EPM US Equity☆

Item 1A. Risk Factors

Our business involves a high degree of risk.Our ownership interest in oil and natural gas properties consists of non-operated working, revenue, and/or royalty interests. We do not operate any of our oil and natural gas properties nor do we do have any employees or contractors in the field. Our risks associated with oil and natural gas operations affect us indirectly through our ownership in non-operated working interests where we proportionately share in the costs and liabilities of operating such properties.

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If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition, or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider to be immaterial also may adversely affect us.

Risks Related to Our Business:

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A substantial or extended decline in oil, natural gas and NGL prices may adversely affect our business, financial condition, results of operations and our ability to meet our capital expenditure obligations and financial commitments.

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The price we receive for our oil, natural gas and NGLs significantly influences our revenue, profitability, access to capital, capital spending, and future rate of growth. At June 30, 2025, approximately 45% of our proved reserves were oil reserves, 38% were natural gas and 17% were NGLs. Oil, natural gas and NGLs are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas, and NGLs have been volatile and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control, including, but not limited to the following:

●changes in global supply and demand for oil and natural gas;

●worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;

●social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as the conflict between Ukraine and Russia and the conflict between Israel and Gaza, and acts of terrorism or sabotage;

●the ability and willingness of the members of OPEC+ to agree and maintain oil price and production controls;

●the price and quantity of imports of foreign oil and natural gas;

●energy transition away from hydrocarbons in response to governmental, scientific, and public concern over the threat of climate change arising from greenhouse gas emissions;

●the relative strength or weakness of the U.S. dollar compared to other currencies;

●the level of global oil and natural gas exploration and production;

●the level of global oil and natural gas inventories;

●localized supply and demand fundamentals of regional, domestic, and international transportation availability;

●weather conditions, natural disasters, and seasonal trends;

●domestic and foreign governmental regulations, including embargoes, sanctions, tariffs, and environmental regulations;

●speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;

●price and availability of competitors’ supplies of oil and natural gas;

●technological advances affecting energy consumption; and

●the price, availability and use of alternative fuels.

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Substantially all of our production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices. A decline in oil, natural gas, and NGL prices will reduce our cash flows, borrowing ability, the present value of our reserves, and our ability to develop future reserves. We may be unable to obtain the needed capital or financing on

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satisfactory terms. Low oil, natural gas, and NGL prices may also reduce the amount of oil, natural gas, and NGL that we can produce economically, which could lead to a decline in our oil, natural gas and NGL reserves. Generally, we hedge substantially less than all of our anticipated oil and natural gas production and typically limited to what is required by our Senior Secured Credit Facility. To the extent that we have not hedged production, any significant and extended decline in oil, natural gas, and NGL prices may adversely affect our financial position.

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Our existing developed oil, natural gas and NGL production will decline; we may be unable to acquire or develop the additional oil and natural gas reserves that are required in order to sustain our production and business operations.

The volume of production from developed oil, natural gas, and NGL properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Environmental issues, operating problems, or lack of extended future investment in any of our properties would cause our net production of oil, natural gas, and NGLs to decline significantly over time, which could have a material adverse effect on our financial condition.

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The types of resources we focus on have substantial operational risks.

Our business plan focuses on the acquisition and development of known resources in partially depleted, naturally fractured, or low permeability reservoirs. Our TexMex, Chaveroo Field, Hamilton Dome Field and Delhi Field properties produce from relatively shallow reservoirs, while our SCOOP/STACK, Jonah Field, Williston Basin and Barnett Shale properties produce from deeper reservoirs. Shallower reservoirs usually have lower pressure, which generally translates into lower reserves volumes in place. Deeper reservoirs have higher pressures and usually more reserves volumes in place, but capturing those reserves often comes at increased drilling and completion costs and risks and, generally, a higher rate of initial production decline. Low permeability reservoirs require substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of sufficient un-depleted fractures to establish commercial production. Depleted reservoirs require successful application of newer, or more expensive, technologies to produce incremental reserves. Our approach on the development and application of technologies on these different types of reservoirs could have a material adverse effect on our results of operations.

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The CO2-EOR project in the Delhi Field, operated by Denbury, a subsidiary of ExxonMobil, requires significant amounts of CO2 reserves, development capital, and technical expertise, the sources of which to date have been committed by the operator. The operator’s failure to manage these and other technical, environmental, operational, strategic, financial, and logistical risks may ultimately cause enhanced recoveries from the planned CO2-EOR project to fall short of our expectations in volume and/or timing. Such occurrences could have a material adverse effect on our results of operations and financial condition.

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We have limited control over the activities on properties we do not operate.

All of our property interests are operated by others. As a result, we have limited ability to influence or control the operations or future development of such properties, including compliance with environmental, safety, and other standards, or the amount or timing of capital or other expenditures that we will be required to fund with respect to such properties. Operators of these properties may act in ways that are not in our best interest. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur unexpected future costs, result in lower production, and materially and adversely affect our financial condition and results of operations.

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We will be subject to risks in connection with acquisitions.

We periodically evaluate acquisitions of reserves, properties, prospects, leaseholds, and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including, but not limited to:

● recoverable reserves;

● future oil, natural gas, and NGL prices and their appropriate differentials;

● development and operating costs;

● potential for future drilling and production;

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● potential environmental issues, litigation, and other liabilities.

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The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable at the ground surface or otherwise when an inspection is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Moreover, in the event of such an acquisition, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions and, importantly, that our assumptions regarding future oil and natural gas prices, differentials, reserves, or production could prove materially inaccurate and have a material adverse effect on our financial condition, results of operations, or cash flows.

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Our inability to complete acquisitions at our historical rate and at appropriate prices that support our long-term strategy could negatively impact our growth rate and stock price.

One of our key strategies is growth through acquisition of low decline, long-life oil and natural gas properties. Our ability to grow revenues, earnings and cash flow at or above our historic rates depends in part upon our ability to identify and successfully acquire and integrate oil and natural gas properties at appropriate prices, and to make appropriate investments that support our long-term strategy. We may not be able to consummate acquisitions at rates similar to the past, which could adversely impact our growth rate, our stock price, and our ability to maintain our dividends. Acquisitions are difficult to identify and complete for a number of reasons, including high valuations, competition among prospective buyers or investors, the availability of affordable funding in the capital markets and the need to satisfy applicable closing conditions.

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We may encounter difficulties integrating newly acquired oil and natural gas properties or businesses.

Increasing our reserve base through acquisitions has been an important part of our business strategy. We may encounter difficulties integrating newly acquired oil and natural gas properties or businesses. In particular, we may face significant challenges in consolidating functions and integrating procedures, personnel, and business operations in an effective manner. The failure to successfully integrate such properties or businesses into our Company may adversely affect our business and results of operations. Any acquisition we make may involve numerous risks, including:

● a significant increase in our indebtedness and working capital requirements;

● customer or key employee loss from the acquired business;

● increased administration of new personnel;

● additional costs due to increased scope and complexity of our business;

● potential disruption of our ongoing business; and

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Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. To the extent that we acquire properties substantially different from the properties we currently own or that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as effectively as with acquisitions within our current footprint and expertise. We may not be successful in addressing these risks or any other problems encountered in connection with any acquisition we may make.

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Oil and natural gas development, re-completion of wells from one reservoir to another reservoir, restoring wells to production, and drilling and completing new wells are speculative activities which involve numerous risks and substantial uncertain costs.

Our growth will be partially dependent upon the success of future development programs on our properties. Drilling for oil and natural gas and extracting NGLs and re-working existing wells involve numerous risks. The cost of drilling, completing, and operating wells is substantial and uncertain; drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including, but not limited to:

● unexpected drilling conditions;

● pressure fluctuations or irregularities in reservoir formations;

● equipment failures or accidents;

● well blowouts and other releases of hazardous materials;

● inability to obtain or maintain leases on economic terms, where applicable;

● adverse weather conditions;

● compliance with governmental requirements; and

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Drilling or re-working is a highly speculative activity. Even when fully and correctly utilized, modern well completion and production techniques, such as Horizontal Drilling or CO2 injection, do not guarantee that we will find and produce oil, natural gas and/or NGLs in economic quantities. Our future drilling, completion and production activities may not be successful and, if unsuccessful, such failure would have an adverse effect on our future results of operations and financial condition.

We may also identify and develop prospects through a number of methods, some of which may include Horizontal Drilling or tertiary injectants, and some of which may be unproven. The drilling and results for these prospects may be particularly uncertain. We cannot ensure that these projects can be successfully developed or that wells will, if drilled, encounter reservoirs of commercially productive oil or natural gas.

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Our oil and natural gas reserves are only estimates and may prove to be inaccurate.

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There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values. Our reserves are only estimates that may prove to be inaccurate because of these inherent uncertainties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot always be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves depend upon a number of variable factors. These factors include historical production from the area compared with production from other comparable producing areas, assumptions concerning effects of regulations by governmental agencies, future oil, natural gas, and NGL product prices, future operating costs, severance and excise taxes, development costs, workover costs, and remedial costs. Some or all of these assumptions utilized in estimating reserve volumes may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of reserves, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected from reserves may vary substantially depending on the timing and different engineers preparing reserves estimates.

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Accordingly, reserve estimates may be subject to downward or upward adjustments. Actual production, revenue, and expenditures with respect to our reserves will likely vary from estimates; such variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on the 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, and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or

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taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor. Interest rates in effect vary from time to time based on risks associated with us or the oil and natural gas industry in general. The Standardized Measure does not necessarily correspond to market value.

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Regulatory and accounting requirements may require substantial reductions in reporting proven reserves.

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On a periodic basis, we review the carrying value of our oil and natural gas properties under the applicable rules of various regulatory agencies, including the SEC. Under the full cost method of accounting that we use, the after-tax carrying value of our oil and natural gas properties may not exceed the present value of estimated future net after-tax cash flows from proved reserves, discounted at 10%. Application of this “ceiling” test requires pricing future revenues at the previous 12-month average beginning-of-month price and requires a write-down of the carrying value for accounting purposes if the ceiling is exceeded. We may in the future be required to write down the carrying value of our oil and natural gas properties when oil and natural gas prices are depressed or unusually volatile. Whether we will be required to take such a charge will depend in part on the prices of oil and natural gas during the previous period and the effect of reserve additions or revisions and capital expenditures during such period. If a write-down is required, it would result in a current charge to our earnings but would not impact our current cash flow from operating activities. A large write-down could adversely affect our compliance with the current financial covenants under our Senior Secured Credit Facility, could limit our access to future borrowings under that facility, or require repayment of any amounts that might be outstanding at the time.

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Our derivative activities could result in financial losses or could reduce our income.

Under the terms of our Senior Secured Credit Facility, we are required to hedge a certain portion of our anticipated oil and natural gas production for future periods when we reach a defined utilization percentage. We may also elect to hedge additional production volumes from time to time based upon our view of the attractiveness of commodity futures and the risks that downward price fluctuations might pose to our business plans. When we engage in hedging transactions, we may utilize costless collars, fixed price swaps or purchased floors to cost-effectively provide us with some protection against price changes. We have not historically designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our future derivative instruments. Derivative arrangements may also expose us to the risk of financial loss in some circumstances, including, but not limited to, if:

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In addition, in a rising commodity price environment, derivative arrangements may limit the extent to which we might benefit from increases in prices of oil and natural gas and may expose us to cash margin requirements.

Operations to develop and produce oil and natural gas reserves and our growth plans require significant amounts of capital and our ability to access additional capital at acceptable costs is important if we are to fund our development, grow our reserves and production and execute our growth plans.

Cash flow from our production varies based on commodity prices and may decline along with nature declines in our production. As a consequence, our cash flow may not be sufficient to fund our ongoing or planned activities at all times. From time to time, we may require additional financing in order to fund operations, acquisitions, exploitation, and development activities. We have, for instance, accessed our Senior Secured Credit Facility on a routine basis, including, recently, to fund acquisitions. Subsequent to our TexMex Acquisition in April 2025 and the SCOOP/STACK Acquisitions in 2024, the borrowings outstanding on our Senior Secured Credit Facility at June 30, 2025 was $37.5 million. On June 30, 2025, we entered into a syndicated amended and restated credit facility with MidFirst as administrative agent and added a second lender. The commitment size of the Senior Secured Credit Facility was

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increased to $65.0 million from $50.0 million. We may not be able to further increase the total commitments by adding additional lenders in the future on terms that are favorable to us. Further, the size of our Senior Secured Credit Facility is influenced by many factors, including our production, reserves and prevailing views on future commodity prices, and it may decrease based on developments negatively impacting those and other factors. While ordinarily positive developments in such factors might increase the amount that lenders are willing to lend to us, we are currently at the limit of our two lenders to increase the size of our Senior Secured Credit Facility due to limitations that the lenders have on the loans they may extend to a single borrower. Additionally, access to debt and equity capital markets or other alternatives may also prove unavailable or unattractive at such times or in such amounts as we may require. If we are unable to access adequate capital at acceptable costs, it could adversely affect our ability to expend the necessary capital to replace our reserves, maintain our production and execute our business plans.

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Government regulation and liability for oil and natural gas operations and environmental matters may adversely affect our business and results of operations.

Oil and natural gas operations are subject to extensive federal, state, and local government regulations, which may change from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas from wells below actual production capacity in order to conserve supplies of oil and natural gas. There are federal, state, and local laws and regulations addressing protection of human health and the environment that apply to the development, production, handling, storage, and transportation of oil, natural gas, and their by-products; the disposal of related wastes; the emission of CO2, methane, and other greenhouse gases; the emission of volatile organic compounds; and the management of other substances and materials released, produced or used in connection with oil and natural gas operations. These laws and regulations may affect the costs, manner, and feasibility of operations by, among other things, requiring us to make significant expenditures in order to comply and restricting the areas available for oil and gas production. Failure to comply with these laws and regulations may result in substantial liabilities to third-parties or governmental entities. In addition, we may be liable for significant environmental damages and cleanup costs, without regard to fault, for releases of hazardous materials on or from property we own or operate, even if we did not cause or contribute to the release. We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations, could have a material adverse effect on us, such as by imposing new emission controls, penalties, fines and/or fees, taxes and tariffs on carbon that could have the effect of raising prices to the end user and thereby reducing the demand for our products.

The risks arising out of the threat of climate change, including transition risks and physical risks, may adversely affect our business and results of operations.

The threat of climate change poses both transition risks and physical risks that could have a material adverse effect on us. Transition risks may arise from political and regulatory, legal, technological or financial changes as society tries to safeguard the climate, while physical risks may result from extreme weather events or other shifts in the natural world.

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We have been facing increased political and regulatory risks as federal, state and local governments have adopted new measures to restrict sources of greenhouse gas emissions and promote energy alternatives, including the final EPA rule announced in December 2023 to reduce the emission of methane from oil and gas facilities. Many such measures have been proposed, and still more can be expected. From time to time, there are proposals to ban hydraulic fracturing of oil and natural gas wells and to remove more lands, both onshore and offshore, from new hydrocarbon production. Many other actions could be pursued such as more rigorous requirements for drilling and construction permits, stricter greenhouse gas emissions standards for both new and existing sources, further limits on construction of new pipelines, reinstatement of the ban on oil exports, enhanced reporting obligations, taxing carbon emissions and creating further incentives for use of alternative energy sources. These actions may cause operational delays or restrictions, increased operating costs and additional regulatory burdens.

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Litigation risks are also increasing for oil and natural gas companies. A number of suits alleging, among other things, that oil and natural gas companies created public nuisances by producing fuels that contributed to climate change have been brought in state or federal court.

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Technological changes may drive market demand for products other than oil and natural gas. Wider adoption of hybrid engines and electric cars, for example, would reduce demand for our products. At the same time, our capital and operating costs may increase if we need to add new emission reduction technologies.

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There are also financial risks for the petroleum industry. It may become more difficult for us to access the capital markets if the threat of climate change discourages new investment. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices, and some of them may elect not to provide funding for fossil fuel energy companies. Limitation of investments in and financings for the energy industry could result in the restriction, delay or cancellation of drilling programs or development or production activities.

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The threat of climate change also may subject oil and natural gas operations and our business to severe weather or other natural hazards, such as flooding, drought, wildfires, and extreme temperatures. Any such event could halt production or exploration activities, damage equipment, disrupt transportation, reduce consumer demand and significantly increase our costs.

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Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, financial condition and access to capital.

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During the last few years, concerns over inflation, energy costs, volatile oil, natural gas, and NGL prices, geopolitical issues, the availability and cost of credit, the United States mortgage market, uncertainties with regard to European sovereign debt, the slowdown in economic growth in large emerging and developing markets, such as China, regional or worldwide increases in tariffs or other trade restrictions, and other issues have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic conditions have had a significant adverse impact on domestic and international financial markets and commodity prices. If uncertain or poor economic, business, or industry conditions in the United States or abroad remain prolonged, demand for petroleum products could diminish or stagnate, and production costs could increase. These situations have led to commodity price volatility and impact the price at which we can sell our oil, natural gas, and NGLs. Any sustained declines in crude oil, natural gas and NGL prices could affect our revenues, our operators ability to continue operations, and ultimately adversely impact our results of operations, liquidity and financial condition.

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Events outside of our control, including a pandemic or broad outbreak of an infectious disease, such as the global outbreak of a novel strain of the coronavirus (“COVID-19”), may materially adversely affect our business.

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We face risks related to pandemics, outbreaks, or other public health events that are outside of our control and could significantly disrupt our operators’ operations and adversely affect our financial condition. In December 2019, COVID-19 was identified in Wuhan, China and rapidly spread around the world. This virus and its variants, and governmental actions to contain it, had material adverse economic impacts globally. These and other actions, among other things, impacted the ability of our employees and contractors to perform their duties, caused increased technology and security risk due to extended and company-wide telecommuting, and led to disruptions in our permitting activities and critical business relationships, and could do so in the future should another similar public health event occur. Additionally, governmental restrictions intended to contain COVID-19 or future pandemics have in the past, and may in the future, significantly impact economic activity and markets and dramatically reduce actual or anticipated demand for oil and natural gas, adversely impacting the prices we receive for our production. The severity and duration of any such events are uncertain and difficult to predict, as is the extent that such events may have on our business.

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Our business could be negatively affected by security threats. A cyber-attack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation, and/or financial loss.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, and financial activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party operators. Our technologies, systems, networks, seismic data, reserves information, or other proprietary information, and those of our operators, vendors, suppliers, customers, and other business partners may become the target of cyber-attacks or information

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security breaches. Cyber-attacks or information security breaches could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyber-attacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation, or potential liability. Also, computers control nearly all of the oil and natural gas distribution systems in the United States and abroad. Computers are necessary to transport our oil and natural gas production to market. A cyber-attack directed at oil and natural gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the United States government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

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Our insurance may not protect us against all of the operating risks to which our business is exposed.

The oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of oil, natural gas, or well fluids, fires, formations with abnormal pressures, hurricanes and storms, flooding, pollution, releases of toxic gas, and other environmental hazards and risks, which can result in (1) damage to or destruction of wells and/or production facilities, (2) damage to or destruction of formations, (3) injury to persons, (4) loss of life, or (5) damage to property, the environment or natural resources. While we carry general liability, control of well, and operator’s extra expense coverage typical in our industry, we are not fully insured against all risks incidental to our business. Should we experience any losses, the costs of our premiums may rise, which could in turn reduce the amount of insurance we are able to carry.

The loss of key personnel could adversely affect us.

We depend to a large extent on the services of certain key management personnel, including our executive officers. The loss of one or more key personnel could have a material adverse effect on our operations. In particular, our future success is dependent upon the abilities of our executive officers to source, evaluate, and close deals, raise capital, and oversee our development activities and operations. Presently, we are not a beneficiary of any key man life insurance.

Oilfield service and materials prices may increase, and the availability of such services and materials may be inadequate to meet our needs.

Our business plan to develop or redevelop oil and natural gas resources requires third-party oilfield service vendors and various material providers, which we do not control. We also rely on third-party carriers for the transportation and distribution of our oil and natural gas production. As our production increases, so does our need for such services and materials. Generally, we do not have long-term agreements with our service and materials providers. Accordingly, there is a risk that any of our service providers could discontinue providing services for any reason or we may not be able to source the services or materials we need. Any delay in locating, establishing relationships, and training our sources could result in production shortages and maintenance problems, resulting in loss of revenue to us. In addition, if costs for such services and materials increase, it may render certain or all of our projects uneconomic, as compared to the earlier prices we may have assumed when deciding to redevelop newly purchased or existing properties. Further adverse economic outcomes may result from the long lead times often necessary to execute and complete our redevelopment plans.

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We may assume risks and financial responsibility for drilling and completing wells at our Chaveroo Field and Williston Basin properties if our third-party operator declines to drill wells and it or other joint interest owners elect not to participate.

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As discussed elsewhere in this report, pursuant to agreements related to our interests in the Chaveroo Field and Williston Basin properties, we have the ability to propose to the operator a drilling plan for certain wells, which the operator may accept or reject. In the event the operator rejects our proposed drilling plan, we have the right to undertake all necessary activities to drill and complete the wells and related facilities in accordance with our proposed drilling plan. In the event we undertake to do so, and the operator and other joint interest owners elect not to participate, we will bear the entire liability and expense associated with drilling and completing the wells and related facilities, subject only to our right to recoup costs incurred on behalf of non-participating joint interest owners to the extent a well generates sufficient revenues to do so. We thus may be required to bear a share of such expenses to an extent that is disproportionate to our economic interest in the property. If we elect to proceed to drill and complete wells we have proposed and the operator has rejected, we also will bear many of the other risks highlighted elsewhere herein, including, without limitation, failing to find economic quantities of oil and natural gas, drilling accidents, potential environmental liabilities, unavailability of insurance at a reasonable cost to cover associated liabilities, and price increases and delivery delays for required drilling and completion equipment, products and services. Ongoing operations of any wells we elect to drill will be turned over to the operator of the property upon completion.

We cannot market the oil and natural gas that we produce without the assistance of third-parties.

The marketability of the oil and natural gas that we produce depends upon the proximity of our reserves and production to, and the capacity of, facilities and third-party services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities necessary to make the products marketable for end use. The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in, delay, or discontinuance could adversely affect our financial condition.

We face strong competition from larger oil and natural gas companies.

Our competitors include major integrated oil and natural gas companies, numerous larger 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 staffs and greater capital resources. We may not be able to successfully conduct our operations, evaluate and select suitable properties, or consummate transactions in this highly competitive environment. Specifically, these larger competitors may be able to pay more for development projects and productive oil and natural gas properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on hiring contract service providers, obtaining oilfield equipment, and acquiring the existing and changing technologies that we believe are, and will be, increasingly important to attaining success in our industry.

We have been, and in the future may become, involved in legal proceedings related to our properties or operations and, as a result, may incur substantial costs in connection with those proceedings.

From time to time we may be a defendant or plaintiff in various lawsuits. The nature of our oil and natural gas properties and related operations exposes us to further possible litigation claims in the future. There is risk that any matter in litigation could be decided unfavorably against us regardless of our belief, opinion, and position, which could have a material adverse effect on our financial condition, results of operations, and cash flow. Litigation can be very costly, and the costs associated with defending litigation could also have a material adverse effect on our financial condition. Adverse litigation decisions or rulings may damage our business reputation.

Ownership of our oil and natural gas production and mineral rights depends on good title to our property.

Good and clear title to our oil and natural gas properties and mineral rights is important to our business. Although title reviews will generally be conducted prior to the purchase of most oil, natural gas, and mineral producing properties or

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the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim. This could result in a reduction or elimination of the revenue received by us from such properties.

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Unanticipated changes in effective tax rates or laws or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations.

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We are subject to tax by U.S. federal, state, and local tax authorities. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:

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● changes in the valuation of our deferred tax assets and liabilities;

● expected timing and amount of the release of any tax valuation allowances;

● tax effects of stock-based compensation;

● costs related to intercompany restructurings; or

● changes in tax laws, regulations, or interpretations thereof.

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For example, in previous years under previous Administrations, legislation has been proposed to eliminate or defer certain key U.S. federal income tax deductions historically available to oil and natural gas exploration and production companies. Such proposed changes have included: (1) a repeal of the percentage depletion allowance for oil and natural gas properties; (2) the elimination of deductions for intangible drilling and exploration and development costs; (3) the elimination of the deduction for certain production activities; and (4) an extension of the amortization period for certain geological and geophysical expenditures. Under the previous Administration there was an increased risk of the enactment of legislation that alters, eliminates, or defers these or other tax deductions utilized within the industry, which could adversely affect our business, financial condition, results of operations, and cash flows.

​

On July 4, 2025, legislation commonly referred to as the “One Big Beautiful Bill Act” (OBBBA) was enacted, significantly changing existing U.S. tax law. The OBBBA includes numerous provisions, such as permanent full expensing of domestic research and experimental expenditures, 100% bonus depreciation, modification of business interest limitations, and various international tax provisions such as Base Erosion and Anti-Abuse Tax, Foreign-Derived Deduction Eligible Income and Net Controlled Foreign Corporations Tested Income. Changes in tax laws between Administrations could affect our business, financial condition, results of operations, and cash flows when compared to previous years.

​

In addition, we may be subject to audits of our income, sales, and other transaction taxes by U.S. federal, state, and local taxing authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.

​

Risks Associated with our Common Stock

​

Our stock price has been and may continue to be volatile.

Our common stock has a relatively low trading volume and the market price has been, and is likely to continue to be, volatile. The variance in our stock price makes it difficult to forecast the stock price at which an investor may be able to buy or sell shares of our common stock. The market price for our common stock could be subject to fluctuations as a result of factors that are out of our control, such as:

​

● actual or anticipated variations in our results of operations;

● changes or fluctuations in the commodity prices of oil and natural gas;

● general conditions and trends in the oil and natural gas industry;

● redemption demands on institutional funds that hold our stock; and

● general economic, political, and market conditions.

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Significant ownership of our common stock is concentrated in a small number of shareholders who may be able to affect the outcome of the election of our directors and all other matters submitted to our stockholders for approval.

As of June 30, 2025, our executive officers and directors, in the aggregate, beneficially owned approximately 3.4 million shares, or approximately 9.9% of our outstanding common stock and, based on recent filings with the SEC, we believe two large non-affiliated fund complexes owned in excess of 12% of the outstanding shares of our common stock. As a result, a significant percentage of our common stock is concentrated in the hands of relatively few shareholders. These shareholders could potentially exercise significant influence over matters submitted to our stockholders for approval (including the election and removal of directors and any merger, consolidation or sale of all or substantially all of our assets). This concentration of ownership may have the effect of delaying, deferring, or preventing any matter that requires shareholder approval, including a change in control of our company, impede a merger, consolidation, takeover, or other business combination involving our company or discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of our company, which in turn could have an adverse effect on the market price of our common stock.

​

The market for our common stock is limited and may not provide adequate liquidity.

Our common stock trades on the NYSE American. Trading volume in our common stock is relatively low compared to larger companies. Our holders may find it more difficult to sell their shares, should they desire to do so, based on the trading volume and price of our stock at that time relative to the quantity of shares to be sold.

If securities or industry analysts do not publish research reports about our business, or if they downgrade our stock, the price of our common stock could decline.

Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry or securities analysts publish. To our knowledge, only two research analysts actively cover our company. The limited number of published reports by securities analysts could limit the interest in our common stock and negatively affect our stock price. We do not have any control over the research and reports these analysts publish or whether they will be published at all. If any analyst who does cover us downgrades our stock, our stock price could decline. If any analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price to decline.

Our stated objective of returning cash to shareholders is subject to our ability to generate sufficient cash flows to pay dividends on our common stock and to repurchase shares of our common stock, as applicable, and we have, in the past, and may in the future, reduce or eliminate dividend payments and stock repurchases.

Our Board of Directors declared cash dividends on our common stock for the first time in December 2013 and we have declared and paid quarterly cash dividends since that time. Additionally, our Board of Directors has in the past approved stock repurchase programs pursuant to which we have expended $8.6 million to repurchase shares over such period. Although one of our primary objectives is to return cash to shareholders, we are not required to repurchase shares of common stock or to pay dividends thereon and may be contractually or legally prohibited from doing so at certain times. Further, even if we are legally and contractually permitted to do so and have available cash to do so, we may elect to reduce or suspend the payment of dividends or the repurchase of shares of common stock to preserve cash based on the current and future capital requirements of our business, our financial condition, the amount of funds legally available therefor, any contractual restrictions to which we are subject at such time, our expectations about future cash inflows and such other factors as our Board of Directors may consider relevant. Accordingly, there is no certainty that dividends will be declared by our Board of Directors or shares of common stock will be repurchased by us in the future.

There may be future sales or issuances of our common stock, which will dilute the ownership interests of stockholders and may adversely affect the market price of our common stock.

We may in the future issue additional shares of common stock, including securities that are convertible into or exchangeable for, or that represent the right to receive, common stock or substantially similar securities, which may result in dilution to our stockholders. In addition, our stockholders may be further diluted by future issuances under our

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equity incentive plans and/or our At-the-Market equity Sales Agreement. The market price of our common stock could decline as a result of future sales or issuances of a large number of shares of our common stock or similar securities in the market or the perception that such sales or issuances could occur.

​

Non-U.S. holders may be subject to U.S. income tax and withholding tax with respect to gain on disposition of the Company’s common stock.

​

We believe we are a U.S. real property holding corporation. As a result, Non-U.S. holders that own (or are treated as owning under constructive ownership rules) more than a specified amount of our common stock during a specified time period may be subject to U.S. federal income tax and withholding on a sale, exchange or other disposition of such common stock, and may be required to file a U.S. federal income tax return.

​

Investor sentiment towards climate change, fossil fuels, sustainability, and other ESG matters could adversely affect our business and our stock price.

​

There have been efforts in recent years aimed at the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities, and other groups, to promote the divestment of shares of fossil fuel companies, as well as to pressure lenders and other financial services companies to limit or curtail activities with fossil fuel companies. As a result, some financial intermediaries, investors, and other capital markets participants reduced or ceased lending to, or investing in, companies that operate in industries with higher perceived environmental exposure, such as the oil and natural gas industry. If such divestment efforts are continued, the price of our common stock or debt securities, and our ability to access capital markets or to otherwise obtain new investment or financing, may be negatively impacted.

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Members of the investment community also have expressed increased interest as to ESG practices and disclosures, including practices and disclosures related to greenhouse gases and climate change in the energy industry in particular, and diversity and inclusion initiatives and governance standards among companies more generally. The SEC, for example, promulgated new rules in 2024 that required disclosure of various specific risks related to climate but promptly issued an order staying their applicability pending resolution of legal challenges and later decided not to defend them in court. Such requirements may take effect in the future. A heightened emphasis on ESG may lead some members of the investment community to screen our ESG performance before investing in our common stock or debt securities or lending to us.

​

If we are unable to meet the ESG standards or investment or lending criteria set by these investors and funds, we may lose investors, investors may allocate a portion of their capital away from us, our cost of capital may increase, the price of our common stock may be negatively impacted, and our reputation may be negatively affected.

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Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

Cybersecurity risk management is part of the Company’s overall enterprise risk management program. Our cybersecurity risk management program is designed to provide a framework for handling cybersecurity threats and incidents, including those associated with the use of third-party services and service providers. This framework includes steps for assessing a cybersecurity threat’s severity and source, including whether the cybersecurity threat is associated with a third-party service provider, implementing cybersecurity countermeasures and threat mitigation strategies, and informing management and our Board of material cybersecurity threats and incidents. To prevent and detect material cybersecurity incidents, our framework further includes, among other things, ongoing security awareness training for employees, regular cybersecurity risk and vulnerability assessments, and mechanisms to detect and monitor unusual network activity. We recognize the complex and evolving nature of cybersecurity threats and engage with various third-party service providers, including cybersecurity assessors and consultants, to evaluate and test our cybersecurity risk management systems. This enables us to leverage knowledge and insights to align our cybersecurity strategies and

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processes with best practices for our industry and size. Additionally, we maintain industry-standard cybersecurity insurance to provide further protection against cybersecurity risk.

​

Our Board is ultimately responsible for overseeing our risk management, including cybersecurity risk management. Management is responsible for identifying, considering, and assessing material cybersecurity risks on an ongoing basis, establishing processes to ensure that such potential cybersecurity risk exposures are monitored, implementing appropriate mitigation measures, and maintaining cybersecurity programs. Our cybersecurity programs are under the direction of our Principal Financial Officer, who receives reports from our cybersecurity consultants and monitors the prevention, detection, mitigation, and remediation of cybersecurity incidents. Any significant cybersecurity incidents are reported to our independent Audit Committee and ultimately to our Board.There were no such cybersecurity incidents or threats that have materially impacted our business or operations. Management presents an assessment of our cybersecurity processes, procedures, and testing results to the Audit Committee at least annually.

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Despite our efforts, we cannot eliminate all risks from cybersecurity threats nor provide assurances that we have not experienced an undetected cybersecurity incident. For more information about these risks, please see discussion captioned “Our business could be negatively affected by security threats. A cyber-attack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation, and/or financial loss.” in Item 1A. Risk Factors.

Item 2. Properties

Information regarding our properties is included in Item 1. Business above and in Note 4, “Property and Equipment” to our consolidated financial statements in Item 8. Consolidated Financial Statements and Supplementary Data, which information is incorporated herein by reference.

Item 3. Legal Proceedings

See Note 10, “Commitments and Contingencies” to our consolidated financial statements in Item 8. Consolidated Financial Statements and Supplementary Data for a description of any legal proceedings, which is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not Applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common stock is currently traded on the NYSE American stock exchange under the ticker symbol “EPM”.

Shares Outstanding and Holders

As of June 30, 2025, there were 34,337,188 shares of common stock issued and outstanding. As of September 1, 2025, there were approximately 220 registered shareholders of our common stock.

Dividends

We began paying cash quarterly dividends on our common stock in December 2013. Over the last two fiscal years, we made the following cash dividends per share:

​

​ ​ ​ ​ ​ ​ ​

​ ​ Fiscal Year

Fourth fiscal quarter ​ $ 0.12 ​ $ 0.12

Third fiscal quarter ​ ​ 0.12 ​ ​ 0.12

Second fiscal quarter ​ ​ 0.12 ​ ​ 0.12

First fiscal quarter ​ ​ 0.12 ​ ​ 0.12

​

As of June 30, 2025, we have paid 47 consecutive quarterly dividends on our common stock. In September 2025, the Company declared a $0.12 per share dividend payable on September 30, 2025. Any future determination with regard to the payment of dividends will be at the discretion of the Board of Directors and will be dependent upon our future earnings, financial condition, results of operations, applicable dividend restrictions, capital requirements, and other factors deemed relevant by the Board of Directors.

Securities Authorized For Issuance Under Equity Compensation Plans

​

​ ​ ​ ​ ​ ​ ​ ​

​ ​ Number of ​ ​ ​ ​ Number of securities

​ ​ securities to ​ ​ ​ ​ remaining

​ ​ be issued ​ Weighted-average ​ available for future

​ ​ upon exercise ​ exercise ​ issuance under

​ ​ of outstanding ​ price of ​ equity compensation

​ ​ options, ​ outstanding ​ plans (excluding

​ ​ warrants and ​ Options, warrants ​ securities reflected

Plan category rights (a) and rights (b) in column (a))(1)

​ ​ ​ ​ ​ ​ ​ ​

Equity compensation plans approved by security holders: ​ ​ ​ ​ ​ ​ ​

Outstanding options ​ — ​ $ — ​ ​

Outstanding contingent rights to shares ​ 241,613 (1)​ ​ — ​ ​

Equity compensation plans not approved by security holders ​ — ​ ​ — ​ —

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Issuer Purchases of Equity Securities

The table below summarizes information about the Company’s purchases of its equity securities during the three months ended June 30, 2025.

​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

​ ​ ​ ​ ​ ​ (c) Total number ​ (d) Maximum dollar value

​ ​ (a) Total number ​ ​ ​ of shares ​ of shares that may yet be

​ ​ of shares ​ ​ ​ purchased as part ​ purchased under the

​ ​ purchased and ​ (b) Average price ​ of public announced ​ plans or programs

May 2025 ​ — ​ ​ — ​ — ​ ​ —

Item 6. Reserved

​

​

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

Executive Overview

Liquidity and Capital Resources

Results of Operations

Critical Accounting Policies and Estimates

Executive Overview

General

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

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

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Recent Developments

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Dividend Declaration

​

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

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Purchase of SCOOP/STACK Minerals

​

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

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Senior Secured Credit Facility

​

On June 30, 2025, we entered into an amended and restated senior secured reserve-based credit agreement (the “Senior Secured Credit Facility”) with MidFirst Bank, as administrative agent for the lenders party thereto, in an amount up to $200.0 million with an initial borrowing base of $65.0 million maturing on June 30, 2028. Refer to “Liquidity and Capital Resources” below for a further discussion.

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Purchase of Non-operated Oil and Natural Gas Assets

​

On April 14, 2025, we closed the acquisition of non-operating working interests in certain long-life oil and natural gas wells located primarily in Lea, Eddy and Chaves Counties, New Mexico and Stephens County, Texas (the “TexMex Acquisition”) from a private seller. The total purchase price for the TexMex Acquisition was approximately $9.0 million before customary post-closing adjustments, with an effective date of February 1, 2025. We funded the purchase price for the TexMex Acquisition with a combination of cash on hand and borrowings under our Senior Secured Credit Facility. The TexMex Acquisition includes an average working interest of 42% and an average revenue interest of 35% in approximately 600 wells.

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

​

On October 21, 2024, we entered into an ATM equity Sales Agreement (the “ATM Sales Agreement”) with Roth Capital Partners, LLC (the “Lead Agent”), Northland Securities Inc., and A.G.P./Alliance Global Partners pursuant to which we

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may issue and sell, from time to time, up to $30.0 million of shares of common stock through or to the Lead Agent, acting as agent or principal. For the year ended June 30, 2025, we sold a total of approximately 0.7 million shares of our common stock under the ATM Sales Agreement for net proceeds of approximately $3.5 million, after deducting $0.3 million in offering costs. We intend to use the net proceeds from any sales of common stock for general corporate purposes, including to repay outstanding indebtedness.

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Proved Reserves

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

​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

​ ​ Proved Reserves ​ ​ ​ ​

Proved Reserves MMBOE ​ ​ 27.1 ​ ​ ​ 31.8 ​ ​ (14.8) %

% Developed ​ ​ 83.7 % ​ ​ 75.6 % ​ 8.1 %

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

​

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

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

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

Risks and uncertainties

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

​

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

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

​

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

​

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

Liquidity and Capital Resources

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

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

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

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

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

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

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

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

​

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

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

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Capital Expenditures

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

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

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

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

Full Cost Pool Ceiling Test

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

​

Overview of Cash Flow Activities

​ ​ ​ ​ ​ ​ ​ ​ ​ ​

​ ​ Years Ended June 30, ​ ​ ​

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

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

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

​

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

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

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

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

​

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Results of Operations

Years Ended June 30, 2025 and 2024

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

​

​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

​ Years Ended June 30, ​ ​ ​ ​ ​ ​

Revenues: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

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

Depletion, depreciation, and accretion: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

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

General and administrative expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Other income (expense): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

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

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

​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Production: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Natural gas liquids (MBBL) ​ ​ 414 ​ ​ 402 ​ ​ 12 ​ 3.0 %

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

​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Average price per unit(2): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

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

​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Average cost per unit: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

Lease operating costs: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

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

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

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

General and administrative expenses: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

General and administrative ​ ​ 3.04 ​ ​ 3.02 ​ ​ 0.02 ​ 0.7 %

​

​

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Revenues

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

​

Lease Operating Costs

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

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

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

Depletion of Full Cost Proved Oil and Natural Gas Properties

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

General and Administrative Expenses

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

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Stock-based Compensation Expenses

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

Net Gain (Loss) on Derivative Contracts

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

​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

​ ​ Years Ended June 30, ​ ​ ​ ​ ​ ​

​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​

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

​

Interest Expense

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

Income tax (expense) provision

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

Critical Accounting Policies and Estimates

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

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

Oil and Natural Gas Properties. Companies engaged in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and natural gas industry. We apply the full cost accounting method for our oil and natural gas properties as prescribed by SEC Regulation S-X Rule 4-10. Under this method of accounting, the costs of unsuccessful and successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration, and development activities but does not include any costs related to production, general corporate overhead, or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties. We exclude these costs until the property has been evaluated. Costs are transferred to the full cost pool as the properties are evaluated. As of June 30, 2025 and 2024, we had no unevaluated property costs. Oil and natural gas properties include costs that are excluded from depletion and amortization, which represent investments in unproved and unevaluated properties and include non-producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs.

Estimates of Proved Reserves. The estimated quantities of proved oil and natural gas reserves have a significant impact on the underlying financial statements. The estimated quantities of proved reserves are used to calculate depletion expense and the estimated future net cash flows associated with those proved reserves is the basis for determining impairment under the quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex and requires significant decisions in the evaluation of all available geologic, geophysical, engineering, and economic data. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information; this includes reservoir performance, additional development activity, new geologic and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates prepared by our third-party independent engineers represent the most accurate assessments possible, the subjective decisions and variances in available data for the properties make these estimates generally less precise than other estimates included in our financial statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect our estimated future net cash flows of our proved reserves. These changes could affect our quarterly ceiling test calculation and could significantly affect our depletion rate. Additionally, a 10% decrease in commodity prices used to determine our proved reserves as of June 30, 2025, while all other factors remained constant, would not have resulted in an impairment of our oil and natural gas properties. Holding all other factors constant, a reduction in our proved reserve estimates at June 30, 2025 of 10% would affect depletion, depreciation, and amortization expense by approximately $0.6 million.

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

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

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

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risks

Derivative Instruments and Hedging Activity

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

​

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

Interest Rate Risk

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

​

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Item 8. Consolidated Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

​ ​ ​

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

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

​ Notes to Consolidated Financial Statements 50

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

​

​

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Evolution Petroleum Corporation

Opinion on the Financial Statements

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

Basis for Opinion

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

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

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

Critical Audit Matter

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

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

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

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

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

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

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

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

o Testing the specialists’ findings for mathematical accuracy; and

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

◾ production forecasts to recent historical actual production,

​ ​

/s/ Baker Tilly US, LLP ​

​ ​

Houston, Texas ​

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

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​

EVOLUTION PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share amounts)

​

​ ​ ​ ​ ​ ​ ​

Assets ​ ​ ​ ​

Current assets ​ ​ ​ ​

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

Derivative contract assets ​ ​ 1,777 ​ ​ 596

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

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

​ ​ ​ ​ ​ ​ ​

Other noncurrent assets ​ ​ ​ ​ ​ ​

Derivative contract assets ​ ​ 198 ​ ​ 171

Liabilities and Stockholders' Equity ​ ​ ​ ​ ​

Current liabilities ​ ​ ​ ​ ​

Accrued liabilities and other ​ ​ 6,909 ​ ​ 6,239

Derivative contract liabilities ​ ​ 1,577 ​ ​ 1,192

State and federal taxes payable ​ ​ — ​ ​ 74

Long term liabilities ​ ​ ​ ​ ​

Senior secured credit facility ​ ​ 37,500 ​ ​ 39,500

Deferred income taxes ​ ​ 6,234 ​ ​ 6,702

Derivative contract liabilities ​ ​ 1,783 ​ ​ 468

Operating lease liability ​ ​ — ​ ​ 58

Commitments and contingencies (Note 10) ​ ​ ​ ​ ​ ​

Stockholders' equity ​ ​ ​ ​ ​

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

​

See accompanying notes to consolidated financial statements.

​

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EVOLUTION PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

​

​ ​ ​ ​ ​ ​ ​

​ Years Ended June 30,

Revenues ​ ​ ​ ​ ​ ​

Operating costs ​ ​ ​ ​ ​ ​

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

General and administrative expenses ​ ​ 10,334 ​ ​ 9,636

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

Other income (expense) ​ ​ ​ ​ ​ ​

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

Interest and other income ​ ​ 191 ​ ​ 342

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

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

Net income (loss) per common share: ​ ​ ​ ​

Weighted average number of common shares outstanding: ​ ​ ​ ​

​

See accompanying notes to consolidated financial statements.

​

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EVOLUTION PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

​

​ ​ ​ ​ ​ ​ ​

​ ​ Years Ended June 30,

Cash flows from operating activities: ​ ​ ​ ​

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

Stock-based compensation ​ ​ 2,482 ​ ​ 2,137

Settlement of asset retirement obligations ​ ​ (385) ​ ​ (20)

Deferred income taxes ​ ​ (468) ​ ​ (101)

Unrealized (gain) loss on derivative contracts ​ ​ 492 ​ ​ 893

Accrued settlements on derivative contracts ​ ​ (251) ​ ​ 67

Other ​ ​ (8) ​ ​ —

Changes in operating assets and liabilities: ​ ​ ​ ​ ​

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

Accounts payable and accrued liabilities and other ​ ​ 4,798 ​ ​ 374

State and federal taxes payable ​ ​ (74) ​ ​ (291)

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

Cash flows from investing activities: ​ ​ ​ ​ ​ ​

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

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

Cash flows from financing activities: ​ ​ ​ ​

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

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

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

Debt issuance costs ​ ​ (90) ​ ​ —

Issuance of common stock ​ ​ 3,840 ​ ​ —

Offering costs ​ ​ (310) ​ ​ —

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

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

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

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