EPM · Read the filing

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Executive Overview

Liquidity and Capital Resources

Results of Operations

Critical Accounting Policies and Estimates

Executive Overview

General

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

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

Table of Contents

Recent Developments

Dividend Declaration

On September 11, 2025, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2025.

Purchase of SCOOP/STACK Minerals

On August 4, 2025, we completed the acquisition of certain mineral and royalty interests in the SCOOP/STACK area of Oklahoma from a non-affiliated private seller (the “Minerals Acquisition”) in a cash transaction valued at approximately $17.0 million, subject to customary post-closing adjustments. The Minerals Acquisition has an effective date of May 1, 2025. We funded the purchase price for the Minerals Acquisition with a combination of $15.0 million in borrowings under our Senior Secured Credit Facility and cash on hand. The acquired assets include an average royalty interest of 0.6% located on approximately 5,500 net royalty acres located primarily in Grady and Canadian Counties, Oklahoma.

Senior Secured Credit Facility

On June 30, 2025, we entered into an amended and restated senior secured reserve-based credit agreement (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. Refer to “Liquidity and Capital Resources” below for a further discussion.

Purchase of Non-operated Oil and Natural Gas Assets

On April 14, 2025, we closed the acquisition of non-operating working interests in certain long-life 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. We funded the purchase price for the TexMex Acquisition with a combination of cash on hand and borrowings under our Senior Secured Credit Facility. The TexMex Acquisition includes an average working interest of 42% and an average revenue interest of 35% in approximately 600 wells.

At-the-Market (“ATM”) Equity Sales Program

On October 21, 2024, we entered into an 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 we

Table of Contents

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. For the year ended June 30, 2025, we sold a total of approximately 0.7 million shares of our common stock under the ATM Sales Agreement for net proceeds of approximately $3.5 million, after deducting $0.3 million in offering costs. We intend to use the net proceeds from any sales of common stock for general corporate purposes, including to repay outstanding indebtedness.

Proved Reserves

The following table is a summary of our proved reserves as of June 30, 2025 and 2024:

Proved Reserves

Proved Reserves MMBOE 27.1 31.8 (14.8) %

% Developed 83.7 % 75.6 % 8.1 %

Standardized Measure ($MM) $ 155.2 $ 166.6 (6.8) %

Proved oil equivalent reserves as of June 30, 2025 were 27.1 MMBOE, a 4.7 MMBOE, or 14.8%, decrease from the previous year of 31.8 MMBOE. The net decrease in total proved reserves was primarily due to net negative revisions of 6.0 MMBOE and production roll-off of 2.6 MMBOE. These decreases were partially offset by 3.0 MMBOE of proved reserves purchased in the TexMex Acquisition as well as extensions of 0.9 MMBOE primarily at Chaveroo Field and SCOOP/STACK. Approximately 1.6 MMBOE of downward revisions were in our oil reserves and 4.4 MMBOE of downward revisions were in our natural gas and NGL reserves. Proved oil reserves declined primarily due to a decrease in the SEC trailing 12-month oil price of 10.4% from the prior fiscal year and drop-off of Williston Basin PUDs due to timing of future drilling plans. Natural gas and natural gas liquids reserves decreased due to a combination of lower price differentials received, specifically at Jonah Field, an increase in lease operating costs at our Barnett Shale properties, and drop-off of the Williston Basin PUDs due to timing of future drilling plans. These metrics impacted the late-in-life economic limits for oil, natural gas, and NGL production.

The Standardized Measure for proved reserves decreased 6.8% to $155.2 million, primarily due to volumes produced and sold and our overall downward revisions in proved reserves as discussed above. Oil prices decreased 10.4% from the prior year when oil was $79.45 per barrel compared to $71.20 per barrel at June 30, 2025. While the SEC price for natural gas increased 23.7% from $2.32 per MMBtu of natural gas at June 30, 2024 to $2.87 per MMBtu of natural gas at June 30, 2025, certain changes in other metrics such as lower price differentials caused our natural gas and natural gas liquids reserves to decrease, as stated above. Our proved reserves consist of 45% oil, 38% natural gas, and 17% NGLs; 83.7% are classified as proved developed and 16.3% are proved undeveloped.

Additional property and project information is included under Item 1. Business and in Note 4, “Property and Equipment” and our Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data, and in Exhibit 99.1 and 99.2 of this Form 10-K.

Risks and uncertainties

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

Oil, natural gas, and NGL prices have been, and we expect may continue to be, volatile. Lower oil and natural gas prices not only decrease our revenues, but an extended decline in oil or natural gas prices may affect planned capital

Table of Contents

expenditures and the oil and natural gas reserves that we can economically produce. Lower oil and natural gas prices may also reduce the amount of our borrowing base under our Senior Secured Credit Facility, which is determined at the discretion of the lenders based on various factors including the collateral value of our proved reserves.

At times, we do maintain cash balances in excess of the U.S. Federal Deposit Insurance Corporation (“FDIC”); however, we believe our bank counterparty to be financially sound. We also utilize insured cash sweep deposits to maximize the amount of our cash that is protected by FDIC insurance. We also rely heavily on our third-party operators who manage their own liquidity with various financial institutions. In recent years, the Federal Reserve took actions to raise interest rates in an attempt to tame inflation and slow the economy, which has contributed to volatility in markets. Currently, our oil and natural gas properties are operated by third-party operators and involve other third-party working interest owners. As a result, we have limited ability to influence the operation or future development of such properties. Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review the management of capital expenditures.

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

Liquidity and Capital Resources

As of June 30, 2025, we had $2.5 million in cash and cash equivalents and $37.5 million outstanding borrowings on our Senior Secured Credit Facility compared to $6.4 million in cash and cash equivalents and $39.5 million outstanding borrowings on our Senior Secured Credit Facility at June 30, 2024. Our primary sources of liquidity and capital resources during the year ended June 30, 2025 were cash provided by operations and net proceeds from the ATM Sales agreement. Our primary uses of liquidity and capital resources for the year ended June 30, 2025 were cash dividend payments to our common stockholders, our TexMex Acquisition, net repayments of borrowings under our Senior Secured Credit Facility and development capital expenditures, primarily at Chaveroo Field and SCOOP/STACK. As of June 30, 2025, working capital was a deficit of $4.0 million. As of June 30, 2024, working capital was $5.9 million.

As noted above, on June 30, 2025, we entered into a syndicated amended and restated senior secured reserve-based credit agreement (the “Senior Secured Credit Facility”) with MidFirst Bank, as administrative agent for the lenders party thereto. The Senior Secured Credit Facility has a maximum capacity of $200.0 million subject to a borrowing base determined by the lenders based on the value of our oil and natural gas properties. The Senior Secured Credit Facility has a current borrowing base of $65.0 million. As of June 30, 2025, we had $37.5 million of indebtedness outstanding and availability of $27.5 million. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on June 30, 2028.

Borrowings bear interest, at our option, at either (i) the SOFR, subject to a minimum SOFR of 3.25%, plus a credit spread adjustment of 0.05%, or (ii) the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%, plus, in either case of (i) or (ii), an applicable margin of 2.75%. For the years ended June 30, 2025 and 2024, the weighted average interest on our borrowings were 7.48% and 8.12%, respectively. The Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. In addition, the Senior Secured Credit Facility contains hedging requirements that apply when utilization is greater than 25% of (x) the Margined Collateral Value, as defined under the Senior Secured Credit Facility, at any time when the leverage ratio is less than 2.25 to 1.00, or (y) the borrowing base, at any time when the leverage ratio is greater than or equal to 2.25 to 1.00. It also contains other customary affirmative and negative covenants, and events of default. As of June 30, 2025, we were in compliance with all covenants under the Senior Secured Credit Facility.

The Senior Secured Credit Facility requires for redeterminations of the borrowing base to occur semi-annually. At each redetermination, the Margined Collateral Value is updated based on the estimated value of our oil and natural gas

Table of Contents

properties, which includes our proved developed reserves, proved undeveloped reserves, and other relevant factors consistent with customary oil and natural gas lending criteria. On August 29, 2025, we entered into an amendment to our Senior Secured Credit Facility with MidFirst Bank, whereas it was determined for purposes of the hedge covenant that total crude oil and natural gas volumes from proved developed producing reserves will be combined on a barrels of oil equivalent (“BOE”) basis to determine compliance with the hedging covenant.

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

We are pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, we have access to the undrawn portion of the borrowing base available under our Senior Secured Credit Facility, totaling $27.5 million as of June 30, 2025. As stated above in “Recent Developments,” on August 4, 2025, we purchased mineral and royalty interests in the SCOOP/STACK area of Oklahoma for approximately $17.0 million. We funded the acquisition with borrowings of $15.0 million on our Senior Secured Credit Facility and cash on hand. On August 5, 2025, we issued an $0.8 million letter of credit agreement to Enterprise Products Operating, LLC, in connection with our gathering and processing agreements at Jonah Field, in exchange for the return of our cash collateral that had been previously provided. This additional borrowing and letter of credit reduced our remaining availability to $11.7 million subsequent to our fiscal year end. We also have an effective shelf registration statement with the SEC under which we may issue up to $500.0 million of new debt or equity securities.

On October 21, 2024, we entered into an ATM Sales Agreement with Roth Capital Partners, LLC as our Lead Agent, Northland Securities Inc., and A.G.P./Alliance Global Partners pursuant to which we may issue and sell, from time to time, up to $30.0 million of shares of common stock through or to the Lead Agent, acting as agent or principal. For the year ended June 30, 2025, we sold a total of approximately 0.7 million shares of our common stock under the ATM Sales Agreement for net proceeds of approximately $3.5 million, after deducting $0.3 million in offering costs.

Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 47 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to increase dividends over time, as appropriate. On September 11, 2025, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on September 22, 2025 and payable on September 30, 2025.

On September 8, 2022, our Board of Directors approved a share repurchase program, under which we were authorized to repurchase up to $25.0 million of our common stock in the open market through December 31, 2024. As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors along with the management team believe that a share repurchase program may be complimentary to the existing dividend policy and could be a tax efficient means to further improve shareholder return. In fiscal year 2025, we did not repurchase any shares under the program. In fiscal year 2024, we entered into a Rule 10b5-1 plan that authorized a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan was effective until June 30, 2024 and had a maximum authorized amount of $0.8 million over that period. During the fiscal year ended June 30, 2024, approximately 0.1 million shares of the Company’s common stock were repurchased under the plan at a cost of approximately $0.8 million, including incremental direct transaction costs. We funded repurchases from working capital and cash provided by operating activities. These shares were subsequently cancelled. We may enter into additional share repurchase programs in the future as well as Rule 10b5-1 plans, the terms of which will be approved by the Board of Directors.

Table of Contents

Capital Expenditures

For the year ended June 30, 2025, we incurred $13.2 million on development capital expenditures. A majority of our spending occurred at the Chaveroo Field where we participated in drilling and completion of four gross wells, and at SCOOP/STACK where our operators have brought 13 gross (0.14 net) wells online during the fiscal year.

Based on discussions with our operators, we expect capital workover projects to continue in most of our fields. Overall, for fiscal year 2026, we expect budgeted capital expenditures to be in the range of $4.0 million to $6.0 million, which excludes any potential acquisitions. Our expected capital expenditures for the next 12 months include bringing approximately five gross wells online at our SCOOP/STACK properties. Additionally, as our third-party operators continue to be active around our acreage, we would expect additional wells to be drilled and/or completed. At Chaveroo Field, we expect to have drilling permits in hand for the next round of six wells before the end of the fiscal third quarter 2026 and the final decision by us and our partner as to timing for spudding these wells will be made based on oil prices and completed well costs at that time.

As of June 30, 2025, our PUD reserves included 4.4 MMBOE of reserves and approximately $75.1 million of future development costs primarily associated with the Chaveroo Field, Williston Basin, and SCOOP/STACK properties.

Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations and as needed from borrowings under our Senior Secured Credit Facility.

Full Cost Pool Ceiling Test

Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion, depreciation, and amortization and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test as of June 30, 2025 were $71.20 per barrel of oil, $2.87 per MMBtu of natural gas and $25.24 per barrel of NGLs. As of June 30, 2025, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling. If commodity price levels were to substantially decline from the 12-month average first day of the month pricing levels as of June 30, 2025 and remain down for a prolonged period of time, our valuation ceiling over our capitalized costs may be reduced and adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future. Additionally, a 10% reduction in respective commodity prices at June 30, 2025, while all other factors remained constant, would not have generated an impairment.

Overview of Cash Flow Activities

Years Ended June 30,

Cash flows provided by operating activities $ 33,052 $ 22,729 $ 10,323

Cash flows used in investing activities (21,642) (49,633) 27,991

Net decrease in cash and cash equivalents $ (3,939) $ (4,588) $ 649

Cash provided by operating activities increased $10.3 million during the fiscal year ended June 30, 2025 compared to fiscal year ended June 30, 2024 primarily due to changes in the timing of our working capital. Cash flows provided by operating activities before changes in working capital for the year ended June 30, 2025 decreased $1.8 million compared to the year ended June 30, 2024, primarily due to increases in our lease operating costs and interest expenses in the current year partially offset by realized gains on derivative contracts in the current year of $1.0 million compared to

Table of Contents

realized losses on derivative contracts in the prior year of $0.4 million. Refer to “Results of Operations” below for further information.

Cash used in investing activities for the year ended June 30, 2025 decreased $28.0 million from the prior year primarily due to the acquisition of our SCOOP/STACK properties in February 2024. In the prior year, net cash spent on acquisitions was $38.7 million, whereas in the current year, net cash spent on acquisitions was $9.0 million. In addition, in fiscal year 2025, we spent $12.6 million on development capital expenditures as compared to $10.9 million in the prior year. In the current fiscal year capital expenditures included drilling and completing four gross (2.0 net) Chaveroo wells and thirteen gross (0.14 net) SCOOP/STACK wells. In the prior year, the Company participated in drilling and completing three gross (1.5 net) Chaveroo wells and to a lesser extent, drilling and completion expenditures at Delhi Field and SCOOP/STACK.

Net cash flows used in financing activities for the year ended June 30, 2025 were $15.3 million compared to net cash flows provided by financing activities of $22.3 million for the year ended June 30, 2024. In the current year period, we paid $16.3 million in cash dividends to our common stockholders, repaid $2.0 million of net borrowings under our Senior Secured Credit Facility, and received net proceeds from the sale of common stock under the ATM Sales Agreement of approximately $3.5 million, after deducting $0.3 million in offering costs. In the prior year period, we received net borrowings of $39.5 million under our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions, paid $16.0 million in cash dividends to our common stockholders together with $0.8 million paid to repurchase shares of common stock under our share repurchase plan.

Table of Contents

Results of Operations

Years Ended June 30, 2025 and 2024

We reported a net income of $1.5 million and $4.1 million for the years ended June 30, 2025 and 2024, respectively. The following table summarizes the comparison of financial information for the periods presented:

Years Ended June 30,

Revenues:

Operating costs:

Lease operating costs:

Ad valorem and production taxes 5,709 5,285 424 8.0 %

Depletion, depreciation, and accretion:

Accretion of asset retirement obligations 1,619 1,457 162 11.1 %

General and administrative expenses:

Other income (expense):

Interest and other income 191 342 (151) (44.2) %

Income tax (expense) benefit (396) (1,417) 1,021 (72.1) %

Production:

Natural gas liquids (MBBL) 414 402 12 3.0 %

Average daily production (BOEPD)(1) 7,074 6,790 284 4.2 %

Average price per unit(2):

Natural Gas Liquids (BBL) 27.11 27.13 (0.02) (0.1) %

Average cost per unit:

Operating costs:

Lease operating costs:

Ad valorem and production taxes $ 2.21 $ 2.13 $ 0.08 3.8 %

Gathering, transportation, and other costs 4.40 3.89 0.51 13.1 %

Other lease operating costs 12.50 13.41 (0.91) (6.8) %

General and administrative expenses:

General and administrative 3.04 3.02 0.02 0.7 %

Table of Contents

Revenues

Crude oil, natural gas and NGL revenues were $85.8 million and $85.9 million for the fiscal years ended June 30, 2025 and 2024, respectively. The decrease in revenues is primarily due to the decrease in our average realized price per BOE partially offset by an increase in our sales volumes primarily as a result of our recent acquisitions. Our average realized commodity price (excluding the impact of derivative contracts) decreased approximately $1.31 per BOE, or 3.8%, for the fiscal year ended June 30, 2025 compared to June 30, 2024. The amount we realize for our production depends predominantly upon commodity prices, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, inventory storage levels, basis differentials and other factors. While crude oil and NGL prices decreased 11.5% and 0.1% from the prior fiscal year respectively, our average realized commodity prices, realized natural gas prices increased 7.3% from the prior fiscal year predominately due to favorable pricing recognized from our SCOOP/STACK properties. Average daily equivalent production increased 4.2% from 6,790 BOEPD to 7,074 BOEPD in the current fiscal year as a result of additional production from newly drilled wells at Chaveroo Field, the Tex Mex Acquisition in April 2025, and drilling activities that are ongoing at SCOOP/STACK since the prior year end. The increase in production was partially offset by natural production declines in our other fields.

Lease Operating Costs

Ad valorem and production taxes were $5.7 million and $5.3 million for the years ended June 30, 2025 and 2024, respectively. The increase in ad valorem and production taxes is primarily due to our SCOOP/STACK Acquisitions since the prior year period. On a per unit basis, ad valorem and production taxes were $2.21 per BOE and $2.13 per BOE for the years ended June 30, 2025 and 2024, respectively.

Gathering, transportation and other costs were $11.4 million for the year ended June 30, 2025 compared to $9.7 million for the year ended June 30, 2024. These costs are gathering, transportation and processing fees we incur primarily for our natural gas producing properties. The increase is primarily due to the SCOOP/STACK Acquisitions in February 2024 which increased gathering, transportation and other costs by $1.2 million over the prior year period. On a per unit basis, gathering, transportation and other costs were $4.40 per BOE and $3.89 per BOE for the years ended June 30, 2025 and 2024, respectively.

Other lease operating costs decreased $1.1 million, or 3.2%, compared to the prior fiscal year primarily due to a $1.9 million credit from the operator of one of our Barnett Shale properties due to a joint venture audit combined with the cessation of CO2 purchases at Delhi late in the third fiscal quarter. CO2 purchases resumed in late October of 2024 following the pipeline shutdown for maintenance and repairs early in 2024. Consequently, we had net purchases of $2.6 million of CO2 for the year ended June 30, 2025 compared to net purchases of $4.2 million in the prior year period. Partially offsetting the reduction in CO2 purchases were cost increases due to our acquisitions of TexMex in April 2025 and SCOOP/STACK in February 2024, which collectively increased other lease operating costs by $2.3 million over the prior year period. On a per unit basis, other lease operating costs decreased to $12.50 per BOE in the current year from $13.41 per BOE in the prior year, primarily due to an overall increase in production.

Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $1.8 million or 9.5% from $18.6 million for the fiscal year ended June 30, 2024 to $20.4 million for the fiscal year ended June 30, 2025 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $7.89 per BOE and $7.49 per BOE for the fiscal years ended June 30, 2025 and 2024, respectively.The depletion rate of our unit of production calculation increased primarily due to an overall decrease in our reserves estimates since the prior year period.

General and Administrative Expenses

General and administrative expenses for the fiscal year ended June 30, 2025 increased $0.4 million, or 4.7%, to $7.9 million compared to $7.5 million for the fiscal year ended June 30, 2024. The increase primarily relates higher salary and compensation expense adjustments for existing employees. On a per unit basis, general and administrative expenses were $3.04 per BOE and $3.02 per BOE for the years ended June 30, 2025 and 2024, respectively.

Table of Contents

Stock-based Compensation Expenses

Stock-based compensation increased $0.3 million to $2.5 million for the year ended June 30, 2025 compared to $2.1 million the prior period. The increase is due to new awards granted during the current year.

Net Gain (Loss) on Derivative Contracts

We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. Financial hedges are a requirement under our Senior Secured Credit Facility and help establish commodity price floors, contributing to stable cash flows when derivative contracts are settled. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the consolidated statements of operations. The amounts recorded on the consolidated statements of operations related to derivative contracts represent the (i) gains (losses) related to fair value adjustments on our open, or unrealized, derivative contracts, and (ii) gains (losses) on settlements of derivative contracts for positions that have settled or been realized. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average realized prices for the periods presented. As a result of our SCOOP/STACK Acquisitions in February 2024 and the corresponding borrowings on our Senior Secured Credit Facility, we were required by terms in our Senior Secured Credit Facility to hedge a portion of our production. The increase in the forward curve for future natural gas prices, as of June 30, 2025 as compared to June 30, 2024, resulted in a net unrealized loss on the mark-to-market of our hedges for the year ended June 30, 2025. As of June 30, 2025, we had a $2.0 million derivative asset, $1.8 million of which was classified as current, and a $3.4 million derivative liability, $1.6 million of which was classified as current.

Years Ended June 30,

Average realized natural gas price per MCF $ 2.80 $ 2.61 $ 0.19 7.3 %

Interest Expense

Interest expense increased $1.5 million during the fiscal year ended June 30, 2025 compared to fiscal year 2024 primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions in February 2024. Partially offsetting the increase in interest expense is the decrease in our weighted average interest rate on our borrowings to 7.48% for the fiscal year ended June 30, 2025 compared to 8.12% for fiscal year 2024.

Income tax (expense) provision

For the year ended June 30, 2025, we recognized income tax expense of $0.4 million on income before income taxes of $1.9 million compared to an income tax expense of $1.4 million on income before income taxes of $5.5 million for the year ended June 30, 2024. The effective tax rates were 21.2% and 25.8% for the years ended June 30, 2025 and 2024, respectively. The decrease in the effective tax rate from the prior year period is due to federal tax credits on marginal natural gas wells for the calendar year 2024 and 2025.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance

Table of Contents

sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our consolidated financial statements. Our significant accounting policies are included in Note 1, “Summary of Significant Events and Accounting Policies” to our consolidated statements in Item 8. Following is a discussion of our most critical accounting estimates, judgments, and uncertainties that are inherent in the preparation of our consolidated financial statements.

Oil and Natural Gas Properties. Companies engaged in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and natural gas industry. We apply the full cost accounting method for our oil and natural gas properties as prescribed by SEC Regulation S-X Rule 4-10. Under this method of accounting, the costs of unsuccessful and successful, exploration and development activities are capitalized as properties and equipment. 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. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties. We exclude these costs until the property has been evaluated. Costs are transferred to the full cost pool as the properties are evaluated. As of June 30, 2025 and 2024, we had no unevaluated property costs. 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.

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 our 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 our financial statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect our estimated future net cash flows of our proved reserves. These changes could affect our quarterly ceiling test calculation and could significantly affect our depletion rate. Additionally, a 10% decrease in commodity prices used to determine our proved reserves as of June 30, 2025, while all other factors remained constant, would not have resulted in an impairment of our oil and natural gas properties. Holding all other factors constant, a reduction in our proved reserve estimates at June 30, 2025 of 10% would affect depletion, depreciation, and amortization expense by approximately $0.6 million.

On December 31, 2008, the SEC issued its final rule on the modernization of reporting oil and natural gas reserves. The rule allows consideration of new technologies in evaluating reserves, generally limits the designation of proved reserves to those projects forecasted to be drilled five years from the initial recognition date of such reserves, allows companies to disclose their probable and possible reserves to investors, requires reporting of oil and natural gas reserves using an average price based on the previous 12-month unweighted arithmetic average first-day-of-the-month price rather than year-end prices, revises the disclosure requirements for oil and natural gas operations, and revises accounting for the limitation on capitalized costs for full cost companies.

Stock-based Compensation. The fair value, and for certain awards the expected vesting period, of our performance-based awards were determined using a Monte Carlo simulation. This technique uses a geometric Brownian motion model with defined variables and randomly generates values for each variable through multiple trials. Variables include stock price volatility, expected term of the award, the expected risk-free interest rate, and the expected dividend yield of our stock. The risk-free interest rate used is the U.S. Treasury yield for bonds matching the expected term of the award on the date of grant. Vesting of performance-based awards is based on our total common stock return compared to a peer

Table of Contents

group of other companies in our industry with comparable market capitalizations and, for certain awards, our share price attaining a set target.

Recent Accounting Pronouncements. Refer to Note 1, “Summary of Significant Events and Accounting Policies” to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data for discussion of the recent accounting pronouncements issued by the Financial Accounting Standards Board.

Item 7A. Quantitative and Qualitative Disclosures About Market Risks

Derivative Instruments and Hedging Activity

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

We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competitive market makers. For the derivative contracts settled during fiscal 2025 and 2024, we did not post collateral. We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, (“ASC 815”). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivatives” to our consolidated financial statements for more details.

Interest Rate Risk

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

Table of Contents

Item 8. Consolidated Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm (PCAOB ID No. 23) 44

Consolidated Balance Sheets as of June 30, 2025 and 2024 46

Notes to Consolidated Financial Statements 50

Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) 71

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Evolution Petroleum Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Evolution Petroleum Corporation and subsidiaries (the “Company”) as of June 30, 2025 and 2024, the related consolidated statements of operations, cash flows, and changes in stockholders’ equity for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of June 30, 2025 and 2024, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of Proved Oil and Natural Gas Reserves on Depletion, Depreciation, and Amortization (“DD&A”) and Full Cost Ceiling Test Impairment Calculation (“Ceiling Test”)

As described in Note 1, the Company follows the full cost method of accounting, pursuant to which oil and natural gas properties are amortized using the unit-of-production method over total proved reserves. The Company’s proved oil and natural gas properties are evaluated for impairment by the Ceiling Test utilizing the Company’s proved oil and natural gas reserves in accordance with accounting principles generally accepted in the United States of America and SEC guidelines. For the year ended June 30, 2025, the Company recorded DD&A related to its proved oil and natural gas properties of approximately $20.4 million, and there was no ceiling test impairment.

The Company engages two independent reservoir engineering firms to serve as a management specialist and to assist with the estimation of proved oil and natural gas reserves. To estimate the volume of proved oil and natural gas reserves

Table of Contents

and associated future net cash flows, management and their specialists make significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties (“PUDs”). The estimation of proved oil and natural gas reserves is impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required. Changes in significant assumptions or engineering data could have a significant impact on the amount of DD&A and impairment recorded for the Company’s proved oil and natural gas properties.

We identified the impact of proved oil and natural gas reserves on DD&A and the Ceiling Test as a critical audit matter due to use of significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the significant assumptions used in developing those estimates of proved oil and natural gas reserves.

The primary procedures we performed to address this critical audit matter included:

o Testing the data inputs used by specialists for completeness and accuracy;

o Testing the specialists’ findings for mathematical accuracy; and

◾ prices to historical benchmark prices, adjusted for pricing differentials,

◾ production forecasts to recent historical actual production,

/s/ Baker Tilly US, LLP

Houston, Texas

We have served as the Company’s auditor since 2017.

Table of Contents

EVOLUTION PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

Assets

Current assets

Cash and cash equivalents $ 2,507 $ 6,446

Derivative contract assets 1,777 596

Prepaid expenses and other current assets 2,287 3,855

Property and equipment, net of depletion, depreciation, and impairment

Other noncurrent assets

Derivative contract assets 198 171

Liabilities and Stockholders' Equity

Current liabilities

Accrued liabilities and other 6,909 6,239

Derivative contract liabilities 1,577 1,192

State and federal taxes payable — 74

Long term liabilities

Senior secured credit facility 37,500 39,500

Deferred income taxes 6,234 6,702

Derivative contract liabilities 1,783 468

Operating lease liability — 58

Commitments and contingencies (Note 10)

Stockholders' equity

Total liabilities and stockholders' equity $ 160,252 $ 162,877

See accompanying notes to consolidated financial statements.

Table of Contents

EVOLUTION PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

Years Ended June 30,

Revenues

Operating costs

Depletion, depreciation, and accretion 21,993 20,062

General and administrative expenses 10,334 9,636

Income (loss) from operations 4,175 7,906

Other income (expense)

Net gain (loss) on derivative contracts 473 (1,292)

Interest and other income 191 342

Income (loss) before income taxes 1,869 5,497

Income tax (expense) benefit (396) (1,417)

Net income (loss) per common share:

Weighted average number of common shares outstanding:

See accompanying notes to consolidated financial statements.

Table of Contents

EVOLUTION PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

Years Ended June 30,

Cash flows from operating activities:

Depletion, depreciation, and accretion 21,993 20,062

Stock-based compensation 2,482 2,137

Settlement of asset retirement obligations (385) (20)

Deferred income taxes (468) (101)

Unrealized (gain) loss on derivative contracts 492 893

Accrued settlements on derivative contracts (251) 67

Other (8) —

Changes in operating assets and liabilities:

Prepaid expenses and other current assets 2,925 (1,562)

Accounts payable and accrued liabilities and other 4,798 374

State and federal taxes payable (74) (291)

Net cash provided by operating activities 33,052 22,729

Cash flows from investing activities:

Acquisition of oil and natural gas properties (9,019) (38,734)

Net cash used in investing activities (21,642) (49,633)

Cash flows from financing activities:

Common stock dividends paid (16,347) (16,040)

Borrowings under senior secured credit facility 2,000 42,500

Repayments of senior secured credit facility (4,000) (3,000)

Debt issuance costs (90) —

Issuance of common stock 3,840 —

Offering costs (310) —

Net cash provided by (used in) financing activities (15,349) 22,316

Net increase (decrease) in cash and cash equivalents (3,939) (4,588)

Cash and cash equivalents, beginning of period 6,446 11,034

Cash and cash equivalents, end of period $ 2,507 $ 6,446

Supplemental disclosures of cash flow information:

Cash paid for interest on senior secured credit facility $ 3,082 $ 1,331

Cash paid for income taxes 874 2,804

Cash refunded from income taxes 1,000 —

Non-cash investing and financing transactions:

Accrued debt issuance costs 275 —

Accrued offering costs 10 —

See accompanying notes to consolidated financial statements.

Table of Contents

EVOLUTION PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands)

Additional Total

Common Stock Paid-in Retained Treasury Stockholders'

Shares Par Value Capital Earnings Stock Equity

Issuance of restricted common stock 294 — — — — —

Retirements of treasury stock (202) — (1,144) — 1,144 —

Stock-based compensation — — 2,137 — — 2,137

Net income (loss) — — — 4,080 — 4,080

Common stock dividends paid — — — (16,040) — (16,040)

Issuance of restricted common stock 376 — — — — —

Forfeitures of restricted stock (8) — — — — —

Retirements of treasury stock (89) — (442) — 442 —

Issuance of common stock 718 1 3,839 — — 3,840

Offering costs — — (320) (320)

Stock-based compensation — — 2,482 — — 2,482

Net income (loss) — — — 1,473 — 1,473

Common stock dividends paid — — — (16,347) — (16,347)

See accompanying notes to consolidated financial statements.

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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 is proactive with its third-party operators to review the management of capital expenditures.

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 expenses and accounts payable.

Segment Information. The Company has one reportable segment, which focuses on the ownership of and investment in onshore oil and natural gas properties in the United States. The segment’s revenues are derived from the Company’s interests in the sales of crude oil, natural gas, and NGL production to customers in the United States. The Company evaluates performance based on various financial metrics, including but not limited to consolidated income or loss from

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

operations, net revenue, and cash flow from operations. The Company’s chief executive officer, chief operating officer, and chief financial officer together function as the chief operating decision maker (“CODM”). The CODM manages the Company’s business activities as a single operating segment.

The accounting policies of the one reportable segment are identical to accounting policies described for the consolidated Company. The CODM uses income (loss), as reported in the 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, 2025 and 2024, 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, 2025 and 2024, 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 to seven years. The assets are depreciated using the straight-line method. Realization of the carrying value of other property and

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2025 and 2024 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 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, 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. In the year ended June 30, 2024, four individual operators, Denbury, Diversified, Foundation, and Merit, each accounted for more than 10% of the Company’s total revenues, collectively representing approximately 69% 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

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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,

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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. The Company is currently evaluating ASU 2023-09 and the impact it may have to the Company’s financial position, results of operations, cash flow or disclosures.

In November 2023 the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”). ASU 2023-07 expands the segment disclosures, even for entities with only one reportable segment, to include additional information about significant segment expenses and other segment items on an annual and interim basis as well as the title and position of the chief operating decision maker. ASU 2023-07 is effective for annual periods beginning after December 15, 2023 and interim periods withing fiscal years beginning after December 15, 2024. Early adoption is permitted and entities must adopt the amendment retrospectively for all prior periods presented in the financial statements. The Company adopted ASU 2023-07 as of June 30, 2025 with no significant impact to the Company’s financial position, results of operations, cash flow or disclosures.

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

Note 2. Revenue Recognition

The Company’s revenues are primarily generated from its crude oil, natural gas and NGL production from the 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 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 years ended June 30, 2025 and 2024 (in thousands):

Years Ended June 30,

Revenues

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

Judgments made in applying the guidance in ASC 606, Revenue from Contracts with Customers, relate primarily to determining the point in time when control of product 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 control of produced hydrocarbons transferring to a customer at a specified delivery point. Consideration is allocated to completed performance obligations at the end of an accounting period.

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

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.

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The TexMex Acquisition includes an average working interest of 42% and an average revenue interest of 35% in approximately 600 wells.

SCOOP/STACK Acquisitions

On February 12, 2024, the Company closed the acquisitions of certain non-operated oil and natural gas assets in the SCOOP and STACK plays in central Oklahoma (the “SCOOP/STACK Acquisitions”) from Red Sky Resources III, LLC, Red Sky Resources IV, LLC, and Coriolis Energy Partners I, LLC. After including customary closing adjustments and an effective date of November 1, 2023, total combined cash consideration for the SCOOP/STACK Acquisitions was approximately $39.1 million, which includes $43.9 million paid at closing less purchase price adjustments totaling approximately $4.8 million related to net cash flows received on the properties subsequent to closing. The Company accounted for these transactions as asset acquisitions and allocated the combined purchase price (including $0.3 million of transaction costs) to proved oil and natural gas properties. In addition, the Company recognized $0.1 million in non-cash asset retirement obligations, the estimated net present value of future net retirement costs. The transactions were funded with cash on hand and $42.5 million in borrowings under the Company’s Senior Secured Credit Facility.

The acquired assets consist of an average net working interest of approximately 2.6%, in 266 producing wells in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma.

Chaveroo Field Participation Agreement

On September 12, 2023, the Company entered into a Participation Agreement with PEDEVCO for the joint development of a portion of PEDEVCO’s Permian Basin property in the Chaveroo Field, located in Chaves and Roosevelt Counties, New Mexico. In accordance with the Participation Agreement, the Company has the right, but not the obligation, to elect to participate and acquire a 50% working interest share in certain development blocks at a fixed price of $450 per net acre for up to a total of approximately 16,000 gross acres. The Participation Agreement does not include any of PEDEVCO’s existing vertical or horizontal wells.

As of June 30, 2025, the Company has incurred approximately $1.1 million in exchange for a 50% working interest share in the existing leases associated with six development blocks. In fiscal year 2024, the Company participated in the drilling and completion of the first development block, consisting of three gross wells (1.5 net wells). During the year ended June 30, 2025, the Company participated in the drilling and completion of the second development block, consisting of four gross wells (2.0 net wells) which came online during the fourth fiscal quarter.

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, with no 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.

Purchase of SCOOP/STACK Minerals

Subsequent to fiscal year-end, in August 2025, the Company closed on an acquisition of certain mineral and royalty interests in the SCOOP/STACK area of Oklahoma. See Note 14, “Subsequent Events,” for further details.

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 4. Property and Equipment

Property and equipment as of June 30, 2025 and 2024 consisted of the following (in thousands):

Oil and natural gas properties

Property costs subject to amortization $ 272,496 $ 249,559

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 unevaluated 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, 2025 and 2024, all oil and natural gas property costs were subject to amortization. Depletion on oil and natural gas properties was $20.4 million and $18.6 million for the years ended June 30, 2025 and 2024, respectively. During the years ended June 30, 2025 and 2024, the Company incurred development capital expenditures of $13.2 million and $12.3 million, respectively.

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 West Texas Intermediate (“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 prices received 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 and, as a result, no write-down was applicable.

At June 30, 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 June 30, 2024 of the WTI crude oil spot price of $79.45 per barrel and Henry Hub natural gas spot price of $2.32 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $23.86, which was based on historical prices received as NGLs do not have any single comparable reference index price. Using these prices, at June 30, 2024 the cost center ceiling was higher than the capitalized costs of oil and natural gas properties 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

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The Senior Secured Credit Facility carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Senior Secured Credit Facility will bear interest, at the Company’s option, at either (i) the Secured Overnight Financing Rate (“SOFR”), subject to a minimum SOFR of 3.25%, plus a credit spread adjustment of 0.05%, or (ii) the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%, plus, in either case of (i) or (ii), an applicable margin of 2.75%.

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

The Senior Secured Credit Facility contains certain events of default, including non-payment; breaches of representation and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary 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, 2025, the Company had $37.5 million in borrowings outstanding under its Senior Secured Credit Facility, resulting in $27.5 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 7.48% and 8.12%, respectively. As of June 30, 2025, the Company was in compliance with all covenants under the Senior Secured Credit Facility.

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.

On August 29, 2025, the Company entered into an amendment of its Senior Secured Credit Facility with MidFirst Bank, whereas 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.

The Company capitalizes certain direct costs associated with the its Senior Secured Credit Facility and amortizes these costs over the life of the facility. For the year ended June 30, 2025, the Company capitalized $0.4 million of debt issuance costs in conjunction with amending and restating the Senior Secured Credit Facility. The debt issuance costs were presented in "Other Assets" on the consolidated balance sheet at June 30, 2025.

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.

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

There were no unrecognized tax benefits, nor any accrued interest or penalties associated with unrecognized tax benefits during the years ended June 30, 2025 and 2024. 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.

Income tax (expense) benefit for the years ended June 30, 2025 and 2024 is comprised of the following (in thousands):

Current:

Total current income tax (expense) benefit (864) (1,518)

Deferred:

Total deferred income tax (expense) benefit 468 101

Total income tax (expense) benefit $ (396) $ (1,417)

For the year ended June 30, 2025 the Company recognized income tax expense of $0.4 million and had an effective tax rate of 21.2% compared to income tax expense of $1.4 million and an effective tax rate of 25.8% for the year ended June 30, 2024. During each of the years ended June 30, 2025 and 2024, the Company recognized an income tax benefit of $0.1 million and less than $0.1 million, respectively, related to the vesting of restricted stock awards.

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 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):

% of Income % of Income

Before Before

Reconciling items:

Return to provision adjustments (2) 0.1 % 3 (0.1) %

Depletion in excess of tax basis 59 (3.2) % 114 (2.1) %

State valuation allowance 140 (7.5) % — — %

Marginal well credit 408 (21.8) % — — %

Other (3) 0.2 % (2) 0.1 %

Income tax (expense) benefit $ (396) 21.2 % $ (1,417) 25.8 %

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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):

Deferred tax assets:

Non-qualified stock-based compensation $ 599 $ 381

Net operating loss carry-forwards and other carry-forwards 148 313

Derivative losses 298 192

Asset retirement obligations 4,982 4,427

Other deferred tax assets 481 197

Total deferred tax assets 6,508 5,510

Deferred tax liabilities:

Oil and natural gas properties (12,742) (12,072)

Total deferred tax liabilities (12,742) (12,072)

Valuation allowance — (140)

Net deferred tax liabilities $ (6,234) $ (6,702)

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.

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, including 100% bonus depreciation, domestic research cost expensing, and the business interest expense limitation. As the legislation was signed into law after the close of the fiscal year end, the impacts are not included in the Company’s operating results as of and for the year-end June 30, 2025 as ASC 740, “Income Taxes”, requires the effects of changes in tax rates and laws on deferred tax balances to be recognized in the period in which the legislation is enacted. The Company is currently assessing the impact of the OBBBA on its consolidated financial statements, and while it does not expect it to have a material impact on its results of operations, it does expect it to provide a benefit to its cash flows from operating activities.

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, 2025, the Company did not post collateral under any of its derivative contracts during the periods in which contracts were open as they were secured under the Company’s Senior Secured Credit Facility.

When the Company utilizes commodity derivative contracts, it expects to enter into deferred premium puts, costless put/call collars including two-way and three-way collars, fixed-price swaps, and/or basis swaps to hedge a portion of its anticipated future production. A two-way costless collar consists of a sold call, which establishes a maximum price the

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2024 (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, 2025 and 2024 (in thousands):

Derivatives not designated

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, 2025 and 2024 (in thousands). “Realized gain (loss) on derivative contracts” represents all receipts (payments) on derivative contracts settled during the period. “Unrealized gain (loss) on derivative contracts” represents the net change in the mark-to-market valuation of the derivative contracts.

Derivatives not designated Location of gain (loss)

as hedging contracts recognized in income on Years Ended June 30,

Commodity contracts:

Total net gain (loss) on derivative contracts $ 473 $ (1,292)

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of June 30, 2025, the Company had the following open crude oil and natural gas derivative contracts:

Volumes in Swap Price per Floor Price per Ceiling Price per

Period Commodity Instrument MMBTU/BBL MMBTU/BBL MMBTU/BBL MMBTU/BBL

Subsequent to June 30, 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 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, 2025 and 2024 (in thousands):

Derivative Contract Assets Derivative Contract Liabilities

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.

Table of Contents

EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2025 and 2024 (in thousands).

Level 1 Level 2 Level 3 Total

Assets

Derivative contract assets $ — $ 1,975 $ — $ 1,975

Liabilities

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

Level 1 Level 2 Level 3 Total

Assets

Derivative contract assets $ — $ 767 $ — $ 767

Liabilities

Derivative contract liabilities $ — $ 1,660 $ — $ 1,660

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”

Table of Contents

EPM US Equity

EPM · 10-K · period ended 2025-06-30

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 7A. Quantitative and Qualitative Disclosures About Market Risks

Item 8. Consolidated Financial Statements and Supplementary Data

EPM US Equity☆

EPM · 10-K · period ended 2025-06-30

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 7A. Quantitative and Qualitative Disclosures About Market Risks

Item 8. Consolidated Financial Statements and Supplementary Data

EPM US Equity