends

For the fiscal year ended June 30, 2025, all common stock dividends for that fiscal year were treated for tax purposes as qualified dividend income to the recipients. Based on its current projections for the fiscal year ended June 30, 2026, the Company expects all common stock dividends for such period to be treated as qualified dividend income to the recipients. Such projections are based on the Company’s reasonable expectations as of December 31, 2025 and are subject to change based on the Company’s final tax calculations at the end of the fiscal year.

Stock-Based Incentive Plan

The Evolution Petroleum Corporation 2016 Equity Incentive Plan (as amended the “2016 Plan”) authorizes the issuance of 3.6 million shares of common stock prior to its expiration on December 8, 2026. On December 5, 2024 shareholders approved and adopted the amendment and restatement of the 2016 Plan (hereinafter the “Amended and Restated Plan”), which increased the shares authorized for issuance under the 2016 Plan by 2.1 million shares to a maximum of 5.7 million shares. The duration of the Amended and Restated Plan is indefinite, provided that no new awards shall be made under the Amended and Restated Plan on or after the tenth anniversary of the date the stockholders approved the Amended and Restated Plan. Incentives under the Amended and Restated Plan may be granted to employees, directors, and consultants of the Company in any one or a combination of the following forms: incentive stock options, non-qualified stock options, stock appreciation rights, restricted awards, and performance share awards. As of December 31, 2025 and June 30, 2025, approximately 2.1 million shares and 2.5 million shares, respectively, remained available for grant under the Amended and Restated Plan.

The Company estimates the fair value of stock-based compensation awards on the grant date to provide the basis for future compensation expense. During the three and six months ended December 31, 2025, the Company recognized $0.6 million and $1.2 million, respectively, related to stock-based compensation. During the three and six months ended December 31, 2024, the Company recognized$0.7 million and $1.2 million, respectively, related to stock-based compensation. Stock-based compensation expense is recorded as a component of “General and administrative expenses” on the unaudited condensed consolidated statements of operations.

Time-Vested Restricted Stock Awards

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

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

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

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

During the six months ended December 31, 2025, the Company granted a total of 0.4 million equity awards that included 0.2 million time-vested restricted stock awards and 0.2 million performance-based restricted stock awards.

During the six months ended December 31, 2024, the Company granted a total of 0.5 million equity awards that included 0.2 million time-vested restricted stock awards,0.2 million performance-based restricted stock awards, and 0.1 million of performance-based contingent stock units.

For performance-based awards granted during the six months ended December 31, 2025 and 2024, the assumptions used in the Monte Carlo simulation valuations were as follows:

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

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

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

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):

Unvested restricted stock awards, totaling 0.2 million and 0.1 million for the three and six months ended December 31, 2025, respectively, were not included in the computation of diluted earnings per common share because the effect would have been anti-dilutive.

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

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

Note 13. Leases

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

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

most recently November 30, 2025 and set to expire June 30, 2031. The Company doesnot have any leases that meet the criteria for classification as a finance lease or a short-term lease.

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

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

The following table presents the Company’s ROU assets and lease liabilities (in thousands):

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

Note 14. Additional Financial Statement Information

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

Note 15. Subsequent Events

Dividend Declaration

On February 9, 2026, the Company declared a quarterly cash dividend of $0.120 per share of common stock to shareholders of record on March 16, 2026 and payable on March 31, 2026.