EVOLUTION PETROLEUM CORP (EPM)

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

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Dividend Declaration

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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.

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SCOOP/STACK Acquisitions

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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

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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

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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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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

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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.

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Chaveroo Oilfield Participation Agreement

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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”).

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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.

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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.

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Proved Reserves

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

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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.

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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.

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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.

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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.

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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.

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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 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.

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.

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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.

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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.

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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.

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Overview of Cash Flow Activities

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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:

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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.

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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.

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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.

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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 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 Jonah Field in Sublette County, Wyoming, a natural gas producing field; non-operated interests in the Williston Basin in North Dakota, a producing oil and natural gas property; non-operated interests in the Barnett Shale located in North Texas, a natural gas producing property; non-operated interests in the Hamilton Dome Field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir; non-operated interests in the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO2 enhanced oil recovery (“EOR”) project; and small overriding royalty interests in four onshore central Texas wells.

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. The properties are operated by Jonah Energy, an established operator in the geographic region.

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 43,300 net acres (approximately 92% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota. The properties are operated by Foundation Energy Management, an established operator in the geographic region.

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.

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 approximately 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company, who owns the vast 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

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7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC. The Delhi Field is located in northeast Louisiana in Franklin, Madison, and Richland Parishes and encompasses approximately 14,000 gross unitized acres, or approximately 3,200 net acres.

Recent Developments

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Dividend Declaration

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On September 11, 2023, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 29, 2023.

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Senior Secured Credit Facility

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On May 5, 2023, we entered into the Tenth Amendment to our Senior Secured Credit Facility, which has a current borrowing base of $50.0 million. This amendment, among other things, extends the maturity of our Senior Secured Credit Facility to April 9, 2026 and converts our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%. For further discussion of the amendment and our Senior Secured Credit Facility, see “Liquidity and Capital Resources” below.

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Appointment of Chief Operating Officer

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On February 23, 2023, we announced that the Board of Directors appointed J. Mark Bunch as COO. Mr. Bunch had been providing consulting services to the Company since 2016. We entered into an offer letter with Mr. Bunch setting forth his compensation as COO on February 21, 2023.

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Appointment of Chief Executive Officer

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On October 27, 2022, we announced that the Board of Directors selected Kelly W. Loyd as President and CEO. Mr. Loyd had been serving as Interim CEO since June 2022 and has served as a member of the Board of Directors since 2008. We entered into an offer letter with Mr. Loyd setting forth his compensation as CEO on October 25, 2022. Upon commencing employment, Mr. Loyd no longer receives compensation for his services as a member of the Board of Directors.

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Share Repurchase Program

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On September 8, 2022, the 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 repurchases from available 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 and 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. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the intrinsic value of our shares, our capital needs and resources, the market price of our common stock, general market and economic conditions, and applicable legal requirements. The value of shares authorized for repurchase by our Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the program may be suspended, modified, or discontinued at any time without prior notice.

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Once we completed repayment of borrowings on our Senior Secured Credit Facility and emerged from our blackout period in December 2022, 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 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

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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. We may enter into additional Rule 10b5-1 plans in the future, the terms of which will be approved by the Board of Directors.

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Proved Reserves

The following table is a summary of our proved reserves as of June 30, 2023 and 2022:

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Proved oil equivalent reserves as of June 30, 2023 were 31.2 MMBOE, a 5.0 MMBOE, or 13.8%, decrease from the previous year of 36.2 MMBOE. The net decrease in total proved reserves was primarily due production of 2.6 MMBOE and net negative revisions of 2.6 MMBOE partially offset by additions and extensions of 0.1 MMBOE. Net negative revisions of 2.6 MMBOE are primarily due to declines in SEC trailing 12-month pricing that impacted late-in-life economic limits of production, adjustment to projections and increased production costs partially offset by restored production at Hamiton Dome Field and improved economics from our differentials at Jonah Field.

The Standardized Measure for proved reserves decreased 24.3% to $238.2 million, primarily due to sales of oil, natural gas and NGLs produced during the period, decreases in reserves estimates, 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. Prices decreased from $85.82 per barrel of oil, $5.19 per MMBtu of natural gas and $44.24 per barrel of NGLs at June 30, 2022 to $83.23 per barrel of oil, $4.78 per MMBtu of natural gas and $33.71 per barrel of NGLs at June 30, 2023. Our proved reserves consist of 32% oil, 49% natural gas, and 19% NGLs; 88.1% are classified as proved developed producing and 11.9% are proved undeveloped.

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

Risks and uncertainties

The global economy was deeply impacted by the effects of the novel coronavirus (“COVID-19”) pandemic and related efforts to mitigate the spread of the disease. These events led to crude oil prices falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020.

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Beginning in 2021, the demand for oil and natural gas started to recover primarily as a result of the roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses. In addition, the military activities of Russia into Ukraine and the subsequent sanctions imposed on Russia and other actions have created significant market uncertainties, including uncertainties around potential supply disruptions for oil and natural gas, which further enhanced volatility in global commodity prices in the first half of 2022.

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Additionally, in March 2023, the closures of Silicon Valley Bank and Signature Bank and their placement into receivership with the Federal Deposit Insurance Corporation (“FDIC”) created broad uncertainty around world-wide financial institutions and liquidity risk. While we do not have exposure to these banks, we do maintain cash balances in excess of FDIC insurance protections at banks we believe 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.

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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; or the impact on the commodity prices that we realize.

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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, 2023, we had no borrowings outstanding on our Senior Secured Credit Facility and $11.0 million in cash and cash equivalents compared to $21.3 million of borrowings on our Senior Secured Credit Facility and $8.3 million in cash and cash equivalents at June 30, 2022. Our primary sources of liquidity and capital resources during the year ended June 30, 2023 were cash provided by operations and the unused portion of our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the year ended June 30, 2023 were repayments on our Senior Secured Credit Facility, cash dividend payments to our common stockholders, common stock repurchases, and capital expenditures on our existing oil and natural gas properties. As of June 30, 2023, working capital was $8.9 million, an increase of $2.8 million from working capital of $6.1 million as of June 30, 2022.

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. The Senior Secured Credit Facility is secured by substantially all of our oil and natural gas properties and matures on April 9, 2026.

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 year ended June 30, 2023, the weighted average interest on our borrowings was 5.25%. 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, 2023, 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

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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 the Ninth Amendment, as discussed above.

On August 5, 2021, we entered into the Seventh Amendment of our Senior Secured Credit Facility which, among other things, added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the consolidated tangible net worth covenant level was reduced to $40.0 million from $50.0 million.

We have historically funded operations through cash from operations and working capital. Our primary source of cash is the sale of produced crude oil, natural gas, and NGLs. A portion of these cash flows is used to fund capital expenditures and pay cash dividends to shareholders. We expect to fund near-future capital development activities for our properties with cash flows from operating activities and existing working capital.

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 $50.0 million as of June 30, 2023. 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 39 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to increase dividends over time, as appropriate. On September 11, 2023, the Board of Directors declared a quarterly cash dividend of $0.12 per share of common stock to shareholders of record on September 22, 2023 and payable on September 29, 2023.

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.

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Once we completed the repayment of borrowings on our Senior Secured Credit Facility and emerged from our blackout period 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. We may enter into additional Rule 10b5-1 plans in the future, the terms of which will be approved by the Board of Directors.

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Capital Expenditures

For the year ended June 30, 2023, we incurred $6.2 million on development capital expenditures and $0.2 million for plugging and abandoning costs. During the latter half of fiscal year 2023, we participated in the completion and fracture stimulation of a vertical Bakken well. Toward the end of fiscal 2023 and into fiscal 2024 we have participated in the drilling of two new down dip wells in the Delhi Field. Completion and first production of the wells are expected in the first quarter of fiscal 2024.

Based on discussions with our operators, we expect capital workover projects to continue in all the fields. Overall, for fiscal year 2024, we expect budgeted capital expenditures to be in the range of $4.0 million to $5.0 million, which excludes any potential acquisitions. Our expected capital expenditures for the next 12 months include the two new drill wells at Delhi Field, discussed above, and also include Foundation, the operator of our Williston Basin properties, drilling two sidetrack locations targeting the Birdbear formation.

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As of June 30, 2023, our PUD reserves included 3.7 MMBOE of reserves and approximately $71.7 million of future development costs primarily associated with the Williston Basin properties.

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, 2023 were $83.23 per barrel of oil, $4.78 per MMBtu of natural gas and $33.71 per barrel of NGLs. As of June 30, 2023, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling. If commodity price levels were to substantially decline from the 12-month average first day of the month pricing levels as of June 30, 2023 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, 2023, while all other factors remained constant, would not have generated an impairment.

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Overview of Cash Flow Activities

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Cash provided by operating activities decreased $1.2 million during the fiscal year ended June 30, 2023 compared to fiscal year ended June 30, 2022 primarily due to decreases in our operating assets and liabilities from the timing of converting working capital into cash. These decreases are partially offset by increases in total revenues over our increase in operating costs. Total revenues increased $19.6 million as compared to the prior year driven by an increase in our average daily production primarily due to our acquisition of non-operated working interests in the Jonah Field and Williston Basin in April 2022 and January 2022, respectively, partially offset by decreases in the average realized price per BOE.

Cash used in investing activities for the year ended June 30, 2023 decreased $47.9 million from the prior year. In fiscal year 2022, we completed the acquisition of our Jonah Field properties totaling $26.4 million and the acquisition of our Williston Basin properties total $25.8 million. The decrease was partially offset by an increase in development capital expenditures in the current fiscal year.

Net cash flows used in financing activities for the year ended June 30, 2023 were $41.5 million which included the repayment of $21.3 million of borrowings outstanding under our Senior Secured Credit Facility, $16.1 million in dividends paid to our common stockholders, and $3.9 million paid to repurchase shares of common stock under our share repurchase program. Net cash flows provided by financing activities for the year ended June 30, 2022 were $5.4 million which primarily included $17.3 million in net borrowings under our Senior Secured Credit Facility offset by $11.8 million in dividends paid to our common stockholders.

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Results of Operations

Years Ended June 30, 2023 and 2022

We reported net income of $35.2 million and $32.6 million for the years ended June 30, 2023 and 2022, respectively. The following table summarizes the comparison of financial information for the periods presented:

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Revenues

Fiscal year ended June 30, 2023 revenues increased 18.0% to $128.5 million compared to $108.9 million for the fiscal year ended June 30, 2022. The increase in revenue is primarily due to our acquisitions of non-operated working interests in the Jonah Field and Williston Basin in the second half of fiscal year 2022. Average daily equivalent production increased 19.3%, from 5,953 BOEPD to 7,104 BOEPD in the current year. Production increases were driven by our acquisitions of non-operated working interests in the Jonah Field and Williston Basin in the second half of fiscal 2022, which increased current fiscal year production by approximately 1,621 BOEPD. The increase in our average daily production from our acquisitions was partially offset by decreases related to downtime at our Barnett Shale properties due to compressor and pipeline repairs as well as shut-in wells and our Delhi Field properties due to winter storms, and Delhi heat exchanger upgrade installation and NGL plant repairs during the fourth fiscal quarter. Our average realized commodity price (excluding the impact of derivative contracts) decreased approximately $0.57 per BOE, or 1.1%, for the fiscal year ended June 30, 2023 compared to June 30, 2022. Realized oil and NGL prices decreased approximately 9.0% and 29.9% respectively, over the prior year. These decreases are partially offset by an increase of approximately 27.5% in realized natural gas prices from the prior year period despite the substantial decrease in natural gas prices that occurred in late third quarter. The year over year increase in realized natural gas prices is primarily attributed to the benefit of natural gas price differentials received at the Jonah Field where our realized price for natural gas for the current year period was $10.63 per MCF.

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Lease Operating Costs

Ad valorem and production taxes were $8.2 million and $7.0 million for the years ended June 30, 2023 and 2022, respectively. The increase in ad valorem and production taxes is primarily due to increased production volumes described above as production taxes are based on sales at the wellhead. On a per unit basis, ad valorem and production taxes were $3.15 per BOE and $3.20 per BOE for the years ended June 30, 2023 and 2022, respectively. The decrease in ad valorem and production taxes on a per unit basis are due to the increased production volumes described above.

The following table summarizes CO2 costs per Mcf and CO2 volumes for the years ended June 30, 2023 and 2022. 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.

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The $0.3 million decrease in CO2 costs for the fiscal year ended June 30, 2023 was primarily due to a 7.5% decrease in CO2 costs per MCF, which was driven by a decrease in our average realized oil price partially offset by a 3.1% increase in purchased CO2 volumes. 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 $2.84 per BOE and $3.55 per BOE for the years ended June 30, 2023 and 2022, respectively.

Other lease operating costs include remedial workover costs and gathering and transportation costs for our oil and natural gas production. Compared to the prior year, other lease operating costs increased $10.0 million, or 29.5%, to $44.0 million in the year ended June 30, 2023 primarily due to the acquisitions in the Jonah Field and Williston Basin in April 2022 and January 2022, respectively, which increased current year other lease operating costs by $8.0 million. Other lease operating costs on a per BOE basis increased to $16.97 per BOE in the current year from $15.64 per BOE in the prior year, an increase of $1.33 per BOE.

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Depletion of Full Cost Proved Oil and Natural Gas Properties

Depletion expense increased $5.6 million or 74.8% from $7.5 million for the fiscal year ended June 30, 2022 to $13.1 million for the fiscal year ended June 30, 2023 primarily due to an increase in production. On a per unit basis, depletion expense was $5.07 per BOE and $3.46 per BOE for the fiscal years ended June 30, 2023 and 2022, respectively. The increase in depletion per BOE was due primarily to an increase in the depletable base of our unit of production calculation due to our acquisitions in fiscal year 2022 and an increase in our future development costs associated with our proved undeveloped reserve addition in fiscal year 2022 combined with a decrease in our proved reserve volumes.

General and Administrative Expenses

General and administrative expenses for the fiscal year ended June 30, 2023 increased $1.2 million, or 18.4%, to $7.9 million compared to $6.7 million for the fiscal year ended June 30, 2022. The increase is primarily due to approximately $0.6 million for salary and employee benefits due to additional personnel added as additional assets were acquired, and $0.3 million in professional fees associated with our search for a CEO. The remaining increase is associated with fees for accounting and audit-related services and public reporting expenses due to the increased size of our Company. On a per unit basis, general and administrative expenses decreased $0.03 per BOE to $3.06 per BOE for the year ended June 30, 2023 from $3.09 per BOE for the prior year. The decrease in general and administrative expenses on a per unit basis are due to the increased production volumes described above.

Stock-based Compensation Expenses

Stock-based compensation increased $1.5 million to $1.6 million for the year ended June 30, 2023 compared to $0.1 million the prior period due primarily to the $1.2 million reduction in prior year expense related to the forfeiture of unvested shares in connection with severance, combined with the addition of new personnel, including our CEO and COO, and the associated new awards granted during the current year period to all staff and directors. In addition, approximately $0.1 million of the current year period increase related to a one-time share award granted in November 2022, which vested and was fully expensed immediately.

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. As a result of our acquisitions during fiscal year 2022 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 resulted in realized losses on derivative contracts for the current and prior years. As of June 30, 2023, we did not have any open crude oil or natural gas derivative contracts.

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Interest Expense

Interest expense decreased $0.1 million during the fiscal year ended June 30, 2023 compared to fiscal year 2022 primarily due to the repayment of borrowings outstanding on our Senior Secured Credit Facility throughout the year.

Income tax (expense) provision

For the year ended June 30, 2023, we recognized income tax expense of $10.1 million on net income before income taxes of $45.3 million compared to an income tax expense of $8.5 million on net income before income taxes of $41.1 million for the year ended June 30, 2022. The effective tax rates were 22.2% and 20.7% for the years ended June 30, 2023 and 2022, respectively. In the prior year, the Company benefited from certain EOR tax credits whereas in the current year the credits were not available.

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, 2023, we had no unevaluated property costs. Oil and natural gas properties include costs that are excluded from depletion and amortization, which represent investments in unproved and unevaluated properties and include non-producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs.

Estimates of Proved Reserves.    The estimated quantities of proved oil and natural gas reserves have a significant impact on the underlying financial statements. The estimated quantities of proved reserves are used to calculate depletion expense and the estimated future net cash flows associated with those proved reserves is the basis for determining impairment under the quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex and requires significant decisions in the evaluation of all available geologic, geophysical, engineering, and economic data. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information; this includes reservoir performance, additional development activity, new geologic and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates prepared by our third-party independent engineers represent the most accurate assessments possible, the subjective decisions and variances in available data for the properties make these estimates generally less precise than other estimates included in our financial statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect our estimated future net cash flows of our proved reserves. These changes could affect our quarterly ceiling test calculation and could significantly affect our depletion rate. Additionally, a 10% decrease in commodity prices used to determine our proved reserves as of

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June 30, 2023, 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, 2023 of 10% would affect depletion, depreciation, and amortization expense by approximately $0.4 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 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

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 Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO2 enhanced oil recovery (“EOR”) project; non-operated interests in the Hamilton Dome Field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir; non-operated interests in the Barnett Shale located in North Texas, a natural gas producing property; non-operated interests in the Williston Basin in North Dakota, a producing oil and natural gas property; non-operated interests in the Jonah Field in Sublette County, Wyoming, a natural gas producing field; and small overriding royalty interests in four onshore central Texas wells.

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 (“Denbury”). The Delhi Field is located in northeast Louisiana in Franklin, Madison, and Richland Parishes and encompasses approximately 14,000 gross unitized acres, or approximately 3,200 net acres.

Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consists of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest). The approximately 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company (“Merit”), who owns the vast 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 Barnett Shale, a natural gas producing shale reservoir, consists of approximately 17% average net working interest with an associated 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 seven other operators.

On January 14, 2022, we acquired non-operated working interests in 73 producing wells in the Williston Basin with an average net working interest of approximately 39% and average net revenue interest of approximately 33% located on approximately 45,000 net acres (approximately 90% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota (the “Williston Basin Acquisition”). After taking into account customary closing adjustments and an effective date of June 1, 2021, cash consideration was $25.2 million which includes $0.3 million of transaction costs related to the acquisition. The properties are operated by Foundation Energy Management (“Foundation”), an established operator in the geographic region.

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On April 1, 2022, we acquired non-operated working interests in the Jonah Field in Sublette County, Wyoming (the “Jonah Field Acquisition”). After taking into account the deposit on the acquisition, customary closing adjustments and an effective date of February 1, 2022, cash consideration at closing was $26.4 million (including $0.2 million of transaction costs). The acquired properties include an average net working interest of approximately 20% and an average net revenue interest of approximately 15% in 595 producing wells and 950 net acres. The properties are operated by Jonah (“Jonah”), an established operator in the geographic region.

Recent Developments

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Dividend Declaration and Share Repurchase Program

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On September 12, 2022, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2022. This represents a 20% increase over the $0.10 per common share dividend paid in the fourth quarter of fiscal year 2022. Also, on September 8, 2022, the Board of Directors authorized a share repurchase program, under which we are approved to repurchase up to $25 million of our common stock through December 31, 2024. We intend to fund repurchases from available 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. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the intrinsic value of our shares, the market price of our common stock, general market and economic conditions, and applicable legal requirements. The value of shares authorized for repurchase by our Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the program may be suspended, modified, or discontinued at any time without prior notice.

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Highlights for our Fiscal Year 2022 and Operations Update

Proved Reserves

Proved oil equivalent reserves as of June 30, 2022 were 36.2 MMBOE, a 55% increase from the previous year primarily due to the acquisitions of properties in the Williston Basin and Jonah Field in January 2022 and April 2022, respectively. The Standardized Measure for proved reserves increased 259% to $314.8 million, primarily due to the acquisitions of

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properties in the Williston Basin and Jonah Field and an increase in the SEC mandated trailing 12-month average first day of the month prices for oil and natural gas. Prices increased from $49.72 per barrel of oil, $2.46 per MMBtu of natural gas and $19.81 per barrel of NGLs at June 30, 2021 to $85.82 per barrel of oil, $5.19 per MMBtu of natural gas and $44.24 per barrel of NGLs at June 30, 2022. Our proved reserves consist of 32% oil, 49% natural gas, and 19% NGLs; 90% are classified as proved developed producing and 10% are proved undeveloped.

The following table is a summary of our proved reserves as of June 30, 2022 and 2021:

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Additional property and project information is included under Item 1. Business and in Note 5, “Property and Equipment” and our Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data, and in Exhibit 99.1 and 99.2 of this Form 10-K.

At June 30, 2022, we had total net proved reserves of 36.2 MMBOE, a 12.8 MMBOE increase from the previous year of 23.4 MMBOE. The net increase in total proved reserves was the result of acquisitions of 9.3 MMBOE, additions and extensions of 3.6 MMBOE and net positive revisions of 2.1 MMBOE, partially offset by production of 2.2 MMBOE. Net positive revisions of 2.1 MMBOE increased primarily due to improvement in SEC trailing 12-month pricing partially offset by the removal of 1.8 MMBOE of PUDs related to Test Site V and 0.7 MMBOE of PDP at our Delhi Field property.

Impact of the COVID-19 Pandemic and Geopolitical factors

The global economy has been deeply impacted by the effects of the novel coronavirus (“COVID-19”) pandemic and related efforts to mitigate the spread of the disease. These events led to crude oil prices falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020.

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In 2021, the demand for oil and natural gas began to recover primarily as a result of the roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses. In addition, the recent special military operation of Russia into Ukraine and the subsequent sanctions imposed on Russia and other actions have created significant market uncertainties, including uncertainties around potential supply disruptions for oil and natural gas, which has further enhanced volatility in global commodity prices in the first half of 2022. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist.

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Currently, none of our oil and natural gas properties are operated by us. As a result, in the past we have had limited ability to influence or control 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 alter plans as appropriate to increase shareholder value.

Liquidity and Capital Resources

As of June 30, 2022, we had $8.3 million in cash and cash equivalents compared to $5.3 million at June 30, 2021. Our primary sources of liquidity and capital resources during the year ended June 30, 2022 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, 2022 were acquisitions of oil and natural gas properties and cash dividend payments to our common stockholders. As of June 30, 2022, working capital was $6.1 million, a decrease of $5.4 million from working capital of $11.5 million as of June 30, 2021.

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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 $21.3 million drawn as of June 30, 2022. Since year-end, we have paid down another $9.0 million under our Senior Secured Credit Facility and as of August 31, 2022, we have $12.3 million outstanding. The Senior Secured Credit Facility is secured by substantially all of our reserves associated with our oil and natural gas properties and matures on April 9, 2024.

Any future borrowings bear interest, at our option, at either the London Interbank Offered Rate (“LIBOR”) plus 2.75% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. 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 and events of default. As of June 30, 2022, we were in compliance with all covenants under the Senior Secured Credit Facility.

We are currently working on our annual redetermination with MidFirst Bank. We expect that our borrowing base will remain at $50.0 million and the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, will be set at $125.0 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. Based on the current amount outstanding, the utilization percentage under the required hedging covenant is below the minimum utilization threshold of 25% and as a result we are not required to enter into additional hedges at this time. 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 defined in the agreement, to the extent it exceeds the borrowing base then in effect. This amendment also required us to enter into hedges for the next 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 the Ninth Amendment, as discussed above.

On August 5, 2021, we entered into the Seventh Amendment of our Senior Secured Credit Facility which, among other things, added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the consolidated tangible net worth covenant level was reduced to $40.0 million from $50.0 million.

We have historically funded operations through cash from operations and working capital. The 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 manage near-future development activities for our properties with cash flows from operating activities and existing working capital.

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. 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.

The Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 35 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

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dividends over time, as appropriate. During the industry downturn primarily due to COVID-19, effective in the quarter ended June 30, 2020, the Board of Directors adjusted the quarterly dividend rate from $0.10 per share to $0.025 per share. The reduction in the dividend rate at that time allowed us to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield of approximately 3% at the then current stock price levels. In light of our improving financial performance and industry outlook, the Board of Directors has since increased the dividend rate, with the most recent increase occurring on September 12, 2022, when the Board of Directors declared a dividend of $0.12 per share payable on September 30, 2022.

Also, on September 8, 2022, our Board of Directors authorized a share repurchase program, under which we are approved to repurchase up to $25 million of our common stock 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. Refer to Note 15, “Subsequent Events,” for a further discussion of our share repurchase program.

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Capital Expenditures

For the year ended June 30, 2022, we incurred $2.6 million on development capital expenditures, $26.4 million for the Jonah Field Acquisition (net of customary purchase price adjustments, excluding $3.0 million in non-cash asset retirement obligations), and $25.2 million for the Williston Basin Acquisition (net of customary purchase price adjustments, excluding $2.4 million in non-cash asset retirement obligations) and less than $0.1 million at the Delhi Field and Hamilton Dome Field, for plugging and abandoning costs.

Based on discussions with our operators, we expect capital workover projects to continue in all the fields. At Delhi Field, we anticipate capital costs for a NGL plant heat exchanger project which is currently underway. Overall, for fiscal year 2023, we expect budgeted capital expenditures to be in the range of $6.5 million to $9.5 million, which excludes any potential acquisitions. Our expected capital expenditures for the next 12 months include Foundation, the operator of our Williston Basin properties, drilling two sidetrack locations targeting the Birdbear formation. Our fiscal year 2023 budget does not include any capital expenditures for drilling at our Pronghorn and Three Forks locations.

As of June 30, 2022, our PUD reserves included 3.6 MMBOE of reserves and approximately $61.7 million of future development costs associated with the Williston Basin properties.

Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations and current working capital, as well as borrowings under our Senior Secured Credit Facility as needed for future acquisitions or development of PUD reserves at our Pronghorn and Three Forks locations.

Full Cost Pool Ceiling Test

As of June 30, 2022, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling; however, we could experience an impairment if commodity price levels were to substantially decline. Lower commodity prices would reduce the excess, or cushion, of our valuation ceiling over our capitalized costs and may 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. 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, 2022 were $85.82 per barrel of oil, $5.19 per MMBtu of natural gas and $44.24 per barrel of NGLs. At December 31, 2020 and September 30, 2020, we recorded ceiling test impairment charges of $15.2 million and $9.6 million, respectively. The ceiling test impairments were driven by decreases in the first-day-of-the-month average price for oil used in the ceiling test calculation. At June 30, 2022, a 10% decrease in commodity

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prices used to determine our proved reserves would not have resulted in an impairment of our oil and natural gas properties.

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Overview of Cash Flow Activities

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Cash provided by operating activities increased $47.7 million during the fiscal year ended June 30, 2022 compared to fiscal year ended June 30, 2021 primarily due to an increased average daily production and an approximate $13.26 per BOE average realized price increase which both contributed to higher revenues in fiscal year 2022.

Cash used in investing activities increased $36.1 million primarily due to the acquisition of the Jonah Field properties in April 2022 totaling $26.4 million (net of customary purchase price adjustments) and Williston Basin properties in January 2022 totaling $25.8 million (net of customary purchase price adjustments), compared to the acquisition of the Barnett Shale properties in May 2021 for $18.3 million (net of customary purchase price adjustments). In addition, capital expenditures increased $1.0 million in fiscal year 2022 due to increased capital workovers for certain return-to-production projects now viable with the increase in commodity prices.

Net cash flows provided by financing activities were $5.4 million for the year ended June 30, 2022, compared to $0.3 million of net cash flows used in financing activities for the year ended June 30, 2021. As of June 30, 2021, we had borrowings of $4.0 million outstanding under our Senior Secured Credit Facility. During the year ended June 30, 2022, we increased these borrowings by a net $17.3 million, ending the year with $21.3 million outstanding under the Senior Secured Credit Facility. In fiscal year 2022, we used cash of $11.8 million for dividends paid to our common stockholders compared to $4.3 million in fiscal year 2021.

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Results of Operations

Years Ended June 30, 2022 and 2021

We reported net income of $32.6 million for the year ended June 30, 2022 compared to a net loss of $16.4 million for the year ended June 30, 2021. The following table summarizes the comparison of financial information for the periods presented:

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Revenues

Fiscal year ended June 30, 2022 revenues increased 233.1% to $108.9 million compared to $32.7 million for the fiscal year ended June 30, 2021. The increase in revenue is primarily due to a 145% increase in average daily equivalent production from 2,430 BOEPD to 5,953 BOEPD due the addition of the Jonah Field Acquisition in April 2022, Williston Basin Acquisition in January 2022, and Barnett Shale Acquisition in May 2021, which increased current fiscal year production by approximately 518 BOEPD, 241 BOEPD, and 2,847 BOEPD, respectively. In addition, our average realized commodity prices (excluding the impact of derivative contracts) increased approximately $13.26 per BOE, or 36%, for the fiscal year ended June 30, 2022 compared to June 30, 2021. Oil and natural gas prices are inherently volatile and began to stabilize in 2021 and continuing into 2022. Our average realized oil price was higher primarily due to the recovery of WTI pricing in 2022, as the demand for oil has begun to recover primarily as a result of the roll-out of the COVID -19 vaccines, lessening of pandemic related government restrictions on individuals and businesses, and sanctions affecting Russian oil and natural gas supplies.

Lease Operating Costs

The following table summarizes CO2 costs per Mcf and CO2 volumes for the years ended June 30, 2022 and 2021. 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.

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The $4.6 million increase in CO2 costs for the fiscal year ended June 30, 2022 was primarily due to a 68.2% increase in purchased CO2 volumes combined with a 50.7% increase in CO2 costs per MCF, which was driven by a 78.8% increase in our average realized oil price. The increase in purchased CO2 volumes is due to the completion of preventative maintenance on the pipeline that supplies newly purchased CO2 to the Delhi Field which resulted in temporary suspension of CO2 purchases for the three months ended September 30, 2021. Additionally, CO2 purchase nominations increased throughout fiscal year 2022 to compensate for reduced reservoir pressure. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. The pipeline is owned and operated by Denbury and we do not have any ownership in the pipeline. On a per unit basis, CO2 costs were $3.55 per BOE and $3.45 per BOE for the years ended June 30, 2022 and 2021, respectively.

Ad valorem and production taxes were $7.0 million and $1.3 million for the years ended June 30, 2022 and 2021, respectively. On a per unit basis, ad valorem and production taxes were $3.20 per BOE and $1.44 per BOE for the years ended June 30, 2022 and 2021, respectively. The increase in ad valorem and production taxes is primarily due to increases in oil and natural gas prices and increased production volumes described above as production taxes are based on sales at the wellhead.

Compared to fiscal year ended June 30, 2021, other lease operating costs increased 177.6% primarily due to the Jonah Field Acquisition in April 2022, Williston Basin Acquisition in January 2022 and Barnett Shale Acquisition in May 2021. Other lease operating costs per BOE for our Jonah Field, Williston Basin and Barnett Shale properties were approximately $10.69 per BOE, $21.86 per BOE and $14.70 per BOE, respectively, for the years ended June 30, 2022. Other lease operating costs for the Delhi and Hamilton Dome fields increased $0.8 million and $0.9 million, respectively, due to higher labor, electricity and chemical expenses during the year ended June 30, 2022.

Depletion expense increased $2.6 million or 53.3% from $4.9 million for the fiscal year ended June 30, 2021 to $7.5 million for the fiscal year ended June 30, 2022 primarily due to an increase in production. On a per unit basis, depletion expense was $3.46 per BOE and $5.53 per BOE for the fiscal years ended June 30, 2022 and 2021, respectively. The integration of the Jonah Field properties in April 2022, Williston Basin properties in January 2022, and Barnett Shale properties in May 2021 together with the ceiling test impairments recorded during the fiscal year ended June 30, 2021 contributed to the overall lower composite depletion per BOE rate for the year ended June 30, 2022.

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Impairment of Proved Property

We utilize the full cost method of accounting for our oil and natural gas properties 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 included in the amortization base, plus the cost of unproved properties excluded from amortization, as adjusted for related income tax effects (the valuation “ceiling”). As of June 30, 2022, our net book value of oil and natural gas properties did not exceed the current ceiling. During the fiscal year ended June 30, 2021, we recorded a proved property impairment of $24.8 million primarily as a result of the decline in the price of oil over the historical 12-month period.

Impairment of Well Lift Inc. - Related Expenses

Our royalty rights and investment in Well Lift, Inc. (“WLI”) resulted from the separation of our artificial lift technology operations in December 2015. We conveyed our patents and other intellectual property to WLI and retained a 5% royalty on future gross revenues associated with the technology. We own approximately 18% of the common stock and 100% of the preferred stock of WLI and account for our investment in this private company at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer, if such were to occur. We evaluate the investment for impairment when we identify any events or changes in circumstances that might have a significant adverse effect on the fair value of the investment. As of March 31, 2021, we reviewed our investment in WLI for potential impairment and, as a result, recorded an impairment expense of $0.1 million. This impairment charge was recorded based on a variety of factors including the level of activity associated with this technology.

General and Administrative Expenses

General and administrative expenses for the fiscal year ended June 30, 2022 increased $1.2 million, or 22.1%, to $6.7 million compared to $5.5 million for the fiscal year ended June 30, 2021. The increase is primarily due to approximately $0.2 million for salary and employee benefits due to additional personnel, $0.3 million in severance, $0.2 million for professional fees related to increased accounting services as a result of the Jonah Field Acquisition, the Williston Basin Acquisition and the Barnett Shale Acquisition, and $0.3 million for increased business development activity. On a per unit basis, general and administrative expenses decreased $3.11 per BOE to $3.09 per BOE for the year ended June 30, 2022 from $6.20 per BOE for the prior year. The decrease in general and administrative expenses on a per unit basis are due to the increased production volumes described above.

Stock-based Compensation Expenses

Stock-based compensation decreased $1.1 million, or 90%, to $0.1 million for the year ended June 30, 2022 compared to $1.3 million the prior period due to a $1.2 million reduction in current period expense related to the forfeiture of unvested shares in connection with severance.

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. As a result of the Williston Basin Acquisition in January 2022 and Jonah Field Acquisition in April 2022, we were required by the terms of our Senior Secured Credit Facility to hedge a portion of our production. The increase in commodity prices since entering into the hedges resulted in a realized loss on hedges for the year ended June 30, 2022 and an unrealized loss due to the mark-to-market value of

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remaining hedges. Certain of our hedges begin to expire in October 2022 with our final hedges expiring March 2023. As of June 30, 2022, we had a $0.2 million derivative asset all of which was classified as current, and a $2.2 million derivative liability, all of which was classified as current.

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Interest Expense

Interest expense increased $0.5 million during the fiscal year ended June 30, 2022 compared to fiscal year 2021 primarily due to the increased borrowings outstanding on our Senior Secured Credit Facility due to our acquisitions throughout the year.

Income tax (expense) provision

For the year ended June 30, 2022, we recognized income tax expense of $8.5 million on net income before income taxes of $41.1 million compared to an income tax benefit of $5.0 million on net loss before income taxes of $21.4 million for the year ended June 30, 2021.

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, 2022, 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.

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Estimates of Proved Reserves.    The estimated quantities of proved oil and natural gas reserves have a significant impact on the underlying financial statements. The estimated quantities of proved reserves are used to calculate depletion expense and the estimated future net cash flows associated with those proved reserves is the basis for determining impairment under the quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex and requires significant decisions in the evaluation of all available geologic, geophysical, engineering, and economic data. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information; this includes reservoir performance, additional development activity, new geologic and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates prepared by our third-party independent engineers represent the most accurate assessments possible, the subjective decisions and variances in available data for the properties make these estimates generally less precise than other estimates included in our financial statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect our estimated future net cash flows of our proved reserves. These changes could affect our quarterly ceiling test calculation and could significantly affect our depletion rate. A 10% decrease in commodity prices used to determine our proved reserves as of June 30, 2022 would not have resulted in an impairment of our oil and natural gas properties. Holding all other factors constant, a reduction our proved reserve estimates at June 30, 2022 of 10% would affect depletion, depreciation, and amortization expense by approximately $0.4 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.

Valuation of Deferred Tax Assets.   We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared or filed; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carry backs and carry forwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets. If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover; this would result in an increase to our income tax expense. The deferred tax asset and valuation allowance of $0.1 million related to the portion of the NOLs that are limited by IRC Section 382 were written off during the year ended June 30, 2022.

Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making the assessment of the ultimate realization of deferred tax assets. The Company has historically established a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods, based upon the level of historical taxable income and projections for future taxable income over the periods for which the deferred tax assets are deductible. At the time of this report, we have not recorded a valuation allowance for our expected inability to realize the future benefits of certain federal and state deferred tax assets as further discussed in Note 7, “Income Taxes”.

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

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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 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

Executive Overview

General

Evolution Petroleum Corporation is an oil and natural gas company focused on delivering a sustainable dividend yield to its stockholders through the ownership, management, and development of oil and natural gas properties. In support of that objective, the Company's long-term goal is to build a diversified portfolio of oil and natural gas assets primarily through acquisitions, while seeking opportunities to maintain and increase production through selective development, production enhancements, and other exploitation efforts on its properties.

Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO2 enhanced oil recovery project, our interests in the Hamilton Dome field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, our interests in the Barnett Shale located in North Texas, a natural gas producing shale reservoir, and overriding royalty interests in two onshore central Texas wells.

Our interests in the Delhi field consist of a 23.9% working interest, with an associated 19.0% revenue interest and separate overriding royalty and mineral interests of 7.2% yielding a total net revenue interest of 26.2%. The field is operated by Denbury, a subsidiary of Denbury, Inc.

On November 1, 2019, the Company acquired mineral interests in the Hamilton Dome field consisting of a 23.5% working interest, with an associated 19.7% revenue interest (inclusive of a small overriding royalty interest). The field is operated by Merit, a private oil and natural gas company, who owns the vast majority of the remaining working interest in Hamilton Dome field. Our acquired interest in this field aligns with the Company's strategy of adding long-lived, low decline reserves expected to be supportive of our dividend over the long-term.

On May 7, 2021, the Company acquired non-operated working interests in the Barnett Shale consisting of approximately 21,000 net acres held by production across nine North Texas counties in the Barnett Shale. The acreage has an average working interest of 17.3% and associated average revenue interest of 14.2%. At the time of the Barnett Shale acquisition, approximately 90% of the wells acquired were operated by Blackbeard, while the remaining 10% were operated by the seven other operators. After the close of the Barnett Shale Acquisition, Blackbeard announced the sale of its interest to Diversified Energy, which closed in July of 2021. At present, Blackbeard is still the operator of the assets under a transition services agreement with Diversified Energy. However, after the transition, Diversified Energy will take over operations of the assets.

Highlights for our Fiscal Year 2021 and Operations Update

•Closed the Barnett Shale Acquisition on May 7, 2021 which included total proved reserves of 13.1 MMBOE as of June 30, 2021 as estimated by DeGolyer & MacNaughton (“D&M”), an independent reservoir engineering firm.

•Returned to shareholders $4.3 million in cash dividends in fiscal 2021. The Company has paid out to shareholders more than $74.5 million in cash dividends since inception of the dividend program in December 2013.

•Generated $3.7 million in operating income before impairments.

•Funded our fiscal year operations, capital expenditures, and dividends out of operating cash flow.

•Proved oil equivalent reserves at June 30, 2021 were 23.4 MMBOE, a 129% increase from the previous year primarily due to the acquisition of interests in the Barnett Shale in May 2021.

•We completed the NYMEX WTI oil swaps entered into during fiscal year 2020, and we have not entered into any new oil and gas derivatives as of June 30, 2021.

•Denbury, whose subsidiary operates the Delhi Field, emerged from bankruptcy on September 18, 2020 and returned to conformance projects with a refreshed capital budget after a period of no conformance spending.

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Oil & Natural Gas Liquids Reserves (based on SEC NYMEX WTI oil price of $49.72 per barrel)

Proved oil equivalent reserves at June 30, 2021 were 23.4 MMBOE, a 129% increase from the previous year primarily due to the acquisition of interests in the Barnett Shale in May 2021. The Standardized Measure for proved reserves increased 40% to $87.6 million, primarily due to the acquisition of interests in the Barnett Shale and an increase in the SEC mandated trailing twelve month average first day of the month net oil price from $46.37 per barrel of oil and $9.00 per barrel of natural gas liquids (we did not have natural gas reserves as of June 30, 2020) at June 30, 2020 to $49.72 per barrel of oil, $19.81 per barrel of natural gas liquids and $2.46 per MMBtu of natural gas at June 30, 2021. Our proved reserves consist of 36% oil, 29% natural gas liquids and 35% natural gas, 92% are classified as proved developed producing and 8% are proved undeveloped.

The following table is a summary of our proved reserves as of June 30, 2021 and 2020:

Additional property and project information is included under Item 1 and in Note 6 and Note 20 to our consolidated financial statements in Item 8, and in Exhibit 99.1 of this Form 10-K.

Delhi Field

At June 30, 2021, we had total net proved reserves of 8.5 MMBOE compared to the prior year's 8.7 MMBOE, or a 3% decline in proved oil reserves. Fiscal year 2021 production of 0.5 MMBOE was partially offset by 0.3 MMBOE positive revisions primarily due to price increases.

Gross production at Delhi in the fourth quarter of fiscal 2021 was 5.1 MBOEPD, a 2% increase compared to 5.0 MBOEPD in the third fiscal quarter. Oil production was 4.1 MBOPD, which was flat compared to the third fiscal quarter’s 4.1 MBOPD. NGL production in the fourth quarter was 1.0 MBOEPD, an increase of 9% compared to third fiscal quarter's 0.9 MBOEPD. Annual oil production was significantly impacted by cessation of CO2 purchases when the CO2 purchase pipeline, upstream of the Delhi field, was shut-in for repairs in late February until October 2020 combined with constrained purchase volumes after the pipeline was returned to service. The loss of CO2 purchases, coupled with the decline in oil prices and bankruptcy filing, led to the operator electing to freeze non-essential capital projects through the end of calendar year 2020. During the fourth quarter of fiscal 2021, the operator resumed limited capital conformance projects within the field. We continue to monitor and evaluate the effectiveness of these projects.

The average oil price realized by Evolution at the Delhi field during the fourth quarter of fiscal 2021 was $64.68 compared to $56.02 during the previous quarter, an increase of 15%. The average NGL price realized by Evolution at the Delhi field during the fourth quarter of fiscal 2021 was $28.69 per barrel compared to $26.00 during the previous quarter, an increase of 10%. The increase was attributable to the broad recovery of commodity prices in fiscal fourth quarter. The uncertain demand outlook due to the ongoing COVID-19 pandemic has resulted in continued volatility in benchmark oil prices, with prices ranging from a low of a price of $58.73 per Bbl to a high of $74.21 per Bbl during our fiscal fourth quarter.

We historically have benefited from the premium that the Delhi field oil receives selling under Louisiana Light Sweet (“LLS”) pricing, as compared to the more widely known West Texas Intermediate (“WTI”) price. The LLS index correlates more closely to the Brent Crude oil price index (“Brent”) and, as such typically trades at a premium to the WTI index. Among other factors, the impacts of the COVID-19 pandemic caused global demand reduction and resulted in the Brent to WTI price spread to tighten, thus also resulting in a lower LLS to WTI price spread. In the fiscal fourth quarter 2021, the Delhi field realized a discount to WTI of $1.51, after deducting marketing and transportation costs. Oil produced from the Delhi field is shipped to market directly by pipeline, the most cost-effective means of transportation from the field. In addition, our received NGL price for royalty production varies because our royalty interests are burdened by a capital recovery charge, which is mostly offset by our working interest share that is reflected as a reduction in lease operating expense.

Our overall lifting costs per BOE for the year were $18.80 per BOE, which increased 14% from $16.50 per BOE in the prior year. Gross CO2 purchase volume rates for fiscal 2021 averaged 49.1 MMcf per day, compared to 51.9 MMcf per day in the prior year, a 5% decrease primarily due to the Delhi CO2 purchase pipeline shut-in for repairs. This decrease together with a 8% lower price per MCF resulted in a 13% decrease in CO2 cost compared to the prior year. Our cost of purchased CO2, the largest

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single component of operating costs at Delhi, is directly tied to the price of oil sold from the field. Other lease operating expenses for fiscal 2021 decreased 10% compared to the prior year, primarily due to lower fuel gas, parts and workover expenses. The decrease in CO2 cost and other lease operating expenses, paired with a decrease in production of 22% for the current year, resulted in the increase in lifting costs per BOE.

For fiscal 2021, our gross NGL production was 1.0 MBOEPD, which sold at an average price of $21.36 per barrel, compared to prior year gross production of 1.1 MBOEPD for which we realized $9.59 per barrel. In addition, the previously mentioned the capital recovery charge affects the NGL price in that if oil prices are below a realized NGL price of $60, the Company's royalty interests in Delhi do not benefit from NGL sales, partially offset by a reduction in the plant operating costs representing our working interest share of the cost recovery fee. This contributed to a lower price per barrel in the prior fiscal year, and the higher price per barrel in fiscal year 2021. Production from the NGL plant is transported by truck to a processing plant in East Texas, and therefore bears a material transportation charge. Our current mix of products is very rich, containing higher value NGLs, such as pentanes and butane. Historically, NGL demand has had a seasonal pattern with prices tending to be higher in the cooler months of the year. Accordingly, the relationship between NGL prices and WTI has fluctuated over time and we expect such volatility to continue in the future.

The NGL plant includes a gas turbine driven generator that converts methane and part of the ethane processed by the plant into electricity. This turbine generates power primarily for the NGL plant and supplies excess power to the CO2 recycle facility. The NGL plant is accomplishing its primary objective of removing the lighter, smaller chain hydrocarbons, thereby increasing the purity of the CO2 recycle stream and improving the efficiency of the CO2 flood throughout the field. Over time, the NGL plant is expected to increase and enhance the recovery of oil in the field. The NGL plant is not only providing feedstock to power the electric turbine, it is also producing significant quantities of higher value NGLs to sell to market.

Remaining estimated capital expenditures for our proved undeveloped reserves amount to approximately $6.44 per BOE of PUD reserves for Phase V. Looking forward, the timing of plans for continued development of the eastern part of the Delhi field are dependent on the operator’s schedule for capital allocation within their portfolio but is projected to occur in the next few years. Development of unquantified volumes is dependent upon the timing of excess capacity within the processing plant and oil price. Over the past decade, we, along with the operator, have invested significant resources and capital demonstrating our commitment to the development of the Delhi field and believe that we will collectively continue to do so.

Hamilton Dome

At June 30, 2021, we had total net proved reserves of 1.9 MMBOE, entirely comprised of oil, compared to prior year net proved reserves of 1.5 MMBOE. The positive revision of 0.4 MMBOE, or 26%, in proved oil reserves is primarily related to improved oil pricing, decreased expenses and restoration of shut-in production from the global pandemic.

Gross oil production at Hamilton Dome in the fourth quarter of fiscal 2021 was 2,035 BOPD, a 3% increase compared to 1,985 BOPD in the third fiscal quarter due to the operator restoring previously shut-in production and maintenance within the field. There were limited capital expenditures in the field during fiscal 2021 due primarily to the decrease in oil prices. Most projects in the field focused on maintenance or restoring shut-in production.

The average oil price realized by Evolution at Hamilton Dome during the fourth quarter was $55.93 compared to $46.61 during the previous quarter, an increase of 20% attributable to the recovery in commodity prices in the fiscal fourth quarter. Production from this field is transported by pipeline to customers and is priced on the Western Canadian Select index, which generally trades at a discount to WTI. In the fourth quarter, our realized price reflected a $7.58 per barrel discount from the WTI price. For fiscal 2021, realized oil price averaged $42.28 compared to $29.19 for the prior year. For this fiscal year, our lifting costs at Hamilton Dome averaged $28.57 per barrel.

Barnett Shale

At June 30, 2021, we had total net proved reserves of 13.1 MMBOE, comprised of 62% natural gas, 37% natural gas liquids, and 1% oil as estimated by our independent petroleum engineering firm D&M. The Barnett Shale asset was acquired on May 7, 2021.

Blackbeard, the primary Barnett Shale operator has yet to formalize a budget, as they are currently under a transition services agreement with Diversified Energy following the sale of their interests to Diversified Energy in July 2021. Diversified Energy has expressed interest in identifying and performing remedial workovers to maintain and restore production.

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Impact of Geopolitical Factors and the COVID-19 Pandemic

On March 11, 2020, the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States of America declared a national emergency with respect to COVID-19. The virus has continued to spread in the United States of America and abroad. National, state, and local authorities continue to recommend social distancing, imposed quarantine and isolation measures, as well as periodic business closures on large portions of the population as the Delta variant of COVID-19 has emerged in the current fiscal year. These measures, while intended to protect human life, are expected to have continued impacts on domestic and foreign economies, potentially resulting in the volatility of commodity prices. The effectiveness of economic stabilization efforts, including government payments to affected citizens and industries, is uncertain.

Currently, all of the Company’s property interests are not operated by the Company and involve other third-party working interest owners. As a result, the Company has limited ability to influence or control the operation or future development of such properties. In light of the current price and economic environment, the Company continues to be proactive with its third-party operators to review spending and alter plans as appropriate.

The Company is focused on maintaining its operations and system of controls remotely and has implemented its business continuity plans in order to allow its employees to securely work from home. The Company was able to transition the operation of its business with minimal disruption and to maintain its system of internal controls and procedures.

Liquidity and Capital Resources

At June 30, 2021, we had $5.3 million in cash and cash equivalents, primarily impacted by the $18.3 million purchase (net of preliminary purchase price adjustments and $2.8 million in non-cash asset retirement obligations) of certain mineral interests in the Barnett Shale in May 2021, compared to $19.7 million of cash and cash equivalents at June 30, 2020.

In addition, the Company has a senior secured reserve-based credit facility (the “Facility”) with a maximum capacity of $50 million subject to a borrowing base determined by the lender based on the value of our oil and gas properties. The Facility had a $30 million borrowing base, with $4 million drawn as of June 30, 2021. The borrowing base does not yet include any portion of the Barnett Shale properties. There are $4 million in borrowings outstanding under the Facility, which matures on April 9, 2024. The Facility is secured by substantially all of the reserves associated with the Company's assets.

Any future borrowings bear interest, at the Company's option, at either the London Interbank Offered Rate (“LIBOR”) plus 2.75% or the Prime Rate, as defined under the Facility, plus 1.0%. The Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not more than 3.0 to 1.0, (ii) a current ratio of not less than 1.0 to 1.0, and (iii) a consolidated tangible net worth of not less than $40 million, each as defined in the Facility. The Facility also contains other customary affirmative and negative covenants and events of default. As of June 30, 2021, the Company was in compliance with all covenants contained in the Facility.

On August 5, 2021, and effective as of June 30, 2021, we entered into the seventh amendment of our Senior Secured Credit Facility which added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the Consolidated Tangible Net Worth was reduced to $40 million from $50 million.

The Company has historically funded operations through cash from operations and working capital. The primary source of cash is the sale of produced oil, natural gas, and natural gas liquids. A portion of these cash flows is used to fund capital expenditures. The Company expects to manage future development activities in the Delhi field and the limited capital maintenance requirements of the Hamilton Dome field and Barnett Shale assets within the boundaries of its operating cash flow and existing working capital.

The Company is pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, the Company has access to the undrawn portion of the borrowing base available under its senior secured credit facility. The Company also has an effective shelf registration statement with the SEC under which the Company may issue up to $500 million of new debt or equity securities.

During the fiscal year ended June 30, 2021, the Company funded operations, capital expenditures, and cash dividends with cash generated from operations resulting in a decrease of $14.4 million in cash. Uses of cash included the acquisition of the Barnett Shale assets ($18.3 million) and cash dividends on common shares ($4.3 million). As of June 30, 2021, working capital was $11.5 million, a decrease of $9.5 million from working capital of $21.0 million at June 30, 2020.

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The Board of Directors instituted a cash dividend on common stock in December 2013. The Company has since paid 31 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 the Company’s financial strategy, and it is the Company's long-term goal to increase dividends over time, as appropriate. During the industry downturn, effective in the quarter ended June 30, 2020, the Board of Directors adjusted the quarterly dividend rate from $0.10 per share to $0.025 per share. The reduction in the dividend rate at that time allowed the Company to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield of approximately 3% at stock price levels. On February 2, 2021, considering an improving industry outlook, the Board of Directors increased the dividend rate from $0.025 per share to $0.03 per share effective in the quarter ended March 31, 2021. On May 7, the Board of Directors further increased the dividend rate to $0.05 per share effective in the quarter ended June 30, 2021 due to improved industry conditions and the Barnett Shale acquisition. As in the past, the Company intends to consider higher dividend levels as warranted by industry conditions and any future accretive acquisitions.

Capital Expenditures

For the year ended June 30, 2021, we incurred $21.7 million on capital projects consisting of $21.1 million for the acquisition of Barnett Shale assets (gross of preliminary purchase price adjustments and $2.8 million in non-cash asset retirement obligations) and $0.6 million at the Delhi field (primarily for plugging costs and capital conformance work).

Based on discussions with the Delhi and Hamilton Dome operators, we expect to continue to perform conformance workover projects and will likely incur additional maintenance capital expenditures at Delhi and will resume projects at Hamilton Dome. Such amounts are not known or approved but we expect such expenditures to be in the range of $0.9 million to $1.5 million over the next 12 months. In addition, we have planned for Delhi Phase V development expenditures of approximately $1.9 million to be incurred in the fourth quarter of our fiscal 2023. Phase V development expenditures are expected to total $8.6 million with $3.7 million to be incurred in fiscal 2024 and the remainder over the following two years.

Our proved undeveloped reserves are associated only with the Delhi field. At June 30, 2021, our proved undeveloped reserves included 1.86 MMBOE of reserves and approximately $8.6 million of future development costs associated with Phase V development in the eastern portion of the Delhi field. Such development requires participation by both the operator and the Company. Although we expect drilling to commence in fiscal 2023, the timing of Phase V is dependent on the field operator's available funds, capital spending plans, and priorities within its portfolio of properties.

Funding for our anticipated capital expenditures over the next 24 months is expected to be met from cash flows from operations and current working capital.

Full Cost Pool Ceiling Test

At June 30, 2021, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling; however, we could experience an impairment if current price levels worsen. Lower oil prices would reduce the excess, or cushion, of our valuation ceiling over our capitalized costs and may 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. Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated DD&A 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 at June 30, 2021 were $49.72 per barrel of oil, $2.46 per MMBtu of natural gas and $19.81 per barrel of natural gas liquids. At December 31, 2020 and September 30, 2020, the Company recorded ceiling test impairment charges of $15.2 million and $9.6 million, respectively. The ceiling test impairments were driven by decreases in the first-day-of-the-month average for oil used in the ceiling test calculation as outlined below. As of June 30, 2021, a 10% decrease in commodity prices used to determine our proved reserves would not have resulted in an impairment of our oil and natural gas properties.

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Overview of Cash Flow Activities

The table below compares a summary of our consolidated statements of cash flows for year ended June 30, 2021 and 2020.

Cash provided by operating activities in the current year decreased $7.7 million compared to fiscal 2020. The difference is primarily the result of a decrease in revenues compared to the prior year and the payments related to realized hedge settlement losses of $2.5 million.

Cash used in investing activities increased $7.7 million primarily due to the acquisition of the Barnett Shale assets in May 2021 for $18.3 million (net of preliminary purchase price adjustments and $2.8 million in non-cash asset retirement obligations) compared to the acquisition of Hamilton Dome field in November 2019 for $9.3 million. The increase is partially offset by a reduction in capital expenditures of $1.3 million in fiscal 2021 due to the decrease in conformance workover activities from lower oil prices.

Cash used in financing activities decreased year over year primarily related to the net borrowing of $4 million on the Senior Secured Credit Facility during fiscal 2021, and the reduction in cash paid for cash dividends as the Company paid $4.3 million in fiscal year 2021 and $10.7 million in fiscal year 2020. In addition, the Company paid $2.5 million more in fiscal year 2020 compared to fiscal year 2021 related to the Company's common share repurchase program.

Contractual Obligations and Other Commitments

The table below provides estimates of the timing of future payments that, as of June 30, 2021, we are obligated to make under our contractual obligations and commitments. We expect to fund these contractual obligations with cash on hand and cash generated from operations.

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Results of Operations

Years Ended June 30, 2021 and 2020

Revenues

The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the years ended June 30, 2021 and 2020. Fiscal 2020 includes eight months of Hamilton Dome production. Fiscal 2021 includes approximately two months of Barnett Shale production.

(a) Equivalent price per BOE has decreased in the current fiscal year despite a 6.3% increase in oil price per Bbl and a 122.7% increase in NGL price per Bbl. With the Barnett Shale Acquisition, the Company added significant natural gas sales compared to the prior year. Natural gas sales are realized at a lower price per BOE than oil and NGLs, and the Company’s total weighted average price per BOE declined by approximately 7% from the prior year.

n. m. Not meaningful.

Fiscal year 2021 revenues increased 10% compared to the prior fiscal year primarily due to increased realized commodity prices and the addition of the Barnett Shale Acquisition, which primarily drove the increase in natural gas and NGL sales revenues and production volumes compared to the prior fiscal year. This increase was partially offset by an 8% decrease in oil revenues primarily driven by an expected temporary increase in production decline and weaker price differentials in the Delhi field. The shut-in of the CO2 supply pipeline from late February 2020 through the end of October 2020, as discussed in “Lease Operating Costs” below, as well as a suspension of field conformance capital expenditures drove the expected temporary increase in production declines in the Delhi field. Purchased CO2 is necessary to maintain reservoir pressure and therefore achieve normal field performance. The shut-in of purchased CO2 volumes resulted in a decline in reservoir pressure and a temporary exacerbated production decline. The resumption of CO2 purchases during the current fiscal year is expected to gradually restore reservoir pressure and lead to a gradual increase in oil production rates. Also contributing to the decrease of production in the current fiscal year was the loss of production associated with the severe winter storm in February 2021. The Company’s average realized oil price was higher primarily due to the recovery of WTI pricing in 2021, as the demand for oil has begun to recover primarily as a result of the roll-out of the COVID -19 vaccines and concerns surrounding the perceived surplus of oil supplies has begun to retract.

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(Gain) Loss on Derivative Contracts

Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil prices. This amount represents the (i) (gain) loss 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. No positions remain outstanding as of June 30, 2021.

Lease Operating Costs

Lease operating costs (also referred to as production expenses) are presented in two components: (i) CO2 purchase costs for the Delhi field and (ii) other lease operating costs for both the Delhi, Hamilton Dome, and Barnett Shale fields.

(a) Under our contract with the 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.

The $0.4 million decrease in CO2 costs was due to a 5.4% decrease in rate of purchased volumes together with a 7.8% decrease in price per Mcf associated with the lower realized oil price. The upstream pipeline that supplies CO2 to the Delhi field was shut-in on February 22, 2020, when a pressure loss was detected. CO2 purchases were suspended until October 2020 for pipeline repairs. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. The recycle facilities continued to operate as usual during the purchase pipeline suspension. The pipeline is owned and operated by Denbury Inc, and the Company does not have any ownership in the portion of the pipeline that was repaired.

Compared to fiscal 2020, “Other lease operating costs” increased 35.2% primarily due to the additional four months of production costs at the Hamilton Dome field in fiscal 2021 compared to eight months of production costs in fiscal 2020 following acquisition in November 2019 and, to a lesser extent, the closing of the Barnett Shale Acquisition in May 2021. The Delhi field's “Other lease operating costs” decreased 10.5% impacted by cost control measures resulting from lower oil prices.

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Compared to fiscal 2020, Delhi field costs increased 14% to $18.80 per BOE of Delhi current year production primarily due to lower production volumes.

For fiscal 2021, Hamilton Dome field costs per BOE were $28.57, a decrease of 1.3% from fiscal year 2020 due to increased production and cost control measures implemented following the pandemic resulting from lower prices.

For fiscal 2021, Barnett Shale field costs per BOE were $12.61 compared to no field costs in the prior year as the Company completed the Barnett Shale Acquisition in the current fiscal year.

Depletion, Depreciation and Amortization (“DD&A”)

Total DD&A expense was 10.3% lower compared to the same one year-ago period due to an 12.3% decrease in the oil and natural gas DD&A amortization rate. The integration of the Barnett Shale assets together with the ceiling test impairments contributed to an overall lower composite DD&A per BOE rate. Additionally, accretion of asset retirement obligations increased 43.5% in the current fiscal year as a result of the asset retirement obligation additions from Barnett Shale Acquisition. Amortization of intangibles increased as a result of amortization of $37.3 thousand of our Well Lift, Inc. (“WLI”) assets during fiscal year 2021.