EVOLUTION PETROLEUM CORP

Note: SeeGlossary of Selected Petroleum Industry Terms starting on page iv.

General

Evolution Petroleum Corporation (“Evolution,” and together with its consolidated subsidiaries, the “Company”, “our”, “we, “us” or similar terms) 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. Our long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisition and through selective development opportunities, production enhancement, and other exploitation efforts on our oil and natural gas properties.

Recent Developments

Dividend Declaration

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

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 with approximately 300 associated potential drilling opportunities.

Senior Secured Credit Facility

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

For further discussion of this amendment and our Senior Secured Credit Facility, see “Liquidity and Capital Resources” within Item 7.Management’s Discussion and Analysis of Financial Conditions and Results of Operations.

Appointment of Chief Accounting Officer

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

Share Repurchase Program

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.

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

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

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

Business Strategy

Our business strategy is to maximize total shareholder return based on our assessment of the operating environment and marketplace, subject to our obligations to other stakeholders. The key elements of our strategy to accomplish our goal of maximizing shareholder return are:

Properties

Our oil and natural gas properties consist of non-operated interests in the following areas: the SCOOP and STACK plays of the Anadarko Basin located in central Oklahoma; the Chaveroo oilfield in Chaves and Roosevelt Counties of New Mexico; the Jonah Field in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome Field located in Hot Springs County, Wyoming; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana; as well as small overriding royalty interests in four onshore central Texas wells.

SCOOP/STACK – Central Oklahoma

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.

Average net daily production from the date of acquisition through June 30, 2024 was 1.4 MBOEPD. For the year ended June 30, 2024, our average net daily production from the SCOOP/STACK properties consisted of 47% natural gas, 37% oil, and 16% NGLs. Hydrocarbons produced from our SCOOP/STACK properties are sold to various purchasers throughout the mid-continent.

Chaveroo Field – Chaves and Roosevelt Counties, New Mexico

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”).

Average net daily production from the date of first production in February 2024 through June 30, 2024 was 0.2 MBOEPD. For the year ended June 30, 2024 our average net daily production from the Chaveroo Field properties consisted of 90% oil, 7% natural gas, and 3% NGLs. Oil produced from our Chaveroo Field properties is sold to various purchasers in New Mexico and gas and NGLs are sold to Targa Resources Corp.

Jonah Field – Sublette County, Wyoming

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 (“Jonah”).

For the year ended June 30, 2024 our average net daily production from the Jonah Field properties was 1.8 MBOEPD consisting of 89% natural gas, 6% NGLs, and 5% oil. Hydrocarbons produced from our Jonah Field properties are sold to West Coast markets.

Williston Basin – Williston, North Dakota

Our non-operated interests in the Williston Basin, oil and natural gas producing properties, 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 (“Foundation”).

For the year ended June 30, 2024, our average net daily production from the Willison Basin properties was 0.5 MBOEPD consisting of 81% oil, 11% NGLs, and 8% natural gas. The primary producing reservoirs are the Three Forks, Pronghorn, and Bakken formations. Hydrocarbons produced from the Williston Basin properties are sold to local refineries and purchasers.

Barnett Shale – North Texas

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) located on approximately 21,000 net acres held by production across nine North Texas counties (Bosque, Denton, Erath, Hill, Hood, Johnson, Parker, Somervell, and Tarrant), in the Barnett Shale. The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other operators.

For the year ended June 30, 2024, our average net daily production from the Barnett Shale properties was 2.6 MBOEPD consisting of 74% natural gas, 25% NGLs, and 1% oil. The producing reservoir is the Barnett Shale, which is also the source rock. Hydrocarbons produced from our Barnett Shale properties are sold to Gulf Coast markets.

Hamilton Dome – Hot Springs County, Wyoming

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 (“Merit”), a private oil and natural gas 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.

For the year ended June 30, 2024, our average net daily production from the Hamilton Dome Field properties was 0.4 MBOEPD consisting of 100% oil. The primary producing reservoirs in the field are the Tensleep and Phosphoria. Produced oil from the field is subject to Western Canadian Select pricing.

Delhi Field – Enhanced Oil Recovery CO 2 Flood – Onshore Louisiana

Our non-operated interests in the Delhi Field, a CO 2-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”), which was acquired by Exxon Mobil Corporation (“ExxonMobil”) on November 2, 2023. The unitized Delhi Field, of which we hold approximately 3,200 net acres, is located in northeast Louisiana in Franklin, Madison, and Richland Parishes.

For the year ended June 30, 2024, our average net daily production from the Delhi Field properties was 1.0 MBOEPD consisting of 78% oil and 22% NGLs. The primary producing reservoirs in the field are the Tuscaloosa and Paluxy formations. Produced oil from the field is priced off of Louisiana Light Sweet (“LLS”) crude, which often trades at a premium to West Texas Intermediate (“WTI”).

Refer to “Production volumes, average sales price and average production costs” table below for further information regarding our properties and their fiscal year results.

Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues

The Securities and Exchange Commission (“SEC”) sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies. These rules require disclosure of oil and natural gas proved reserves by significant geographic area, using the trailing 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, rather than year-end prices, and allows the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Subject to limited exceptions, the rules also require that proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years.

There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserves quantities and values must be viewed as being subject to significant change as more data about the properties becomes available.

Summary of Oil & Gas Reserves for Fiscal Year Ended 2024

Our proved reserves as of June 30, 2024, denominated in thousands of barrels of oil equivalent (“MBOE”), were estimated by our independent reservoir engineers, Netherland, Sewell & Associates, Inc. (“NSAI”), DeGolyer and MacNaughton (“D&M”) and Cawley, Gillespie and Associates, Inc. (“CG&A”), all worldwide petroleum consultants.

NSAI evaluated the reserves for our SCOOP/STACK, Jonah Field and Williston Basin properties. NSAI began evaluating these properties when we acquired each of them. The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.1 to this Annual Report on Form 10-K.

D&M evaluated the reserves for our Barnett Shale, Hamilton Dome, and Delhi Field properties. The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.2 to this Annual Report on Form 10-K.

CG&A evaluated the reserves for our Chaveroo Field properties. CG&A has a history with the field as it evaluates reserves for the operator of the field. The scope and results of their procedures are summarized in a letter from the firm, which is included as Exhibit 99.3 to this Annual Report on Form 10-K.

The following table sets forth our estimated proved reserves as of June 30, 2024. For additional reserve information, see ourSupplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial statements in Item 8.Financial Statements and Supplementary Data. The New York Mercantile Exchange (“NYMEX”) previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $79.45 per barrel of oil and $2.32 per MMBtu of natural gas. The net price per barrel of NGLs was $23.86, which does not have

any single comparable reference index price. The NGL price was based on historical prices received. For periods for which no historical price information was available, we used comparable pricing in the geographic area. Pricing differentials were applied based on quality, processing, transportation, location and other pricing aspects for each individual property and product.

Proved Reserves as of June 30, 2024

Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company’s Overall Reserve Estimation Process

Our policies regarding internal controls over reserves estimates require such estimates to be prepared by an independent petroleum engineering firm under the supervision of our internal reserve engineering team, which includes our Chief Operating Officer (“COO”), J. Mark Bunch. Our internal reserve engineering team has a combined experience of over 80 years in Petroleum Engineering. Our COO, the person responsible for overseeing the preparation of our reserves estimates, has a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University, is a registered Professional Engineer in the State of Texas (No. 86704), has over 40 years of oil and natural gas experience including large independents and financial firm services for projects and acquisitions. Our Board of Directors also has oversight of our reserve estimation process and contains a Reserves Committee with William Dozier, an independent director who is a Registered Professional Engineer in the State of Texas (No. 47279) with experience in energy company reserve evaluations. Such reserve estimates comply with generally accepted petroleum engineering and evaluation principles, definitions, and guidelines as established by the SEC.

The reserves information in this filing is based on estimates prepared by NSAI, D&M and CG&A. The person responsible for the preparation of the reserve report at NSAI is Matthew D. Pankey, P.E., Petroleum Engineer. Mr. Pankey, a licensed Professional Engineer in the State of Texas (No. 142931), has been practicing consulting petroleum engineering at NSAI since 2019 and has over six years of prior industry experience. Mr. Pankey received a Bachelor of Science degree in Chemical Engineering in 2012 from Auburn University. The person responsible for the preparation of the reserve report at D&M is Dr. Dilhan Ilk, P.E., Executive Vice President. Dr. Ilk received a Bachelor of Science degree in Petroleum Engineering in 2003 from Istanbul Technical University and a Master’s degree and Doctorate in Petroleum Engineering in 2005 and 2010, respectively, from Texas A&M University, and he has in excess of 14 years of experience in oil and natural gas reservoir studies and evaluations and is a licensed Professional Engineer in the state of Texas (No. 139334). The person responsible for the preparation of the reserve report at CG&A is W. Todd Brooker,

P.E., President. Mr. Brooker received a Bachelor of Science degree in Petroleum Engineering in 1989 from the University of Texas at Austin and is a registered Professional Engineer in the State of Texas (No. 83462). Mr. Brooker joined CG&A in 1992 and has over 30 years of experience in engineering and geological services.

We provide NSAI, D&M and CG&A with our property interests, production, current operating costs, current production prices, estimated abandonment costs and other information in order for them to prepare the reserve estimates. This information is reviewed by our senior management team and designated operations personnel to ensure accuracy and completeness of the data prior to submission to the reserve engineers. The scope and results of NSAI’s, D&M’s and CG&A’s procedures, as well as their professional qualifications, are summarized in the letters included as Exhibit 99.1, Exhibit 99.2 and Exhibit 99.3, respectively, to this Annual Report on Form 10-K.

Proved Undeveloped Reserves

During the year ended June 30, 2024 our proved undeveloped (“PUD”) reserves changed as follows:

Our PUD reserves were 7.7 MMBOE as of June 30, 2024, with related future development costs of approximately $90.5 million, which are primarily associated with the Williston Basin and Chaveroo Field and to a lesser extent our SCOOP/STACK properties, where we hold a smaller average net working interest, and the Delhi Field. Extensions of 4.5 MMBOE are primarily associated with new wells at SCOOP/STACK, subsequent to our acquisition, and Chaveroo Field. Transfers of 0.1 MMBOE are associated with two Delhi wells placed online during the first fiscal quarter of 2024. The net downward revisions were due primarily to adjustments made to the Williston Basin development plan. These adjustments include updated economic assumptions to drill and complete wells, changes to the specific well locations on the drilling plan based on continuous technical analysis of the acreage, and the development timing of the project that maximizes the efficiency of our capital projects. The positive revisions in natural gas and NGLs are associated with changes in type curves at SCOOP/STACK subsequent to our acquisition. Under SEC reporting requirements, our PUD reserves include only those reserves in which the Company has current plans to develop within five years. See “Drilling and Present Activities” below for a further discussion of our expected development of the PUDs associated with Williston Basin, Chaveroo Field, SCOOP/STACK and Delhi Field.

Drilling and Present Activities

Currently, none of our oil and natural gas properties are operated by us. We therefore rely on information from our operators regarding near-term drilling programs. There are no plans to drill new wells in fiscal year 2025 in the Jonah Field, the Barnett Shale, and the Hamilton Dome Field. At this time, operators of our properties at SCOOP/STACK, Williston Basin, Hamilton Dome Field and Delhi Field are periodically running workover rigs focusing on projects to return wells to production that have experienced mechanical issues.

At SCOOP/STACK, we currently expect 13 gross wells to be brought online during fiscal year 2025. Additionally, as our third-party operators continue to be active around our acreage, we would expect additional wells to be drilled and/or completed. At Chaveroo Field, the next development block is currently planned to begin drilling during the second quarter of fiscal 2025, with production estimated to commence during the second half of fiscal 2025. At the Williston Basin, we anticipate that fiscal year 2025 will be used to finalize permits, maximize economic efficiencies in vendor

contracts, and prepare for initiating a drilling program to exploit the Three Forks formation on our acreage. We envision production to begin in the second quarter of fiscal year 2026. At Delhi Field, the third-party operator is planning to drill three new wells within Test Site V. The first of these three new wells is expected to come online during the second half of fiscal 2025.

For further discussion, see “Capital Expenditures” within Item 7.Management’s Discussion and Analysis of Financial Conditions and Results of Operations.

Production volumes, average sales price and average production costs

The following table summarizes our crude oil, natural gas, and natural gas liquids production volumes, average sales price per unit and average daily production on an equivalent basis for the periods indicated:

The following table summarizes our production costs, and production costs per unit for the periods indicated:

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which we own a working interest as of June 30, 2024.

Acreage

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2024. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would allow production of oil and natural gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and natural gas in commercial quantities whether or not the acreage contains proved reserves.

The table below reflects our net undeveloped acreage in Williston Basin, North Dakota as of June 30, 2024 that will expire each year if we do not establish production in paying quantities on the units in which such acreage is included to maintain the lease:

Markets and Customers

Our production is marketed to third parties in a manner consistent with industry practices. In the United States market where our properties are operated, crude oil, natural gas, and NGLs are readily transportable and marketable. In the Jonah Field, we take our natural gas and NGL working interest production in-kind and market separately to purchasers on six-month contracts for natural gas and to Enterprise Products Partners L.P. for NGLs. We do not currently market our share of oil, natural gas, or NGLs production from any other field separately from the operators’ shares of production. Although we have the right to take our working interest production in-kind, we are currently selling our production through the field operators pursuant to the delivery and pricing terms of their sales contracts. Under such arrangements, we typically do not know the identity of the buyers.

As a non-operator, we are highly dependent on the success of our third-party operators and the decisions made in connection with their operations. With the exception of the Jonah Field, our third-party operators sell our oil, natural gas, and NGLs to purchasers, collect the cash, and distribute the cash to us. In the year ended June 30, 2024, four individual purchasers, Denbury, Diversified, Foundation, and Merit, each accounted for more than 10% of our total revenues, collectively representing approximately 69% of our total revenues for the year. In the year ended June 30, 2023, three individual purchasers, Diversified, Denbury, and Conoco Phillips, each accounted for more than 10% of our total revenues, collectively representing approximately 65% of our total revenues for the year.

The loss of a purchaser at any of our major producing properties or disruption to pipeline transportation from these fields could adversely affect our net realized pricing and potentially our near-term production levels.

Market Conditions

Prices we receive for crude oil, natural gas, and NGLs are influenced by many factors that are beyond our control, the exact effect of which is difficult to predict. These factors include changes in supply and demand, the relative strength of the U.S. dollar, government regulation, weather, and actions of major foreign producers.

Oil and natural gas prices over the past few years have been volatile and we expect that volatility to continue. Worldwide factors such as global health pandemics, geopolitical, international trade disruptions and tariffs, macroeconomics, supply and demand, refining capacity, petrochemical production, and derivatives trading, among others, influence prices for oil, natural gas, and NGLs. Local and domestic factors also influence prices for oil, natural gas, and NGLs and include increasing or decreasing production trends, quality differences, regulation, legislation and transportation issues unique to certain producing regions and reservoirs.

Competition

The oil and natural gas industry is highly competitive for prospects, acreage, and capital. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating

staff and greater capital resources. Competitors are national, regional, or local in scope and compete on the basis of financial resources, technical prowess or local knowledge. The principal competitive factors in our industry are expertise in given geographical areas and geologic systems and the ability to efficiently conduct operations, achieve technological advantages, identify and acquire economically producible reserves, and obtain capital at rates that allow economic investments.

Risk Management

We are exposed to certain risks relating to our ongoing business operations, including commodity price risk. In accordance with our company strategy and the covenants under the Senior Secured Credit Facility, derivative instruments are occasionally utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production. We do not enter into derivative contracts for speculative trading purposes.

While there are many different types of derivative instruments available, historically we have used costless collars, stand alone put options, and fixed-price swaps to attempt to manage price risk. Costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. All costless collar agreements provide for payments to counterparties if the settlement price under the agreement exceeds the ceiling and payments from the counterparties if the settlement price under the agreement is below the floor. Stand alone put options are floors that are purchased for a cost and provide that counterparties make payments to us if the settlement price is below the established floor. The fixed-price swap agreements call for payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under the fixed-price swap agreement.

It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. We will continue to evaluate the benefit of employing derivatives in the future. Our hedge strategies and objectives may change as our operational profile changes. See Item 7A.Quantitative and Qualitative Disclosures About Market Risk and Note 7,*“Derivatives”*to our consolidated financial statements in Item 8.Financial Statements and Supplementary Data for additional information.

Government Regulation

As an oil and natural gas exploration and production company, our interests are subject to numerous legal requirements.

Regulation of Oil and Natural Gas Production

Federal, state and local authorities have promulgated extensive rules covering oil and natural gas exploration, production and related operations. Those regulations require our third-party operator to obtain permits, post bonds and submit reports. They also may address conservation, including unitization or pooling of oil and natural gas properties, well locations, the method of drilling and casing wells, surface use and restoration of properties where wells are drilled, sourcing and disposal of water used in the process of drilling, completion and abandonment, the establishment of maximum rates of production from wells, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce and to limit the number of wells or the locations at which we can produce. Moreover, many states impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdictions. Failure to comply with any applicable legal requirements may result in substantial penalties. Because such regulations are frequently amended or reinterpreted, we are unable to predict future compliance costs or impacts. Significant expenditures may be required to comply with governmental laws and regulations, however, and may have a material adverse effect on our financial condition and results of operations.

Regulation of Transportation of Oil and Natural Gas

The prices for crude oil, condensate and natural gas liquids and natural gas are negotiated and not currently regulated. But Congress, which has been active in oil and natural gas regulation, could impose price controls in the future.

Our sales of crude oil and natural gas are affected by the availability, terms and cost of transportation. The Federal Energy Regulatory Commission (“FERC”) primarily regulates interstate oil and natural gas transportation rates. In some circumstances, FERC regulations also may affect intrastate pipelines. In addition, states may impose on intrastate pipelines various obligations relating to such matters as safety, environmental protection, nondiscriminatory take and pay rates. The basis for intrastate oil and natural gas pipeline regulation, and the degree of regulatory oversight and scrutiny given to such matters, vary from state to state. To the extent effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and natural gas transportation rates will not affect our business in any way that is of material difference from those of our competitors who are similarly situated.

Environmental Matters

Our properties are subject to extensive and changing federal, state and local laws and regulations relating to the protection of the environment, worker safety and human health. Such requirements may address:

Failure to comply with such requirements may result in a variety of sanctions, including fines, administrative orders and injunctions. In addition, issuing authorities may revoke, adversely condition or deny permits necessary for our operations. In the opinion of management, our properties are in substantial compliance with applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our company, as well as the oil and natural gas industry in general. Significant environmental requirements that may affect our operations are described below.

The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict liability, and in some cases joint and several liability, on owners and operators of sites and on persons who arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for neighboring landowners or other third parties to also file claims for personal injury and property damage allegedly caused by any hazardous substances released into the environment. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” our operations do entail handling other chemicals that may be subject to the statute. In addition, state laws affecting our properties may impose cleanup liability relating to petroleum and petroleum related products. The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste.” Violations may result in substantial fines. Although RCRA currently classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous, thereby subjecting our operations to more stringent handling and disposal requirements. In some circumstances, moreover, RCRA authorizes both the federal government and private persons to seek injunctions requiring the cleanup of wastes, whether hazardous or non-hazardous.

The Endangered Species Act (“ESA”) protects fish, wildlife and plants that are listed as threatened or endangered. Under the ESA, exploration and production operations may not significantly impair or jeopardize a protected species or its habitat. The ESA provides for criminal penalties for willful violations. Our operations also may be subject to other statutes that protect animals and plants such as the Migratory Bird Treaty Act. Although we believe that our properties are in compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject our company (directly or indirectly through our third-party operators) to significant expenses to modify operations, could force discontinuation of certain operations altogether and could limit the locations our third-party operators may utilize in the future.

The Clean Air Act (“CAA”) is the comprehensive federal law addressing sources of air emissions. Oil and natural gas production and natural gas processing operations are among the many source categories subject to the CAA. Regulated emissions from oil and natural gas operations include sulfur dioxide, volatile organic compounds (“VOCs”) and hazardous air pollutants such as benzene, among others.

In particular, the Environmental Protection Agency (“EPA”) announced regulations in December 2023 that impose more comprehensive restrictions on emissions of methane (a greenhouse gas) and VOCs from new, existing, and modified facilities in the oil and gas sector (such as wells and storage tank batteries). Among other things, the rule sets new emissions standards for certain equipment; requires routine monitoring for and repair of leaks at well sites, centralized production facilities, and compressor stations; limits flaring from existing oil wells; and prohibits flaring from new oil wells. EPA also established a “Super Emitter Program” to authorize third parties to detect “super emitter events” at operators’ sites and report them to EPA. The regulations do provide phase-in periods for certain requirements. And State plans for existing sources are due 24 months after the rule’s effective date. States can either adopt the rule’s presumptive standards or develop their own requirements that are at least as strict as EPA’s. These regulations or practices and any other new rules requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations and financial condition.

The Clean Water Act (the “CWA”) is the primary federal law controlling the discharge of produced waters and other pollutants into waters of the United States. Permits must be obtained for such discharges and to conduct construction activities in waters and wetlands. Some states also require permits for discharges or operations that may impact groundwater.

The CAA, CWA and comparable state statutes authorize civil, criminal and administrative penalties for violations. Further, the CWA and Oil Pollution Act may impose liability on owners or operators of onshore facilities that impact surface waters.

Pursuant to the Safe Drinking Water Act, EPA (or an authorized state) regulates the construction, operation, permitting, and closure of injection wells used to place oil and natural gas wastes and other fluids underground for enhanced hydrocarbon recovery, storage or disposal. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. Underground injection associated with oil and gas operations, particularly the disposal of produced water, has been linked in some cases to localized earthquakes. This in turn has led to new legislative and regulatory initiatives, which have the potential to restrict injection in certain wells or limit operations in certain areas.

Certain of the oil and natural gas production in which we have an interest is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection into the formation of water, sand and chemicals under pressure to stimulate production. From time to time, legislation has been proposed in the United States Congress to repeal the Safe Drinking Water Act’s exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting of hydraulic fracturing. If ever enacted, such legislation would add to costs for hydraulic fracturing.

Scrutiny of hydraulic fracturing activities continues in other ways. Several states where our properties are located have proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities likewise have enacted bans on hydraulic fracturing. We cannot predict whether any other legislation restricting hydraulic fracturing will be enacted and if so, what its provisions would be. If additional levels of regulation and permits were to be required through the adoption of new laws and regulations at the federal, state or local level, it could lead to delays, increased operating costs and process prohibitions that could materially adversely affect our revenue and results of operations.

The National Environmental Policy Act (“NEPA”) requires federal agencies to assess the environmental effects of their proposed actions prior to making decisions. Among the broad range of actions covered by NEPA are decisions on permit applications and federal land management. Many of the activities of our third-party operators involve federal decisions subject to NEPA. Such federal actions may trigger robust NEPA review, which could lead to delays and increased costs

that could materially adversely affect our revenues and results of operations. The Biden Administration reversed changes to NEPA rules enacted under the Trump Administration that had been intended to streamline NEPA review. The revised regulations lay the foundation for additional scrutiny of impacts on climate change, which could affect the assessment of projects ranging from oil and gas leasing to development on public and Indian lands.

Climate Change

Climate change has become a major public concern and policy issue in the United States and around the world. Much of the debate has focused on greenhouse gas (“GHG”) emissions from oil and natural gas, particularly carbon dioxide and methane.

In the United States, there is no comprehensive federal regulatory statute addressing climate change, although Congress does periodically consider such measures. At the federal level, the United States therefore has primarily addressed climate change through executive actions and regulatory initiatives pursuant to existing statutes. These include rejoining the Paris Agreement on climate change, the Biden Administration’s commitment to cut greenhouse gas emissions by 2030 to 50-52 percent of 2005 levels, various executive orders, limiting land available for oil and gas leasing, the United States Methane Emissions Reduction Action Plan (intended to reduce overall methane emissions by 30% below 2020 levels by 2030), and Clean Air Act rules (such as regulation announced in December 2023 to reduce methane emissions from the oil and gas sector). The SEC even promulgated new rules in 2024 that would require disclosure of various specific risks related to climate but promptly issued an order staying their applicability pending resolution of legal challenges. In addition, several states have already implemented or are considering programs to reduce GHG emissions. These include cap and trade programs, promotion of alternative forms of energy, transportation standards and restrictions on particular GHGs. New Mexico, for example, is requiring oil and gas operators to capture 98% of their produced natural gas by December 31, 2026, and is limiting most venting and flaring. To the extent that new climate change measures are adopted, our business may be adversely impacted.

In addition, recent court decisions have left open the question of whether tort claims alleging property damage may proceed under state common law against entities responsible for GHG emissions. Thus, there is some litigation risk for such claims.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG emitting energy sources, for example, our products would become more desirable in the market with more stringent limitations on GHG emissions. But in 2022, the United States enacted the Inflation Reduction Act that, among other things, creates a series of financial incentives intended to discourage use of oil and natural gas (including imposing a fee on methane emissions) and to promote alternative sources of energy. Pursuant to that Act, EPA announced a proposed rule in December 2023 that would implement the program for collecting the annual “Waste Emissions Charge” on certain excess methane emissions from oil and gas facilities. By statute, the charge would be $900 per metric ton of methane for 2024, $1,200 per metric ton for 2025, and $1,500 per metric ton each year thereafter. To the extent that our products are competing with lower GHG emitting energy sources such as solar and wind, our products may become less desirable in the market with such government intervention. We cannot predict with any certainty at this time how these possibilities may affect our operations.

Various studies on climate change indicate that extreme weather conditions and other risks may occur in the future in the areas where we operate. Although we have not experienced any material impact from such extreme conditions to date, no assurance can be given that they will not have a material adverse effect on our business in the future.

See discussion captioned “Government regulation and liability for oil and natural gas operations and environmental matters may adversely affect our business and results of operations” in Item 1A.Risk Factors.

Insurance

We maintain insurance on our oil and natural gas properties and operations for risks and in amounts customary in the industry. Such insurance includes, but is not limited to, general liability, excess liability, control of well, operators extra expense, casualty, fraud, and directors and officer’s liability coverage. Not all losses are insured, and we retain certain

risks of loss through deductibles, limits, and self-retentions. We do not carry business interruption or lost profits coverage.

Human Capital, Sustainability, and ESG

Employees

As of June 30, 2024, we had eleven full-time employees, not including contract personnel and outsourced service providers. Due to our current focus on non-operating properties, our staff is disproportionately weighted towards higher wage professionals. We believe that we have positive relations with our employees. Our team is broadly experienced in oil and natural gas operations, development, acquisitions, and financing. We follow a strategy of outsourcing most of our property accounting, human resources, administrative, and other non-core functions. For our full-time employees, our benefits package, as determined by our Board of Directors, includes medical, dental, and vision insurance, short-term disability, 401(k) contributions based on a portion of the employee’s base salary, short and long-term performance-based and service-based incentive pay (i.e., annual bonuses and stock awards), and paid time off.

Our workforce is provided with annual training and is expected to sign an acknowledgement regarding our policies and disclosures which include, but are not limited to, the Corporate Sustainability Report (“CSR”), employee handbook, human rights, code of ethics, health and safety, emergency procedures, conflicts of interest, insider trading, bribery, kickbacks, discrimination, diversity, equity, and inclusion.

Sustainability and ESG

In fiscal year 2023, we formed a Sustainability Committee which is responsible for overseeing our Environmental Social Governance (“ESG”) initiatives. In fiscal year 2021-2022, under the supervision of our Board of Directors, the Nominating and Corporate Governance committee, and senior management, the foundation of our sustainability efforts and CSR were led by an ESG Task Force. Evolution’s most recent CSR was published in November 2023. This report is accessible on our website at www.evolutionpetroleum.com.

The ESG Task Force formalized our existing ESG programs, proposed and implemented new ESG initiatives, monitored adherence to our internal and third-party sustainability standards, and provided public disclosures for our stakeholders. Each year, we continue to disclose, enhance, implement, and provide training for a number of new and existing policies and procedures. These include, but are not limited to: implementing a charitable donation program and employee volunteer initiatives, an annual company-wide ESG training program for both the Board of Directors and our workforce, implementation of safety inspections and health and safety coordinators, and incorporating ESG considerations into our compensation structure.

We are committed to high standards of conduct and ethics in order to contribute to the sustainability of our business. Our core values are the base to support our strategy and long-term success. We believe integrity is paramount and we are committed to developing and producing energy resources in environmentally, socially, and ethically respectful and responsible ways. Our people are critical to our success and as such we promote and maintain a safe and inclusive work environment. We strategically plan for the long-term and strive to maintain capital discipline, stakeholder transparency, and continuous focus on returning capital to shareholders.

We work with third-party operators that share our desire to operate and work responsibly, particularly for the natural environments in which they operate.

Denbury Inc., the operator of our Delhi Field property, and now a subsidiary of ExxonMobil, is an industry leader in Carbon Capture, Utilization and Storage with a network of CO 2 EOR operations and the United States’ largest operated system of CO 2 transmission pipelines. As of year-end 2022, Denbury reportedly injects over three million tons of captured industrial-sourced CO 2 annually, and has a goal to reach Net Zero for Scope 1, Scope 2 and Scope 3 CO 2 emissions by 2030, primarily through increasing the amount of captured industrial-sourced CO 2 used in their operations.

Jonah Energy, the operator of our Jonah Field property, is one of the leading sustainable natural gas producers in the U.S. In 2021, Jonah was the first and only U.S. company to achieve the Gold Standard Rating, announced by the United Nations Environment Programme International Methane Emissions Observatory.

As a non-operator of our current properties, we do not have direct control over environmental initiatives at a property-level. However, we believe it is important to partner with third-party operators that share our core values and are committed to being environmental stewards as they responsibly produce energy resources. We recognize that the expectations, requirements, and responsibilities of operators regarding safeguarding the environment and environmental stewardship continue to evolve. We are, and will continue to be, committed to supporting our third-party operators as they respond to these expectations, requirements, and responsibilities.

In fiscal year 2023, we implemented our first annual voluntary Environmental Operator Questionnaire to collect various environmental metrics on behalf of our third-party operators. In addition, we host regular operations meetings with our third-party operators in which we discuss asset level operations, expenses, any environmental issues and compliance, including ESG and health and safety related topics. The objectives of these endeavors are to obtain environmental data to better disclose the impact of operations, as well as to be better prepared to work with our operating partners in mitigating potential environmental impacts.

We report in our CSR the estimated Scope 1 and Scope 2 GHG emissions for our corporate office located in Houston, Texas. We are not required to and do not report Scope 1 GHG, or direct, emissions to the EPA as we are not the operator of our oil and natural gas properties, nor do we have financial control over our oil and natural gas properties and operations. We prefer to partner with third-party operators that work to reduce their Scope 1 GHG emissions, and we encourage them to accelerate their efforts as appropriate in this regard. Scope 2 GHG emissions are based on indirect emissions representing purchased electricity. We are one of many tenants leasing space in our corporate office building and do not know the actual amount of electricity used in our space. As such, we estimate our consumption by multiplying the electricity purchased for the entire building by the percentage of the floor area that we occupy. Water use is also reported in the CSR and is calculated in a similar fashion.

We maintain a hotline which operates 24/7/365 and allows anonymous and confidential reporting for employees, consultants, partners, and contractors, including the ability to report concerns or violations of our policies through the phone or internet (Phone: 877-628-7489 / Website: www.epm.alertline.com).

Additional Information

We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports with the SEC. Our reports filed with the SEC are available free of charge to the general public through our website at www.evolutionpetroleum.com. These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC. This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Corporate Secretary, 1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079, or calling (713) 935-0122. These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.