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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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For the fiscal year ended June 30, 2022

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For the transition period from                to

Commission File Number 001-32942

EVOLUTION PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

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1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079

(Address of principal executive offices and zip code)

(713) 935-0122

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

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Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes: ☐    No: ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes: ☐    No: ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes: ☒    No: ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes: ☒    No: ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definition of "large accelerated filer", "accelerated filer", "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.

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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes: ☐    No: ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates on December 31, 2021, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $5.05 on the NYSE American was $154.7 million.

The number of shares outstanding of the registrant’s common stock, par value $0.001, as of September 9, 2022, was 33,466,905.

DOCUMENTS INCORPORATED BY REFERENCE

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EVOLUTION PETROLEUM CORPORATION

2022 ANNUAL REPORT ON FORM 10-K

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We use the terms, “EPM,” “Company,” “we,” “us,” and “our” to refer to Evolution Petroleum Corporation, and unless the context otherwise requires, its wholly-owned subsidiaries.

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FORWARD-LOOKING STATEMENTS

This Form 10-K and the information referenced herein contains forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, except for statements of historical fact, that relate to the anticipated future activities, plans, strategies, objectives or expectations of the Company are forward-looking statements. The words “plan,” “expect,” “project,” “estimate,” “may,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words or phrases. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. Forward-looking statements include statements regarding: expectations of plans, strategies and objectives of the Company, including anticipated development activity and capital spending; the Company’s capital allocation strategy, capital structure, anticipated sources of funding, growth in long-term shareholder value and ability to preserve balance sheet strength; the benefits of the Company’s multi-basin portfolio, including operational and commodity flexibility; the Company’s ability to maximize cash flow and the application of excess cash flows to reduce long-term debt and to pay dividends and repurchase shares pursuant to its Share Repurchase Program; oil, natural gas and NGLs production and commodity mix, GHG emissions and ESG performance; anticipated oil, natural gas and NGL prices; anticipated drilling and completions activity; estimates of the Company’s oil, NGLs and natural gas reserves and recoverable quantities; future interest expense; the Company’s ability to access credit facilities and other sources of liquidity to meet financial obligations throughout commodity price cycles; the Company’s ability to manage debt and financial ratios, finance growth and comply with financial covenants; the implementation and outcomes of risk management programs, including exposure to commodity price and interest rate fluctuations, the volume of oil, NGLs and natural gas production hedged, and the markets or physical sales locations hedged; the impact of changes in federal, state, provincial and local, rules and regulations; anticipated compliance with current or proposed environmental legislation, including the costs thereof; adequacy of provisions for abandonment and site reclamation costs; the Company’s operational and financial flexibility, discipline and ability to respond to evolving market conditions; the declaration and payment of future dividends and any anticipated repurchase the Company’s outstanding common shares; the adequacy of the Company’s provision for taxes and legal claims; the Company’s ability to manage cost inflation and expected cost structures, including expected operating, transportation, processing and labor expenses; the competitiveness of the Company against its peers, including with respect to capital, materials, people, assets and production; oil, NGL and natural gas inventories and global demand for oil, NGL and natural gas; the outlook of the oil and natural gas industry generally, including impacts from changes to the geopolitical environment; anticipated staffing levels; anticipated payments related to the Company’s commitments, obligations and contingencies, and the ability to satisfy the same; and the possible impact of accounting and tax pronouncements, rule changes and standards.

Readers are cautioned against unduly relying on forward-looking statements which, by their nature, involve numerous assumptions and are subject to both known and unknown risks and uncertainties (many of which are beyond our control) that may cause such statements not to occur, or actual results to differ materially and/or adversely from those expressed or implied. These assumptions include: future commodity prices and basis differentials; the ability of the Company to access credit facilities and shelf prospectuses; assumptions contained in the Company’s corporate guidance; the availability of attractive commodity or financial hedges and the enforceability of risk management programs; expectations that counterparties will fulfill their obligations pursuant to gathering, processing, transportation and marketing agreements; access to adequate gathering, transportation, processing and storage facilities; assumed tax, royalty and regulatory regimes; expectations and projections made in light of, and generally consistent with, the Company’s historical experience and its perception of historical industry trends; and the other assumptions contained herein.

Readers are cautioned that the assumptions, risks and uncertainties referenced above, and in the other documents incorporated herein by reference (if any), are not exhaustive. Although the Company believes the expectations represented by its forward-looking statements are reasonable based on the information available to it as of the date such statements are made, forward-looking statements are only predictions and statements of our current beliefs and there can be no assurance that such expectations will prove to be correct.

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When considering any forward-looking statement, the reader should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in Part I, Item 1A. Risk Factors and elsewhere in this report and as also may be described from time to time in our future reports we file with the Securities and Exchange Commission. Readers should also consider such information in conjunction with our consolidated financial statements and related notes and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in this report. There also may be other factors that we cannot anticipate or that are not described in this report, generally because we do not currently perceive them to be material. Such factors could cause results to differ materially from our expectations.

Forward-looking statements speak only as of the date they are made, and we do not undertake to update these statements other than as required by law. Readers are advised, however, to review any further disclosures we make on related subjects in our periodic filings with the Securities and Exchange Commission.

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GLOSSARY OF SELECTED PETROLEUM INDUSTRY TERMS

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PART I

Item 1.   Business

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

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. 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, production enhancement, and other exploitation efforts on our oil and natural gas properties.

Recent Developments

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, 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. 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 common 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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Jonah Field Acquisition

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 was $26.4 million. 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 approximately 950 net acres. The properties are operated by Jonah Energy (“Jonah”), an established operator in the geographic region.

Williston Basin Acquisition

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 cash expenses related to the acquisition. The properties are operated by Foundation Energy Management (“Foundation”), an established operator in the geographic region.

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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:

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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; the Hamilton Dome Field located in Hot Springs County, Wyoming; the Barnett Shale located in North Texas; the Williston Basin in North Dakota; the Jonah Field in Sublette County, Wyoming; and small overriding royalty interests in four onshore central Texas wells.

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Delhi Field – Enhanced Oil Recovery CO₂ Flood – Onshore Louisiana

Our 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”), a subsidiary of Denbury Inc. 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.

For the year ended June 30, 2022, our average net daily production from the Delhi Field properties was 1.2 MBOE per day (“MBOEPD”) consisting of 81% oil and 19% natural gas liquids (“NGLs”). The primary producing reservoirs in the

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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").

Hamilton Dome –Hot Springs County, Wyoming

Our 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”), a private oil and natural gas 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.

For the year ended June 30, 2022, 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.

Barnett Shale - North Texas

On May 7, 2021, we acquired non-operated working interests in the Barnett Shale (the “Barnett Shale Acquisition”), a natural gas producing shale reservoir consisting of 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 acreage consists of an average net working interest of approximately 17% and associated average net revenue interest of approximately 14% (inclusive of small overriding royalty interests). The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by seven other operators.

For the year ended June 30, 2022, our average net daily production from the Barnett Shale properties was 3.5 MBOEPD consisting of 79% natural gas, 20% 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.

Williston Basin – Williston, North Dakota

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 properties are operated by Foundation, an established operator in the geographic region.

Average net daily production from the date of acquisition through June 30, 2022 was 0.5 MBOEPD. For the year ended June 30, 2022, our average net daily production from the Willison Basin properties consisted 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.

Jonah Field – Sublette County, Wyoming

On April 1, 2022, we acquired non-operated working interests in the Jonah Field in Sublette County, Wyoming. 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 approximately 950 net acres all held by production. The properties are operated by Jonah Energy, an established operator in the geographic region.

Average net daily production from the date of acquisition through June 30, 2022 was 2.1 MBOEPD. For the year ended June 30, 2022 our average net daily production from the Jonah Field properties consisted of 88% natural gas, 7% NGL, and 5% oil. Hydrocarbons produced from our Jonah Field properties are sold to West Coast markets.

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

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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 2022

Our proved reserves as of June 30, 2022, denominated in thousands of barrels of oil equivalent (MBOE), were estimated by our independent reservoir engineers, DeGolyer and MacNaughton (“D&M”) and Netherland, Sewell & Associates, Inc. (“NSAI”), both worldwide petroleum consultants.

D&M evaluated the reserves for our Barnett Shale, Hamilton Dome, and Delhi Field properties. D&M, which was formed in 1936, has completed more than 23,000 projects in more than 100 countries. 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.

NSAI evaluated the reserves for our Williston Basin and Jonah Field properties. NSAI, which was founded in 1961, began evaluating these properties when we acquired each of them during the fiscal year ended June 30, 2022. 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.

The following table sets forth our estimated proved reserves as of June 30, 2022. For additional reserve information, see our Supplemental 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 $85.82 per barrel of oil and $5.19 per MMBtu of natural gas. The net price per barrel of NGLs was $44.24, 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.

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Reserves as of June 30, 2022

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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 third-party consultants. Our internal reserve engineering team and third-party consultants have a combined experience of over 80 years in Petroleum Engineering. 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, 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 an independent director who is a Registered Professional Engineer 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.

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The reserves information in this filing is based on estimates prepared by D&M and NSAI. The person responsible for the preparation of the reserve report at D&M is Dilhan Ilk, Senior Vice President and Division Manager of North America. 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 10 years of experience in oil and natural gas reservoir studies and evaluations. The person responsible for the preparation of the reserve report at NSAI is Steven W. Jansen, P.E., Vice President. Mr. Jansen, a Licensed Professional Engineer in the State of Texas (No. 112973), has been practicing consulting petroleum engineering at NSAI since 2011 and has over four years of prior industry experience. He graduated from Kansas State University in 2007 with a Bachelor of Science Degree in Chemical Engineering.

We provide D&M and NSAI 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, designated operations personnel, and third-party consultants to ensure accuracy and completeness of the data prior to submission to the reserve engineers. The scope and results of D&M’s and NSAI’s procedures, as well as their professional qualifications, are summarized in the letters included as Exhibit 99.1 and Exhibit 99.2, respectively, to this Annual Report on Form 10-K.

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Proved Undeveloped Reserves

During the year ended June 30, 2022 our proved undeveloped (“PUD”) reserves changed as follows:

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Our PUD reserves were 3.6 MMBOE as of June 30, 2022, with related future development costs of approximately $61.7 million, which are associated with the Williston Basin properties. At June 30, 2021, our PUD reserves were 1.8 MMBOE, which were associated with Test Site V at our Delhi Field. PUD reserves associated with Test Site V were removed in the fiscal year ended June 30, 2022. The technical and economic merits of Test Site V remain attractive; however, the operator does not currently have Test Site V on its expenditure schedule for the next five years and, as a result, has been excluded from our proved reserves at this time. See “Drilling and Present Activities” below for a further discussion of our expected development of the PUDs added for the Williston Basin properties.

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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. As certain of our properties are considered fully developed, there are no plans to drill wells in fiscal year 2023 in the Hamilton Dome Field, the Delhi Field and the Jonah Field. At this time, operators of our Delhi Field, Hamilton Dome Field, Barnett Shale, Williston Basin, and Jonah Field properties are running workover rigs focusing on projects to return previously shut-in wells to production.

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During fiscal year 2022, we participated in the drilling of two gross wells in Barnett Shale which were brought online during the fourth quarter of the fiscal year. Our net interest in each of these wells is approximately one percent or less. There are currently no plans to participate in the drilling of additional wells in the Barnett Shale in fiscal year 2023.

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In the latter half of fiscal year 2022, our management team and third-party consulting engineers performed a technical review of drilling locations on our Williston Basin properties. Currently, there are 20 PUD drilling locations in the Pronghorn and Three Forks formations attributed to these properties. Pursuant to agreements we have with the operator, Foundation, we can propose drilling wells, in which the operator may participate. In the event the operator does not participate in our proposed drilling well, we have the right to undertake all necessary activities to drill, complete and install related facilities for the well. Ongoing operations of any well we elect to drill will be turned over to the operator of the property upon completion.

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Our operator, Foundation, has also identified four PUD sidetrack locations in the Williston Basin targeting the Birdbear formation.  Our management team and third-party consulting engineers have reviewed Foundation’s plans and technical justification and plan to participate in the drilling of two of these wells during fiscal year 2023 and included the expected cost in our fiscal year 2023 capital budget.

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For further discussion, see “Highlights for our Fiscal Year 2022” and “Capital Expenditures” within Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations.

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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, average daily production on an equivalent basis, production costs, and production costs per unit for the periods indicated:

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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, 2022.

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Acreage Data

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2022. 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.

We acquired the Williston Basin properties on January 14, 2022. The table below reflects our net undeveloped acreage in Williston Basin, North Dakota as of June 30, 2022 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:

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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

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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 the Delhi Field, the Hamilton Dome Field, the Barnett Shale or the Williston Basin 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. The third-party operator sells the oil, natural gas, and NGLs to the purchaser, collects the cash, and distributes the cash to us. In the years ended June 30, 2022 and 2021, three operators each distributed over 10% of our oil, natural gas and NGL revenues making up approximately 83% and 100% of total revenues for the years, respectively.

As the acquisition of the Williston Basin and Jonah Field properties occurred in the second half of fiscal year 2022, we expect purchases of our crude oil, natural gas, and NGL production from these properties to represent a larger percentage of total sales in fiscal year 2023 and beyond. The loss of a purchaser at any of our five 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, market prices, government regulation, weather, and actions of major foreign producers.

Oil prices over the past few years have fluctuated widely and been extremely volatile. For example, average daily prices for WTI oil ranged from a high of $123.64 per barrel to a low of $35.64 per barrel over our last two fiscal years. The price of oil per barrel dropped substantially in fiscal 2020 as a result of the impact of the novel coronavirus (“COVID-19”) pandemic and geopolitical factors but recovered to an average of $108.83 per barrel during the fiscal fourth quarter of 2022. The severe drop in oil price during the pandemic and market share competition between OPEC+ members in the spring of 2020 substantially and adversely impacted oil, natural gas, and NGL prices during the balance of 2020, and thus impacted the trailing 12-month commodity prices required for reserves and ceiling tests for asset carrying value which in turn led to substantial impairments during our first and second quarters of fiscal 2021. 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 factors also influence prices for oil, natural gas, and NGLs and include increasing or decreasing production trends, quality differences, regulation, 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 policies and the covenants under the Senior Secured Credit Facility, derivative

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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, we typically use costless collars 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. 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 policies and objectives may change as our operational profile changes. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Note 8, “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.

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Regulation of Oil and Natural Gas Production

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Federal, state, tribal and local authorities have promulgated extensive rules covering oil and natural gas exploration, production and related operations. Those regulations require our operating partners 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. 

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Regulation of Transportation of Oil and Natural Gas

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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. 

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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 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.

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Environmental Matters

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

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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 modify 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.

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The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, 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.

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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 operating partners) to significant expenses to modify operations, could force discontinuation of certain operations altogether and could limit the locations our operating partners may utilize in the future.

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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.

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In particular, the Environmental Protection Agency (“EPA”) proposed in November 2021 to impose new CAA rules restricting methane (a greenhouse gas) and VOC emissions from new, existing and modified facilities in the oil and gas sector. Among other things, EPA’s proposed new rule would require states to implement plans that meet or exceed established emission reduction guidelines for oil and natural gas facilities. These regulations and proposals and any other

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new regulations requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations and financial condition.

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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.

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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.

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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 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.

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Substantially all 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 our production costs.

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Scrutiny of hydraulic fracturing activities continues in other ways. Several states where our properties are located have also 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, tribal 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.

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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 operating partners 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. In 2022, moreover, 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.

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Climate Change

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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.

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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

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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, and Clean Air Act rules (such as the November 2021 proposal to regulate methane from the oil and gas sector). 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. To the extent that new climate change measures are adopted, and our third-party operating partners must further control GHG emissions, our business may be adversely impacted.

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

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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. 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.

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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, 2022, we had eight full-time employees, not including contract personnel and outsourced service providers. 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, 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, equality, and inclusion.

Sustainability and ESG

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In fiscal year 2021, we formed an Environmental Social Governance (“ESG”) Task Force. Under the supervision of our Board of Directors, the Nominating and Corporate Governance committee, and senior management, the ESG task force is responsible for the creation and implementation of our CSR and ESG initiatives. Evolution’s inaugural CSR was published in November 2021. This report is accessible on our website at www.evolutionpetroleum.com.

The ESG Task Force has formalized our existing ESG programs, proposed and implemented new ESG initiatives, monitored adherence to ESG standards, and provided public disclosures for our stakeholders. In fiscal year 2022, the ESG Task Force continued to disclose, enhance, implement, and provide training for a number of new and existing policies and procedures. These include, but are not limited to: formalizing and implementing charitable donation program and employee volunteer initiative, completing our first 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 develop and produce 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 and 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.

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.

At present, we do not report or collect data regarding emissions, water use, waste generation, spills, or other similar measurements on behalf of our operating partners. We host regular operations meetings with our operating partners in which we discuss asset level operations, expenses, any environmental issues and compliance, as well as ESG and health and safety related topics.

We do not report Scope 1 GHG, or direct, emissions to the EPA as we are not the operator of our 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. As a non-operator, the Company reports in its CSR the estimated Scope 2 GHG emissions for its corporate office located in Houston, Texas. 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.