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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 of non-operated interests in the SCOOP and STACK plays of the Anadarko Basin located in central Oklahoma; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; 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; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana; and small overriding royalty interests in four onshore central Texas wells.

Our non-operated interests in the SCOOP and STACK plays, consist of oil and natural gas producing properties in the Anadarko basin, where we hold approximately 2.6% average net working interest and approximately 2.0% average net revenue interests located on approximately 4,200 net acres (approximately 96% held by production) across Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties in Oklahoma. The oil and natural gas properties are operated by Continental Resources, Inc., Ovintiv USA Inc. and EOG Resources, Inc. with approximately 40% of wells operated by other operators.

Our non-operated interests in the Chaveroo oilfield consist of a 50% net working interest, with an average associated 41% revenue interest, in approximately 1,600 net acres all held by production, associated with five development blocks, with the right to acquire the same working interest in additional development locations and associated acreage at a fixed price. The field is operated by PEDEVCO Corp. (“PEDEVCO”). See “Chaveroo Oilfield Participation Agreement” below for further information.

Our non-operated interests in the Jonah Field, a natural gas and NGL property in Sublette County, Wyoming, consist of approximately 20% average net working interest and approximately 15% average net revenue interest located on approximately 950 net acres all held by production. The properties are operated by Jonah Energy.

Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of approximately 39% average net working interest and approximately 33% average net revenue interest located on approximately 43,000 net acres (approximately 93% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy Management.

Our non-operated interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately 17% average net working interest and approximately 14% average net revenue interest (inclusive of small overriding royalty interests). The approximately 21,000 net acres are held by production across nine North Texas counties. The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other operators.

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Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consist of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest). The unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company, who owns the majority of the remaining working interest in the Hamilton Dome Field. The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming.

Our non-operated interests in the Delhi Field, a CO2-EOR project, consist of approximately 24% average net working interest, with an associated 19% revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC. The unitized Delhi Field, of which we hold approximately 3,200 acres, is located in northeast Louisiana in Franklin, Madison, and Richland Parishes.

Recent Developments

Dividend Declaration

On September 9, 2024, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2024.

SCOOP/STACK Acquisitions

On February 12, 2024, we 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 taking into account customary closing adjustments and an effective date of November 1, 2023, total combined cash consideration for the SCOOP/STACK Acquisitions was approximately $39.2 million, which includes $43.9 million paid at closing less purchase price adjustments totaling approximately $4.7 million related to net cash flows earned on the properties from the effective date to the closing date.

The acquired assets consist of an average net working interest of approximately 2.6% in 253 producing wells in the SCOOP and STACK plays of the Anadarko Basin in Blaine, Canadian, Carter, Custer, Dewey, Garvin, Grady, Kingfisher, McClain, Murray, and Stephens counties, Oklahoma. The acquisitions also include approximately 4,200 net acres (approximately 96% held by production) with approximately 300 associated potential drilling opportunities.

Senior Secured Credit Facility

On February 12, 2024, we entered into an amendment to the Senior Secured Credit Facility. This amendment required that we enter into hedges for the next 12-month period, and on a rolling 12-month basis thereafter, covering expected crude oil and natural gas production from proved developed reserves, calculated separately, equal to a minimum of 40% of expected crude oil production each month, or 25% of expected crude oil and natural gas production each month over that period. We have the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.

Appointment of Chief Accounting Officer

On December 18, 2023, we announced that the Board of Directors approved the appointment of Kelly M. Beatty as Chief Accounting Officer, effective January 1, 2024. Ms. Beatty has been serving as Principal Accounting Officer since December 2022 and has served as the Company’s Controller since February 2022.

Share Repurchase Program

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maximum authorized amount of $0.8 million over that period. During the fiscal year ended June 30, 2024, 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. These shares were subsequently cancelled. We may enter into additional Rule 10b5-1 plans in the future, the terms of which will be approved by the Board of Directors.

Chaveroo Oilfield Participation Agreement

On September 12, 2023, we entered into a participation agreement (the “Participation Agreement”) with PEDEVCO for the joint development of the Chaveroo oilfield, a conventional oil-bearing San Andres field located in Chaves and Roosevelt Counties, New Mexico (the “Chaveroo Field”).

Pursuant to the Participation Agreement, we have the right, but not the obligation, to elect to participate in drilling locations on approximately 16,000 gross leasehold acres consisting of all leasehold rights from surface to the base of the San Andres formation, where PEDEVCO currently holds leasehold interest. We have agreed to pay PEDEVCO $450 per acre to acquire a 50% working interest share in the leases associated with the locations that we choose to participate in. The Participation Agreement initially includes up to 80 gross drilling locations across twelve development blocks. We have entered into a standard operating agreement with PEDEVCO serving as the operator with respect to the development of the properties. The Participation Agreement includes customary representations and warranties of the parties and other terms and conditions that are standard in such participation agreements.

As of June 30, 2024, we have incurred approximately $0.8 million in exchange for a 50% working interest share in approximately 1,600 net acres, associated with five development blocks. As of June 30, 2024, we have participated in the drilling and completion of the first development block which consisted of three gross (1.5 net) wells. Refer to Capital Expenditures below for a further discussion of Chaveroo drilling and completion activities since entering into the Participation Agreement.

Proved Reserves

The following table is a summary of our proved reserves as of June 30, 2024 and 2023:

Proved Reserves

Proved Reserves MMBOE 31.8 31.2 1.9 %

Standardized Measure ($MM) $ 166.6 $ 238.2 (30.1) %

Proved oil equivalent reserves as of June 30, 2024 were 31.8 MMBOE, a 0.6 MMBOE, or 1.9%, increase from the previous year of 31.2 MMBOE. The net increase in total proved reserves was primarily due extensions of 4.8 MMBOE primarily in Chaveroo Field and SCOOP/STACK as well as 3.2 MMBOE of reserves purchased in our SCOOP/STACK acquisition. These increases are partially offset by production of 2.5 MMBOE and net negative revisions of 4.9 MMBOE. Net negative revisions of 4.9 MMBOE are primarily due to declines in SEC trailing 12-month pricing, especially for natural gas reserves where the price per MMBTU declined 51.5% from the prior year, as well as impacting the late-in-life economic limits of production.

The Standardized Measure for proved reserves decreased 30.1% to $166.6 million, primarily due to decreases in the SEC mandated trailing 12-month average first day of the month prices for oil and natural gas and the price received for our NGLs; sales of oil, natural gas and NGLs produced during the period; and decreases in reserves estimates partially offset by extensions in Chaveroo Field and SCOOP/STACK and our SCOOP/STACK Acquisition. Prices decreased from $83.23 per barrel of oil, $4.78 per MMBtu of natural gas and $33.71 per barrel of NGLs at June 30, 2023 to $79.45 per barrel of oil, $2.32 per MMBtu of natural gas and $23.86 per barrel of NGLs at June 30, 2024. Our proved reserves consist of 37% oil, 41% natural gas, and 22% NGLs; 75.6% are classified as proved developed producing and 24.4% are proved undeveloped.

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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, 99.2, and 99.3 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 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 and natural gas prices have been, and we expect may continue to be, volatile. Lower oil and gas prices not only decrease our revenues, but an extended decline in oil or gas prices may affect planned capital expenditures and the oil and natural gas reserves that we can economically produce. Lower oil and 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.

The Federal Reserve has taken actions to raise interest rates in an attempt to tame inflation and slow the economy, which has contributed to volatility in markets.

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist; predict the broader impact of liquidity concerns around financial institutions; the impact to long-term cost of capital or economic growth as a result of the Federal Reserve’s policies; or the impact on the commodity prices that we realize.

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 capital expenditures and present alternative plans as necessary.

Liquidity and Capital Resources

As of June 30, 2024, we had $6.4 million in cash and cash equivalents and $39.5 million outstanding borrowings on our Senior Secured Credit Facility compared to $11.0 million in cash and cash equivalents and no borrowings outstanding on our Senior Secured Credit Facility at June 30, 2023. Our primary sources of liquidity and capital resources during the year ended June 30, 2024 were cash provided by operations as well as net borrowings under our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the year ended June 30, 2024 were our SCOOP/STACK Acquisition, cash dividend payments to our common stockholders, and development capital expenditures, primarily at Chaveroo oilfield where we participated in the drilling of three gross (1.5 net) wells. As of June 30, 2024, working capital was $5.9 million, a decrease of $3.0 million from working capital of $8.9 million as of June 30, 2023.

The Senior Secured Credit Facility has a maximum capacity of $50.0 million subject to a borrowing base determined by the lender based on the value of our oil and natural gas properties. The Senior Secured Credit Facility has a current borrowing base of $50.0 million, with $39.5 million drawn as of June 30, 2024. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on April 9, 2026.

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Borrowings bear interest, at our option, at either the SOFR plus 2.80% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. For the years ended June 30, 2024 and 2023, the weighted average interest on our borrowings was 8.12% and 5.25%, 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. It also contains other customary affirmative and negative covenants, including a hedging covenant discussed below, and events of default. As of June 30, 2024, we were in compliance with all covenants under the Senior Secured Credit Facility.

On May 5, 2023, we entered into the Tenth Amendment to the Senior Secured Credit Facility. This amendment, among other things, extended the maturity of our Senior Secured Credit Facility to April 9, 2026, converted our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%, and modified the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million. We are required to enter into hedges on a rolling 12-month basis when the borrowings under the Senior Secured Credit Facility exceed 25% of the Margined Collateral Value. The required amount of hedged oil and natural gas production is related to the amount of borrowings outstanding. At each redetermination, our Margined Collateral Value takes into account the estimated value of our oil and natural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria.

On February 7, 2022, we entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as amended above, to the extent it exceeds the borrowing base then in effect. This amendment also required us to enter into hedges for the 12-month period ending February 2023, covering 25% of expected oil and natural gas production over that period.

On November 9, 2021, we entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby we must hedge a certain amount of our future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in subsequent amendments, as discussed above.

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, existing working capital and, as needed, borrowings under our Senior Secured Credit Facility.

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 $10.5 million as of June 30, 2024. 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.

Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 43 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 9, 2024, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on September 20, 2024 and payable on September 30, 2024.

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On September 8, 2022, our Board of Directors approved a share repurchase program, under which we are authorized to repurchase up to $25.0 million of our common stock in the open market through December 31, 2024. We intend to fund any repurchases from working capital and cash provided by operating activities. 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 is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return.

In December 2022, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan included a 30-day cooling off period that did not allow repurchases to commence until January 2023. The plan was effective until June 30, 2023 and had a maximum authorized amount of $5.0 million over that period. During the year ended June 30, 2023, 0.6 million shares of our common stock were repurchased under the plan at a total cost of approximately $3.9 million, including incremental direct transaction costs. These treasury shares were subsequently cancelled.

In November 2023, 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, 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. These shares were subsequently cancelled. We may enter into additional Rule 10b5-1 plans in the future, the terms of which will be approved by the Board of Directors.

Capital Expenditures

For the year ended June 30, 2024, we incurred $12.3 million on development capital expenditures across our portfolio of assets, excluding acquisitions. At the Chaveroo Field, we purchased undeveloped acreage and also participated in drilling and completion of three gross (1.5 net) wells. First production on the three gross wells at Chaveroo Field occurred at the beginning of February 2024. We also participated in the drilling and completion of two new wells in the Delhi Field that came online during the first fiscal quarter of 2024. Since acquiring our SCOOP/STACK properties, we have participated in the drilling and completion of 14 gross wells.

Based on discussions with our operators, we expect capital workover projects to continue in all the fields. Overall, for fiscal year 2025, we expect budgeted capital expenditures to be in the range of $12.5 million to $14.5 million, which excludes any potential acquisitions. Our expected capital expenditures for the next 12 months include bringing approximately 13 gross wells online at our SCOOP/STACK properties, the drilling and completion of four new wells at Chaveroo Field, and the drilling and completion of one new well at Delhi Field Test Site V.

As of June 30, 2024, our PUD reserves included 7.7 MMBOE of reserves and approximately $90.5 million of future development costs primarily associated with the SCOOP/STACK, Chaveroo Field, and Williston Basin properties, and Test Site V at Delhi Field.

Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations and current working capital, 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, 2024 were $79.45 per barrel of oil, $2.32 per MMBtu of natural gas and $23.86 per barrel of NGLs. As of June 30, 2024, our capitalized costs of oil and natural gas properties were below the full cost valuation

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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, 2024 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, 2024, 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 $ 22,729 $ 51,272 $ (28,543)

Cash flows used in investing activities (49,633) (6,992) (42,641)

Cash provided by operating activities decreased $28.5 million during the fiscal year ended June 30, 2024 compared to fiscal year ended June 30, 2023 primarily due to a decrease in revenue. Total revenues decreased $42.6 million as compared to the prior year primarily due to lower commodity prices coupled with lower sales volumes. Our average realized price per barrel of oil equivalent (“BOE”) decreased $15.00, or 30.3% from the prior year period. Refer to “Results of Operations” below for further information.

Cash used in investing activities for the year ended June 30, 2023 increased $42.6 million from the prior year primarily due to the acquisition of our SCOOP/STACK properties in February 2024 together with an increase in capital expenditures related to the drilling and completion of three gross (1.5 net) new wells in the Chaveroo Field and to a lesser extent, drilling and completion expenditures at Delhi Field and SCOOP/STACK. As of the year ended June 30, 2024, we have paid approximately $38.7 million for the SCOOP/STACK Acquisitions and have accrued purchase price adjustments of $0.5 million related to net cash flows due on the properties from the effective date to the closing date to arrive at a net purchase price of $39.2 million.

Net cash flows provided by financing activities for the year ended June 30, 2024 were $22.3 million compared to net cash flows used in financing activities of $41.5 million for the year ended June 30, 2023. In the current year period, we had net borrowings of $39.5 million under our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions, $16.0 million cash dividends paid to our common stockholders together with $0.8 million paid to repurchase shares of common stock under our share repurchase plan. In the prior year period, we had repayments totaling $21.3 million of borrowings outstanding under our Senior Secured Credit Facility, $16.1 million in cash dividends paid to our common stockholders and $3.9 million paid to repurchase shares of common stock under our share repurchase program.

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Results of Operations

Years Ended June 30, 2024 and 2023

We reported net income of $4.1 million and $35.2 million for the years ended June 30, 2024 and 2023, respectively. The following table summarizes the comparison of financial information for the periods presented:

Years Ended June 30,

Revenues:

Operating costs:

Lease operating costs:

Depletion, depreciation, and accretion:

Accretion of asset retirement obligations 1,457 1,131 326 28.8 %

General and administrative expenses:

General and administrative 7,499 7,944 (445) (5.6) %

Other income (expense):

Production:

Natural gas liquids (MBBL) 402 416 (14) (3.4) %

Average daily production (BOEPD)(1) 6,790 7,104 (314) (4.4) %

Average price per unit(2):

Average cost per unit:

Operating costs:

Lease operating costs:

Ad valorem and production taxes 2.13 3.15 (1.02) (32.4) %

Other lease operating costs 15.59 16.97 (1.38) (8.1) %

General and administrative expenses:

General and administrative 3.02 3.06 (0.04) (1.3) %

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Revenues

Crude oil, natural gas and NGL revenues were $85.9 million and $128.5 million for the fiscal years ended June 30, 2024 and 2023, respectively. The decrease in revenues is primarily due to the decrease in our average realized price per BOE coupled with a decrease in our sales volumes. Our average realized commodity price (excluding the impact of derivative contracts) decreased approximately $15.00 per BOE, or 30.3%, for the fiscal year ended June 30, 2024 compared to June 30, 2023. 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. Realized natural gas prices decreased 62.7% from the prior fiscal year, which was the largest portion of the driver of the decrease in revenues. This was partially attributed to the prior fiscal year benefit of strong natural gas price differentials received at the Jonah Field where we realized an average natural gas price of $10.63 per MCF in the prior fiscal year compared to $3.55 for the current fiscal year. Average daily equivalent production decreased 4.4% from 7,104 BOEPD to 6,790 BOEPD in the current fiscal year as a result of natural production declines in our properties combined with operational issues and downtime at certain properties throughout the year. As of June 30, 2024, due to low natural gas prices, certain wells at Barnett Shale are shut-in and remain offline which has continued to negatively impact production volumes. The overall decrease in production was partially offset by the acquisitions of non-operated working interests in the SCOOP/STACK in February 2024 and first production at our wells in the Chaveroo Field in early February 2024, which collectively increased production for the year ended June 30, 2024 by approximately 601 BOEPD. Combined production at these two fields is primarily oil, thus increasing our oil volumes year over year.

Lease Operating Costs

Ad valorem and production taxes were $5.3 million and $8.2 million for the years ended June 30, 2024 and 2023, respectively. On a per unit basis, ad valorem and production taxes were $2.13 per BOE and $3.15 per BOE for the years ended June 30, 2024 and 2023, respectively. The decrease in ad valorem and production taxes is primarily due to decreases in our realized oil and natural gas prices as well as decreased production volumes described above as production taxes are based on sales at the wellhead.

The following table summarizes CO2 costs per Mcf and CO2 volumes for the years ended June 30, 2024 and 2023. CO2 purchase costs are for the Delhi Field. Under our contract with the Delhi Field operator, purchased CO2 is priced at 1% of the realized oil price in the field per Mcf, plus sales taxes and transportation costs as per contract terms.

Years Ended June 30,

CO2 volumes (MMCF per day, gross) 50.3 85.2 (34.9) (41.0) %

The $3.1 million decrease in CO2 costs for the fiscal year ended June 30, 2024 was primarily due to a 41.0% decrease in purchased CO2 volumes combined with a 2.0% decrease in CO2 costs per MCF, which was driven by a decrease in our average realized oil price. In February 2024, CO2 purchased volumes were suspended due to maintenance on the CO2 pipeline. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. We do not have any ownership in the CO2 pipeline which is owned and operated by Denbury. On a per unit basis, CO2 costs were $1.71 per BOE and $2.84 per BOE for the years ended June 30, 2024 and 2023, respectively. CO2 purchases are expected to restart in early second quarter of fiscal 2025.

Other lease operating costs decreased $5.3 million, or 12.0%, compared to the prior fiscal year primarily due to lower production combined with the lower commodity price environment. On a per unit basis, other lease operating costs decreased to $15.59 per BOE in the current year from $16.97 per BOE in the prior year. The largest decrease in other lease operating costs is at our Barnett Shale properties and the Delhi Field. At the Barnett Shale, significant cost savings efforts are being prioritized due to the lower realized natural gas prices and the shut-in of certain low margin wells at current natural gas prices. We are incurring lower operating costs in all cost categories, especially lower water hauling costs and lower gathering, transportation and processing charges. At Delhi Field, we have seen lower electricity charges due to lower commodity prices and decreased electrical demand due the installation of heat exchangers. These decreases are partially offset by increases in other lease operating costs associated with our acquisitions of non-operated working

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interests in the SCOOP/STACK in February 2024 and first production at our wells in the Chaveroo Field in early February 2024.

Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $5.5 million or 41.6% from $13.1 million for the fiscal year ended June 30, 2023 to $18.6 million for the fiscal year ended June 30, 2024 primarily due to an increase in the depletion rate. On a per unit basis, depletion expense was $7.49 per BOE and $5.07 per BOE for the fiscal years ended June 30, 2024 and 2023, respectively.The depletion rate of our unit of production calculation increased primarily due to an increase in our depletable base due to our SCOOP/STACK Acquisitions and capital expenditures since the prior year period.

General and Administrative Expenses

General and administrative expenses for the fiscal year ended June 30, 2024 decreased $0.4 million, or 5.6%, to $7.5 million compared to $7.9 million for the fiscal year ended June 30, 2023. The decrease primarily relates to lower consulting fees totaling approximately $0.3 million related to our search for a CEO in the prior year period. On a per unit basis, general and administrative expenses were $3.02 per BOE and $3.06 per BOE for the years ended June 30, 2024 and 2023, respectively.

Stock-based Compensation Expenses

Stock-based compensation increased $0.5 million to $2.1 million for the year ended June 30, 2024 compared to $1.6 million the prior period due primarily to the addition of new personnel and the associated new awards granted during the current year period to all staff and directors.

Net Gain (Loss) on Derivative Contracts

Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. 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.

Years Ended June 30,

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As a result of our acquisitions during fiscal years 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 commodity prices since entering into the hedges and the continued increase in forward commodity prices resulted in a realized loss on hedges for the current year and an unrealized loss on the mark-to-market of our hedges. As of June 30, 2024, we had $0.8 million derivative assets, $0.6 million of which was classified as current, and a $1.7 million derivative liability, $1.2 million of which was classified as current.

Interest Expense

Interest expense increased $1.0 million during the fiscal year ended June 30, 2024 compared to fiscal year 2023 primarily due to borrowings drawn on our Senior Secured Credit Facility to finance our SCOOP/STACK Acquisitions during the current year. In addition, the weighted average interest rate on our borrowings increased to 8.12% for the fiscal year ended June 30, 2024 compared to 5.25% for fiscal year 2023.

Income tax (expense) provision

For the year ended June 30, 2024, we recognized income tax expense of $1.4 million on net income before income taxes of $5.5 million compared to an income tax expense of $10.1 million on net income before income taxes of $45.3 million for the year ended June 30, 2023. The effective tax rates were 25.8% and 22.2% for the years ended June 30, 2024 and 2023, respectively. The effective tax rate increased compared to the prior year period as projected state income taxes have become a larger component of our overall income tax expense during the period.

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 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, 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

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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, 2024, 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, 2024 of 10% would affect depletion, depreciation, and amortization expense by approximately $0.5 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 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 natural gas liquids 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 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 2024 and 2023, 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

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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 SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR, subject to a minimum SOFR of 0.50%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%. 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.

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Item 8. Consolidated Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

Consolidated Balance Sheets as of June 30, 2024 and 2023 51

Notes to Consolidated Financial Statements 55

Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) 74

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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, 2024 and 2023, 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, 2024 and 2023, 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.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of June 30, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated September 11, 2024, expressed an unqualified opinion on the Company’s internal control over financial reporting.

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 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.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, 2024, the Company recorded DD&A related to its proved oil and natural gas properties of approximately $18.6 million, and there was no ceiling test impairment.

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The Company engages three 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 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 specialist for completeness and accuracy;

o Testing the specialist’s findings for mathematical accuracy; and

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

◾ production forecasts to recent historical actual production,

/s/ Moss Adams LLP

Houston, Texas

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

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Evolution Petroleum Corporation

Opinion on Internal Control over Financial Reporting

We have audited Evolution Petroleum Corporation and subsidiaries (the “Company”) internal control over financial reporting as of June 30, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of June 30, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of Evolution Petroleum Corporation and subsidiaries as of June 30, 2024 and 2023, 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”) and our report dated September 11, 2024, expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting included in Item 9A. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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/s/ Moss Adams LLP

Houston, Texas

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

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EVOLUTION PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

Assets

Current assets

Cash and cash equivalents $ 6,446 $ 11,034

Derivative contract assets 596 —

Prepaid expenses and other current assets 3,855 2,277

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

which none were excluded from amortization 139,685 105,781

Other noncurrent assets

Derivative contract assets 171 —

Liabilities and Stockholders' Equity

Current liabilities

Accrued liabilities and other 6,239 6,027

Derivative contract liabilities 1,192 —

State and federal taxes payable 74 365

Long term liabilities

Senior secured credit facility 39,500 —

Deferred income taxes 6,702 6,803

Derivative contract liabilities 468 —

Operating lease liability 58 125

Commitments and contingencies (Note 10)

Stockholders' equity

Total liabilities and stockholders' equity $ 162,877 $ 128,317

See accompanying notes to consolidated financial statements.

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EVOLUTION PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

Years Ended June 30,

Revenues

Operating costs

Depletion, depreciation, and accretion 20,062 14,273

General and administrative expenses 9,636 9,583

Income (loss) from operations 7,906 45,113

Other income (expense)

Net gain (loss) on derivative contracts (1,292) 513

Interest and other income 342 121

Interest expense (1,459) (458)

Income (loss) before income taxes 5,497 45,289

Income tax (expense) benefit (1,417) (10,072)

Net income (loss) per common share:

Weighted average number of common shares outstanding:

See accompanying notes to consolidated financial statements.

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EVOLUTION PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

Years Ended June 30,

Cash flows from operating activities:

Depletion, depreciation, and accretion 20,062 14,273

Stock-based compensation 2,137 1,639

Settlement of asset retirement obligations (20) (174)

Deferred income taxes (101) (296)

Unrealized (gain) loss on derivative contracts 893 (1,994)

Accrued settlements on derivative contracts 67 (919)

Other — (4)

Changes in operating assets and liabilities:

Prepaid expenses and other current assets (1,562) (692)

Accounts payable and accrued liabilities and other 374 (13,489)

State and federal taxes payable (291) (730)

Net cash provided by operating activities 22,729 51,272

Cash flows from investing activities:

Acquisition of oil and natural gas properties (38,734) (31)

Capital expenditures for oil and natural gas properties (10,899) (6,961)

Net cash used in investing activities (49,633) (6,992)

Cash flows from financing activities:

Common stock dividends paid (16,040) (16,106)

Borrowings under senior secured credit facility 42,500 —

Repayments of senior secured credit facility (3,000) (21,250)

Net cash provided by (used in) financing activities 22,316 (41,526)

Net increase (decrease) in cash and cash equivalents (4,588) 2,754

Cash and cash equivalents, beginning of period 11,034 8,280

Cash and cash equivalents, end of period $ 6,446 $ 11,034

Supplemental disclosures of cash flow information:

Cash paid for interest on senior secured credit facility $ 1,331 $ 498

Cash paid for income taxes 2,804 11,876

Non-cash investing and financing transactions:

See accompanying notes to consolidated financial statements.

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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 476 1 (1) — — —

Forfeitures of restricted stock (26) — — — — —

Retirements of treasury stock (673) (1) (4,169) — 4,170 —

Stock-based compensation — — 1,639 — — 1,639

Net income (loss) — — — 35,217 — 35,217

Common stock dividends paid — — — (16,106) — (16,106)

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)

See accompanying notes to consolidated financial statements.

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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 oilfield 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 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; 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. To conform with the current year presentation, $0.6 million of accrued ad valorem and productions taxes at June 30, 2023 are included with “Accrued taxes other than federal and state income tax” instead of “Accrued payables” as disclosed in Note 13, “Additional Financial Information.” This reclassification has no impact on previously reported net income or stockholders’ equity.

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 a limited ability to influence the operation or future development of such properties. However, the Company is proactive with its third-party operators to review capital projects and related spending and present alternative plans as appropriate.

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 natural gas liquids (“NGL”) revenues and 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.

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

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EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2024 and 2023, 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 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, 2024 and 2023, the Company did not have any costs excluded from 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 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

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EVOLUTION PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2024 and 2023 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, 2024, four individual purchasers, 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. In the year ended June 30, 2023, three individual purchasers, Diversified, Denbury, and Conoco Phillips, each accounted for more than 10% of the Company’s total revenues, collectively representing approximately 65% of the Company’s total revenues for the year. The majority of the Company’s crude oil, natural gas, and NGL production is sold to purchasers under short-term (less than 12 months) contracts at market-based prices.

Derivative Instruments. The Company follows Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging (“ASC 815”). From time to time, in accordance with the Company’s risk management strategy and with certain covenants under the Senior Secured Credit Facility, it may hedge a portion of its forecasted crude oil, natural gas, and NGL production. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”); the agreement provides for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.

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EVOLUTION PETROLEUM CORPORATION

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availability of additional information; this includes reservoir performance, additional development activity, new geologic and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates prepared by the Company’s third-party independent engineers represent the most accurate assessments possible, the subjective decisions and variances in available data for the properties make these estimates generally less precise than other estimates included in the Company’s financial statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect the Company’s estimated future net cash flows of its proved reserves. These changes could affect the Company’s quarterly ceiling test calculation and could significantly affect its depletion rate.

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

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

Recently Issued Accounting Pronouncements

In 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

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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 is currently evaluating ASU 2023-07 and the impact it may have to the Company’s financial position, results of operations, cash flow or disclosures.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. Early adoption is permitted and entities must adopt the amendment using a modified retrospective approach to the first reporting period in which the guidance is effective. For smaller reporting companies, as provided by ASU 2019-10, Financial Instruments - Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842), ASU 2016-13 is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2022. The Company adopted ASU 2016-13 effective July 1, 2023. The adoption did not have a material effect on the Company’s financial position, results of operations, cash flows 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 oilfield 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; and the Delhi Field in Northeast Louisiana. 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, 2024 and 2023 (in thousands):

Years Ended June 30,

Revenues

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

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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

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 taking into account customary closing adjustments and an effective date of November 1, 2023, total combined cash consideration for the SCOOP/STACK Acquisitions was approximately $39.2 million, which includes $43.9 million paid at closing less purchase price adjustments totaling approximately $4.7 million related to net cash flows received on the properties subsequent to closing. The Company accounted for these transactions as asset acquisitions and allocated all of 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 253 producing wells in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma.

Chaveroo Oilfield 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 oilfield, located in Chaves and Roosevelt Counties, New Mexico. In accordance with the Participation Agreement, the Company will have 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

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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, 2024, the Company incurred approximately $0.8 million in exchange for a 50% working interest share in the existing leases associated with five development blocks. As of June 30, 2024, the Company has participated in the drilling and completion of the first development block, consisting of three gross wells (1.5 net wells).

In accordance with the FASB’s authoritative guidance on asset acquisitions, the Company allocated the cost of the above acquisitions to the assets acquired and liabilities assumed based on a relative fair value basis of the assets acquired and liabilities assumed, 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.

Note 4. Property and Equipment

Property and equipment as of June 30, 2024 and 2023 consisted of the following (in thousands):

Oil and natural gas properties

Property costs subject to amortization $ 249,559 $ 197,049

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, 2024 and 2023, all oil and natural gas property costs were subject to amortization. Depletion on oil and natural gas properties was $18.6 million and $13.1 million for the years ended June 30, 2024 and 2023, respectively. During the years ended June 30, 2024 and 2023, the Company incurred development capital expenditures of $12.3 million and $6.2 million, respectively.

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 West Texas Intermediate (“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 differentials to WTI 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.

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At June 30, 2023, 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, 2023 of the WTI crude oil spot price of $83.23 per barrel and Henry Hub natural gas spot price of $4.78 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $33.71, which was based on historical differentials to WTI as NGLs do not have any single comparable reference index price. Using these prices at June 30, 2023, 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 three-year, senior secured reserve-based credit facility, as amended, (the “Senior Secured Credit Facility”) with MidFirst Bank in an amount up to $50.0 million with a current borrowing base of $50.0 million. On May 5, 2023, the Company entered into the Tenth Amendment to the Senior Secured Credit Facility extending the maturity to April 9, 2026. The Tenth Amendment also replaced the London Interbank Offered Rate ("LIBOR") with the Secured Overnight Financing Rate (“SOFR”) plus a credit spread adjustment of 0.05% to effectively convert SOFR to a LIBOR equivalent and modifies the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million. The borrowing base will be redetermined semiannually, with the lenders and the 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 SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR, subject to a minimum SOFR of 0.50%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%.

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 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 or 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. As of June 30, 2024, the Company had $39.5 million in borrowings outstanding under its Senior Secured Credit Facility, resulting in $10.5 million of available borrowing capacity. For the years ended June 30, 2024 and 2023, the weighted average interest rate on borrowings under the Senior Secured Credit Facility was 8.12% and 5.25%, respectively. As of June 30, 2024, the Company was in compliance with all covenants under the Senior Secured Credit Facility.

On February 12, 2024, the Company entered into an amendment to the Senior Secured Credit Facility. This amendment required that the Company enter into hedges for the next 12-month period, and on a rolling 12-month basis thereafter, covering expected crude oil and natural gas production from proved developed reserves, calculated separately, equal to a minimum of 40% of expected crude oil production each month, or 25% of expected crude oil and natural gas production each month over that period. The Company has the option to choose whether to hedge 40% of expected crude oil production or 25% of expected crude oil and natural gas production.

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On February 7, 2022, the Company entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as defined in the agreement, to the extent it exceeds the borrowing base then in effect. This amendment also required the Company to enter into hedges for the next 12-month period ending February 2023, covering 25% of expected crude oil and natural gas production over that period.

On November 9, 2021, the Company entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby the Company must hedge a minimum of 25% to 75% of future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in subsequent amendments, as discussed above.

Note 6. Income Taxes

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

There were no unrecognized tax benefits, nor any accrued interest or penalties associated with unrecognized tax benefits during the years ended June 30, 2024 and 2023. 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, 2020 through June 30, 2023 for federal tax purposes and for the fiscal years ended June 30, 2019 through June 30, 2023 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, 2024 and 2023 is comprised of the following (in thousands):

Current:

Total current income tax (expense) benefit (1,518) (10,368)

Deferred:

Total deferred income tax (expense) benefit 101 296

Total income tax (expense) benefit $ (1,417) $ (10,072)

For the year ended June 30, 2024 the Company recognized income tax expense of $1.4 million and had an effective tax rate of 25.8% compared to income tax expense of $10.1 million and an effective tax rates of 22.2% for the year ended June 30, 2023. During the years ended June 30, 2024 and 2023, the Company recognized an income tax benefit of less than $0.1 million and $0.1 million, respectively, related to the vesting of restricted stock awards.

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The Company’s effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the states of Louisiana, North Dakota, and Texas, due to percentage depletion in excess of basis, and other permanent differences. 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 3 (0.1) % — — %

Depletion in excess of tax basis 114 (2.1) % 78 (0.2) %

Other (2) 0.1 % (1) — %

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 $ 381 $ 250

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

Derivative losses 192 —

Asset retirement obligations 4,427 3,883

Other deferred tax assets 197 201

Total deferred tax assets 5,510 4,334

Deferred tax liabilities:

Oil and natural gas properties (12,072) (11,137)

Total deferred tax liabilities (12,072) (11,137)

Valuation allowance (140) —

Net deferred tax liabilities $ (6,702) $ (6,803)

Evolution Petroleum OK, Inc., a wholly-owned subsidiary of the Company, has a prior year carryforward of NOLs of $8.9 million generated during tax years 2011 through 2017. With the current year acquisition of assets in Oklahoma by Evolution Petroleum OK, Inc., a deferred tax asset was recorded for a portion of this NOL carryforward.

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.

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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, 2024, 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 and/or fixed-price swaps to hedge a portion of its anticipated future production. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract, and a purchased put that establishes a minimum price. 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. 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, 2024 and 2023 (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, 2024 and 2023 (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 $ (1,292) $ 513

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As of June 30, 2024, the Company had the following open crude oil and natural gas derivative contracts:

Weighted Average Weighted Average Weighted Average

Volumes in Swap Price per Floor Price per Ceiling Price per

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

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, 2024 and 2023 (in thousands):

Derivative Contract Assets Derivative Contract Liabilities

Net amount $ 270 $ — $ 1,163 $ —

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

Note 8. Fair Value Measurement

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

The three levels are defined as follows:

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

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

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

Fair Value of Derivative Instruments. The Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The Company utilizes market data or assumptions that market

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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.

EPM US Equity

EPM · 10-K · period ended 2024-06-30

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 2024-06-30

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