EVOLUTION PETROLEUM CORP

Note 1. Summary of Significant Events and Accounting Policies

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

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

Principles of Consolidation and Reporting. The 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 consolidated financial statements for the previous year may 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 interest.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles in the United States 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 consolidated financial statements.

From time to time, the Company conducts joint venture audits of the operators of its oil and natural gas properties. Any audit findings are reflected in the consolidated financial statements once agreed upon by all parties. In fiscal year 2025, the Company received a credit adjustment of $1.9 million from one its operators at its Barnett Shale properties, recognized as a reduction to “Lease operating costs” on the consolidated statement of operations and “Accounts payable” on the consolidated balance sheet for the fiscal year ended June 30, 2025.

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 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 consolidated balance sheets. The significant expense categories regularly provided to and reviewed by the CODM are the expenses categories as noted on the consolidated statements of operations.

Cash and Cash Equivalents. The Company considers all highly liquid investments, with original maturities of 90 days or less when purchased, to be cash and cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable consist of accrued hydrocarbon revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. The Company establishes provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2026 and 2025, no allowance for doubtful accounts was considered necessary.

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. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of depletion, estimated future development costs, and asset retirement costs (net of salvage values) not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves.

The capitalized costs of the Company’s oil and natural gas properties, net of accumulated amortization and related deferred income taxes are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations. Any excess over the full cost ceiling limitation is charged to expense as an impairment and is reflected as additional accumulated depletion, depreciation, and impairment or as a credit to oil and natural gas properties.

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 June 30, 2026 and 2025, the Company did not have any costs excluded from its full-cost pool or depletion and amortization.

Other Property and Equipment. Other property and equipment includes building leasehold improvements, data processing and telecommunications equipment, office furniture, and office equipment. These items are recorded at cost

and depreciated over expected lives of the individual assets or group of assets, which range from three toseven years. The assets are depreciated using the straight-line method. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. Repair and maintenance costs are expensed in the period incurred.

Asset Retirement Obligations. An asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred. It is associated with an increase in the carrying amount of the related long-lived asset, the Company’s oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The initial recognition or subsequent revision of asset retirement cost is considered a Level 3 fair value measurement. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment.

Fair Value of Financial Instruments. The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivative instruments, and debt. Except for derivatives, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable are short-term instruments and approximate fair value due to their highly liquid nature. The carrying amount of debt approximates fair value as the variable rates on the Senior Secured Credit Facility, as defined in Note 5,“Senior Secured Credit Facility,” are market interest rates. The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and natural gas, discount rates, and volatility factors.

Concentrations of Credit Risk. The Company’s primary concentrations of credit risk are the risks of uncollectible accounts receivable, and to a lesser extent, the non-performance by counterparties under the Company’s derivative contracts, and cash and cash equivalent balances in excess of limits federally insured by the Federal Deposit Insurance Corporation.

Substantially all of the Company’s accounts receivable as of June 30, 2026 and 2025 are from crude oil, natural gas, and NGL sales to third-party purchasers in the oil and natural gas industry. The Company holds working interests and mineral interests in crude oil and natural gas properties for which a third-party serves as operator. As a non-operator, the Company primarily markets its production through its field operators, except at the Jonah Field, where the Company takes its natural gas and NGL production in-kind. As a non-operator, the Company is highly dependent on the success of its third-party operators and the decisions made in connection with their operations. With the exception of the Jonah Field, the third-party operator sells the crude oil, natural gas, and NGLs to the purchaser, collects the cash, and distributes the cash to the Company. In the year ended June 30, 2026, three individual operators, Diversified, Denbury (ExxonMobil), and Foundation, each accounted for more than 10% of the Company’s total revenues, collectively representing approximately 46% of the Company’s total revenues for the year. In the year ended June 30, 2025, three individual operators, Denbury (ExxonMobil), Diversified, and Foundation, each accounted for more than 10% of the Company’s total revenues, collectively representing approximately 51% of the Company’s total revenues for the year. The majority of the Company’s crude oil, natural gas, and NGL production is sold to purchasers under short-term (less than 12 months) contracts at market-based prices.

Derivative Instruments. The Company follows Accounting Standards Codification (“ASC”) 815,Derivatives and Hedging (“ASC 815”). From time to time, in accordance with the Company’s risk management strategy and with certain

covenants under the Senior Secured Credit Facility, it may hedge a portion of its forecasted crude oil, natural gas, and NGL production. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”); the agreement provides for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in*“Net gain (loss) on derivative contracts”* on the consolidated statements of operations.

Estimates of Proved Reserves*.*The estimated quantities of proved oil and natural gas reserves have a significant impact on the underlying financial statements. The estimated quantities of proved reserves are used to calculate depletion expense and the estimated future net cash flows associated with those proved reserves is the basis for determining impairment under the quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex and requires significant decisions in the evaluation of all available geologic, geophysical, engineering, and economic data. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information; this includes reservoir performance, additional development activity, new geologic and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates prepared by the Company’s third-party independent engineers represent the most accurate assessments possible, the subjective decisions and variances in available data for the properties make these estimates generally less precise than other estimates included in the Company’s financial statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect the Company’s estimated future net cash flows of its proved reserves. These changes could affect the Company’s quarterly ceiling test calculation and could significantly affect its depletion rate.

Income Taxes. The Company recognizes deferred income tax assets and liabilities based on the differences between the tax basis of assets and liabilities and its reported amounts in the financial statements that may result in taxable or deductible amounts in future years. The measurement of deferred income tax assets may be reduced by a valuation allowance based upon management’s assessment of available evidence if it is deemed more likely than not that some or all of the deferred income tax assets will not be realizable. The Company recognizes a tax benefit from an uncertain position when it is more likely than not that the position will be sustained upon examination which is based on the technical merits of the position. The Company records the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax expense.

Earnings (Loss) Per Share. The Company grants restricted stock awards which entitle the recipient to all of the rights of a shareholder of the Company including non-forfeitable rights to receive all dividends or other distributions paid with respect to such share; therefore, it applies the two-class method of calculating basic and diluted earnings (loss) per share (“EPS”) in accordance with ASC 260,Earnings Per Share (“ASC 260”). Basic EPS is computed by dividing earnings or loss available to common stockholders, after allocating undistributed earnings to participating securities, by the weighted-average number of common shares outstanding during the period. The computation of diluted EPS is similar to the computation of basic EPS, except that the denominator is increased to include the number of additional common shares that would have been outstanding if potentially dilutive common shares had been issued. Unvested performance-based restricted stock awards and unvested contingent restricted share units are only potentially dilutive if the awards meet their respective performance criteria as of the period end. The Company uses the treasury stock method to determine the effect of potentially dilutive common shares on diluted EPS, unless the effect would be anti-dilutive. The unamortized stock-based compensation expense related to unvested awards is assumed to be used to repurchase shares of common stock at the average market price during the period. The incremental shares (the difference between the number of shares assumed issued and the number of shares assumed repurchased) are included in the denominator of the diluted

EPS computation. Awards with performance-based vesting restrictions are included in the computation of diluted shares, if dilutive, when the underlying performance conditions either (i) were satisfied as of the end of the reporting period or (ii) would be considered satisfied if the end of the reporting period were the end of the related contingency period.

Recently Issued Accounting Pronouncements

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

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

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

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

Note 2. Revenue Recognition

The Company’s revenues are primarily generated from its crude oil, natural gas and NGL production from the SCOOP and STACK plays in central Oklahoma; the Chaveroo Field in Chaves and Roosevelt Counties of New Mexico; the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field in Wyoming; the Delhi Field in Northeast Louisiana; and the TexMex interests located in Lea, Eddy and Chaves Counties, New Mexico and Stephens County, Texas;. Additionally, the Company has small overriding royalty and mineral interests in Texas and Louisiana. The following table disaggregates the Company’s revenues by major product for the years ended June 30, 2026 and 2025 (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 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 and Divestitures

From December 2025 through June 2026, the Company acquired mineral and royalty interests in multiple parishes across Louisiana from various private sellers for cash consideration totaling$6.2 million, including capitalized direct transaction costs. 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.

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$16.3 million, including customary post-closing adjustments of$0.8 million. The SCOOP/STACK Minerals Acquisition had an effective date of May 1, 2025. The Company accounted for the transaction as an asset acquisition, allocating$12.5 million of the purchase price to proved oil and natural gas properties, subject to amortization, and$3.8 million to unproved properties. The Company funded the purchase price for the SCOOP/STACK 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.

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 $3.1 million, before customary post-closing adjustments.

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 $8.9 million including customary post-closing adjustments of $0.3 million, 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.

In accordance with the FASB’s authoritative guidance on asset acquisitions, the Company allocated the cost of the above acquisitions to the assets acquired and liabilities assumed based on a relative fair value basis of the assets acquired and liabilities assumed, withno recognition of goodwill or bargain purchase gain recorded. Incremental legal and professional fees related directly to the acquisitions were capitalized as part of the acquisition cost. The fair value is 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 (exit price). Fair value measurements also utilize market assumptions of market participants.

Subsequent to fiscal year-end, in August 2026, the Company closed on an acquisition of certain mineral and royalty interests in the core Midland Basin of the Permian Basin. See Note 15, “Subsequent Events,” for further details.

Note 4. Property and Equipment

Property and equipment as of June 30, 2026 and 2025 consisted of the following (in thousands):

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.

As of June 30, 2026 and 2025, all oil and natural gas property costs were subject to amortization. Depletion on oil and natural gas properties was $21.2 million and $20.4 million for the years ended June 30, 2026 and 2025, respectively. During the years ended June 30, 2026 and 2025, the Company incurred development capital expenditures of $5.5 million and $13.2 million, respectively.

At June 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 June 30, 2026 of the West Texas Intermediate (“WTI”) crude oil spot price of $72.93 per barrel and Henry Hub natural gas spot price of $3.62 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $27.50, which was based on historical differentials to WTI as NGLs do not have any single comparable reference index price. Using these prices, at June 30, 2026 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 June 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 June 30, 2025 of the WTI crude oil spot price of $71.20 per barrel and Henry Hub natural gas spot price of $2.87 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $25.24, which was based on historical differentials to WTI as NGLs do not have any single comparable reference index price. Using these prices, at June 30, 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.

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 borrowing base of $65.0 million, maturing on June 30, 2028. As of June 30, 2026, the borrowing base was $65.0 million. 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 June 30, 2026, the Company had $56.5 million borrowings outstanding and $0.8 million in letters of credit outstanding under its Senior Secured Credit Facility, resulting in $7.7 million of available borrowing capacity. For the years ended June 30, 2025 and 2024, the weighted average interest rate on borrowings under the Senior Secured Credit Facility was 6.69% and 7.48%, 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 Facility, was modified to $65.0 million. In addition, it granted the Company additional time to enter into further commodity hedges to meet the hedging requirements under the Senior Secured Credit Facility.

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.

On March 7, 2025, the Company entered into a letter agreement with MidFirst Bank, which allows for the option to hedge 72% of expected natural gas production rather than hedging 25% of expected crude oil production in each month of the calendar year ending December, 31, 2026, as long as the Company remains in the 25% required hedging tier. See Note 7,“Derivatives,” for a listing of all crude oil and natural gas derivative contracts the Company has entered into.

As of June 30, 2026, the Company was 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 year ended June 30, 2026, the Company amortized $0.2 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, net” on the consolidated balance sheets.

Subsequent to fiscal year end, 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 $65.0 million to $73.0 million from August 20, 2026 until October 20, 2026, unless redetermined in accordance with the terms of the credit agreement.

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 wereno unrecognized tax benefits, nor any accrued interest or penalties associated with unrecognized tax benefits during the years ended June 30, 2026 and 2025. 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, 2022 through June 30, 2025 for federal tax purposes and for the fiscal years ended June 30, 2021 through June 30, 2025 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.

Income tax (expense) benefit for the years ended June 30, 2026 and 2025 is comprised of the following (in thousands):

For the year ended June 30, 2026 the Company recognized an income tax benefit of $0.7 million and had an effective tax rate of 22.8% compared to income tax expense of $0.4 million and an effective tax rate of 21.2% for the year ended June 30, 2025. During each of the years ended June 30, 2026 and 2025, the Company recognized an income tax benefit of $0.1 million related to the vesting of restricted stock awards.

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 year ended June 30, 2026, include the OBBBA’s effect for the period beginning July 1, 2025, through June 30,2026. 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 year ended June 30, 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. The following table presents the reconciliation of the Company’s income taxes calculated at the statutory federal tax rate to the income tax (expense) benefit (in thousands):

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. The components of net deferred income tax assets (liabilities) recognized are as follows (in thousands):

Evolution Petroleum OK, Inc., a wholly-owned subsidiary of the Company, had a prior year carryforward of NOLs of $8.9 million generated during tax years 2011 through 2017. In fiscal year 2024, in conjunction with the acquisition of oil and natural gas properties in Oklahoma by Evolution Petroleum OK, Inc., a deferred tax asset was recorded for a portion of this NOL carryforward. In fiscal year 2025, the valuation allowance of $0.1 million was released.

The Company’s cash paid for income taxes, net of refunds received, during the years ended June 30, 2026 and 2025 are as follows (in thousands):

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 consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the 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 June 30, 2026, 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 consolidated statements of operations.

All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820,Fair Value Measurement (“ASC 820”) and included in the 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 June 30, 2026 and 2025 (the “mark-to-market valuation”).

The following table summarizes the location and fair value amounts of all derivative contracts in the consolidated balance sheets as of June 30, 2026 and 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 consolidated statements of operations for the years ended June 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.

As of June 30, 2026, the Company had the following open crude oil and natural gas derivative contracts:

Subsequent to June 30, 2026, 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 consolidated balance sheets. The following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative contracts as of June 30, 2026 and 2025 (in thousands):

The Company enters into an 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 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 as of June 30, 2026 and 2025 (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 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 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 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 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 years ended June 30, 2026 and 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 June 30, 2026, the Company had 35,949,843 shares of common stock outstanding.

The Company began paying quarterly cash dividends on common stock in December 2013. As of June 30, 2026, the Company has cumulatively paid over $151.7 million in cash dividends. The Company paid dividends of $16.9 million

and $16.3 million to its common stockholders during the years ended June 30, 2026 and 2025, respectively. The following table reflects the dividends paid per share within the respective quarterly periods:

On September 10, 2026, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2026. Refer to Note 15,*“Subsequent Events,”*for a further discussion.

On August 20, 2026, the Company completed a public offering issuing an aggregate of 4.3 million shares of its common stock. See Note 15, “Subsequent Events,” for further details.

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$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, the Company executed a new ATM equity Sales Agreement, substantially consistent with the original October 2024 agreement (the “ATM Sales Agreements”) restoring the$30.0 million common stock sales capacity. For the year ended June 30, 2026, the Company sold a total of approximately 1.4 million shares of its common stock under the ATM Sales Agreements for net proceeds of approximately$5.8 million, net of$0.2 million of offering costs incurred. For the year ended June 30, 2025, the Company sold a total of approximately 0.7 million shares of its common stock under the ATM Sales Agreements for net proceeds of approximately$3.5 million, after deducting$0.3 million in offering costs. Net proceeds from the sales of common stock were used to fund a portion of our Louisiana Minerals acquisitions and for general corporate purposes.

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, the plan’s termination date. 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 years ended June 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 in the years ended June 30, 2026 and 2025 (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.

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 June 30, 2026 and 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. For the years ended June 30, 2026, and 2025, the Company recognized $2.3 million and $2.5 million, respectively, related to stock-based compensation expense recorded as a component of “General and administrative expenses” on the 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.

For performance-based awards granted during the years ended June 30, 2026 and 2025, the assumptions used in the Monte Carlo simulation valuations were as follows:

Unvested restricted stock awards as of June 30, 2026 consisted of the following:

The following table sets forth the restricted stock award transactions for the years ended June 30, 2026 and 2025:

The following table sets forth contingent restricted stock unit transactions for the years ended June 30, 2026 and 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 (both time-vested and performance-based), totaling approximately 0.8 million for the year ended June 30, 2026, 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 (both time-vested and performance-based), totaling approximately 0.1 million for the year ended June 30, 2025, 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.

Pursuant to year end, in August 2026, the Company issued an additional 4.3 million shares of common stock. See Note 15, “Subsequent Events,” for further details.

Note 13. Leases

Operating leases are reflected as an operating lease right of use (“ROU”) asset included in*“Other assets, net”, 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 does not have any leases that meet the criteria for classification as a finance lease or a short-term lease.

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

The table below summarized the Company’s leases for the years ended June 30, 2026 and 2025 (in thousands, except years and discount rate):

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

As of June 30, 2026, the future minimum lease payments associated with the Company’s non-cancellable operating lease for office space are as follows (in thousands):

The Company applied the following practical expedients as provided in the standards update which provide elections to not reassess:

Note 14. Additional Financial Statement Information

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

Note 15. Subsequent Events

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 $65.0 million to $73.0 million from August 20, 2026 until October 20, 2026, unless redetermined early in accordance with the terms of the credit agreement. The Company currently expects to being its semi-annual Fall redetermination on or about October 1, 2026.

On August 20, 2026, the Company completed a public offering of 4.3 million shares of its common stock, at an offering price of $3.25 per share (the “Offering”). The Company received net proceeds of approximately$12.8 million from the Offering, after deducting underwriting discounts and commissions and estimated offering expenses. Net proceeds from the Offering, together with borrowings under its Senior Secured Credit Facility and cash on hand, were used to fund the Permian Minerals Acquisition (defined below).

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 $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. The Company funded the purchase price for the Permian Minerals Acquisition with a combination of net proceeds from its concurrent public equity offering and $3.2 million in borrowings under its Senior Secured Credit Facility. The acquired assets include approximately 3,420 net royalty acres across Reagan, Martin, Midland, Glasscock, and Upton Counties, Texas.

On September 10, 2026, the Company declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on September 21, 2026 and payable on September 30, 2026.