Evolution Petroleum (EPM) 10-K2021 FY Annual report

the remaining two phases (Phase V) is reflected as proved undeveloped in our current reserves report and the other (Phase VI) was removed from proved reserves as it was not deemed economic due to distant location and oil price.

On November 1, 2019, the Company acquired certain mineral interests in the Hamilton Dome field from Merit, who owns the vast majority of the remaining working interest in the field. The Hamilton Dome field is located in the southwest part of the Big Horn Basin in northwest Wyoming about twenty miles northwest of Thermopolis in Hot Springs County.

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

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

The following table sets forth our estimated proved reserves as of June 30, 2021. For additional reserve information, see Note 20 to our consolidated financial statements in Item 8. The NYMEX previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $49.72 per barrel of oil and $2.46 per MMBtu of natural gas. The net price per barrel of NGLs was $19.81, which does not have any single comparable reference index price. The NGL price was based on historical prices received. For periods for which no historical price information was available, we used comparable pricing in the geographic area. Pricing differentials were applied based on quality, processing, transportation, location and other pricing aspects for each individual property and product.

The following table presents a reconciliation of changes in our proved reserves by major property, on the basis of equivalent MBOE quantities.

Our policies regarding internal controls over reserves estimates require such estimates to be prepared by an independent petroleum engineering firm under the supervision of our President and Chief Executive Officer, Jason Brown, who has over 20 years of experience in the energy industry and is a Registered Professional Engineer (Petroleum) in the State of Texas. He earned his B.S. degree in chemical engineering from the University of Tulsa and his M.B.A. from the Mendoza School of

Business at the University of Notre Dame. Such reserves estimates comply with generally accepted petroleum engineering and evaluation principles, definitions, and guidelines as established by the SEC.

We provide D&M with our property interests, production, current operating costs, current production prices, and other information in order to prepare the reserve estimates. This information is reviewed by our President and Chief Executive Officer, designated operations personnel, and other members of management to ensure accuracy and completeness of the data prior to submission to D&M. The scope and results of D&M's procedures, as well as their professional qualifications, are summarized in the letter included as Exhibit 99.1 to this Annual Report on Form 10-K.

Our proved undeveloped reserves were 1,813 MBOE at June 30, 2021, with associated future development costs of approximately $8.6 million, which are associated with the Phase V development of Delhi field. The Company does not have any proved undeveloped reserves associated with its Hamilton Dome field or Barnett Shale asset.

As of June 30, 2021, we have estimated total future net capital expenditures of approximately $8.6 million for remaining development of Phase V in the eastern part of the field, which we expect to commence in fiscal year 2023, however the timing is dependent on the field operator's available funds, capital spending plans, and priorities within its portfolio of properties.

incorporate the completion of the NGL plant in late 2016 and delays relating to the 2013 adverse fluid release event; (2) we have had significant ongoing development activities at this project that, as budgeted and currently being expended, reflect a significant and sufficient portion of remaining capital expenditures to convert proved undeveloped reserves to proved developed reserves; and (3) the operator has a historical record of completing the development of comparable long-term projects.

As of June 30, 2021, no proved reserves were attributed to (a) the area beneath the inhabited portion of the town of Delhi in the northeast and (b) the farthest east of the two remaining undeveloped sites in the eastern portion of the field (Phase VI) due to the current economics and other technical aspects of our future development plans. In addition, no proved reserves are currently attributed to three smaller reservoirs within the Unit in similar formations with similar production history due to the lower oil price utilized in our reserves calculation. We also do not have any proved reserves associated with our interests in the Mengel Sand, a separate interval within the Unit that is not currently producing, but has produced oil in the past.

In connection with establishing a six-well water curtain on two pads in advance of Phase V site development, during fiscal 2019 our operator drilled two (0.48 net) wells and completed three (0.72 net) wells. A pad consists of one gross water source well and two gross water injector wells. The northern pad commenced injection during fiscal 2019 and the southern pad became fully operational late in the second quarter of fiscal 2020 when capital expenditures for completion work concluded.

Hamilton Dome field is considered fully developed. No wells were drilled in fiscal 2021, and there are no plans to drill wells in fiscal 2022.

Starting in late third quarter 2021, the operator of the Delhi field resumed some capital conformance work to recomplete existing wells into different production zones, including recompleting a temporarily abandoned well in Test Site V. This work is still ongoing and too early to quantify the impact of these projects on the patterns. There are no significant drilling plans until Phase V development, expected to commence in 2023.

For further discussion, see “Highlights for our fiscal year 2021” and “Capital Expenditures” within Item 7.

As of June 30, 2021, we were not committed to provide a fixed and determinable quantity of oil, NGLs, or natural gas under existing agreements, nor do we currently intend to enter into any such agreements.

The following table sets forth the number of productive oil and gas wells in which we own a working interest as of June 30, 2021.

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2021. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would allow production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves. 

For more complete information regarding current year activities, including oil and natural gas production, refer to Item 7.

Our production is marketed to third parties in a manner consistent with industry practices. In the United States of America market where we operate, oil, natural gas, and NGLs are readily transportable and marketable. We do not currently market our share of oil, natural gas, or NGLs production from the Delhi field, the Barnett Shale or from the Hamilton Dome field separately from the operators' shares of production. Although we have the right to take our working interest production in-kind, we are currently selling our production through the field operators pursuant to the delivery and pricing terms of their sales contracts. Under such arrangements, we typically do not know the identity of the buyers of production except in the case of the Delhi field where there is a sole buyer for oil and another for NGL's, and in the case of the Barnett Shale where there is a sole buyer for approximately all of the natural gas.

On November 1, 2019, Evolution acquired a non-operated interest in the Hamilton Dome field in Wyoming. All the field’s production is sour heavy oil which is the sole component of the field’s reserves. Oil is transported by pipeline primarily to purchasers in Casper, Wyoming. As a result of transportation differentials, the high sulfur content and low API gravity, this oil trades at a discount to WTI, averaging $9.60 lower for the year ended June 30, 2021, and $17.62 lower for the eight months ended June 30, 2020. Although we have the option of taking our production in-kind, we have elected to have the operator market our share of production. Our realized price is net of transportation and marketing costs.

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

The oil and natural gas industry is highly competitive for prospects, acreage, and capital. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staff and greater capital resources. Competitors are national, regional, or local in scope and compete on the basis of financial resources, technical prowess or local knowledge. The principal competitive factors in our industry are expertise in given geographical areas and geologic systems and the ability to efficiently conduct operations, achieve technological advantages, identify and acquire economically producible reserves, and obtain capital at rates that allow economic investments.

Derivative instruments are occasionally utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas production. We have designed a risk management policy to use derivative instruments from time to time during periods of extraordinary price volatility and when such instruments are needed to ensure the Company can meet its current dividend policy, fund its capital expenditures commitments, and maintain liquidity. We determine the duration of derivative positions to approximate the anticipated period of volatility and the percentage of our production to be hedged based on our view of current and future market conditions. We do not enter into derivative contracts for speculative trading purposes.

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

During fiscal 2020, we entered into NYMEX WTI oil swaps that covered approximately 42,000 barrels per month for the period of April 2020 through December 2020 at a fixed swap price of $32.00 per barrel. As of June 30, 2021, we did not have any open fixed-price swaps or costless collars. In the future, we may add additional swaps or other derivative positions covering a variable portion of our anticipated future production during subsequent periods.

It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. For the year ended June 30, 2021, we did not post collateral under any of our derivative contracts as they are uncollateralized trades. We will continue to evaluate the benefit of employing derivatives in the future. See Item 7A and Note 18 to our consolidated financial statements in Item 8 for additional information.

Numerous federal and state laws and regulations govern the oil and natural gas industry, including environmental laws and regulations. These laws and regulations are often changed in response to changes in the political or economic environment. Compliance with this evolving regulatory environment is often difficult and costly; substantial penalties may be incurred for

noncompliance. To the best of our knowledge, we are in compliance with all federal and state-level laws and regulations applicable to our operations. The future annual capital cost of complying with the regulations applicable to our operations is uncertain and will be governed by several factors, including future changes to regulatory requirements which are unpredictable. We do not currently anticipate that continued and future compliance with existing laws and regulations will have a materially adverse effect on our consolidated financial position or results of operations.

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

We maintain insurance on our oil and natural gas properties and operations for risks and in amounts customary in the industry. Such insurance includes general liability, excess liability, control of well, operators extra expense, casualty, fraud, and directors  and officer's liability coverage. Not all losses are insured, and we retain certain risks of loss through deductibles, limits, and self-retentions. We do not carry lost profits coverage, and we do not have coverage for consequential damages.

At June 30, 2021, we had five full-time employees, not including contract personnel and outsourced service providers. None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees. Our team is broadly experienced in oil and natural gas operations, development, acquisitions, and financing. We follow a strategy of outsourcing most of our property accounting, human resources, administrative, and other non-core functions.

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

The price we receive for our oil and natural gas significantly influences our revenue, profitability, access to capital, and future rate of growth. Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. For example, average daily prices for WTI oil ranged from a high of $74 per barrel to a low of a negative $38 per barrel, and Henry Hub natural gas prices ranged from a high of $23.86 to a low of $1.33 per MMBTU over our last two fiscal years. Historically, the markets for oil, natural gas, and natural gas liquids 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:

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 needed capital or financing on 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. At June 30, 2021, approximately 36% of our proved reserves are oil reserves, 35% are natural gas and 29% are NGL reserves. As such, we are heavily impacted by movements in natural gas and oil prices, the latter also influencing NGL prices. To the extent that we have not hedged our production with derivative contracts or fixed-price contracts, any significant and extended decline in oil, natural gas, and NGL prices may adversely affect our financial position.

Our revenues come from our royalty, mineral, and working interests in the Delhi field in Louisiana, the Hamilton Dome field in Wyoming, and the Barnett Shale in Texas and thus our current revenues are concentrated from these fields. Any significant downturn in production, oil, natural gas, and NGL prices, or other events beyond our control which impact these fields could have a material adverse effect on our results of operations and financial results. We are not the operator of these fields, and our revenues and future growth are heavily dependent on the success of operations, which we do not control.

Substantially all of our property interests are not operated by the Company and involve other third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety, and other regulations, or the amount of capital 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 conditions and results of operations.

Any significant downturn in production or other events beyond our control which impact our assets could have a material adverse effect on our results of operations and financial results (or timing thereof).

We are not the operator of the Barnett Shale assets. At the time of acquisition, approximately 90% of the wells in the Barnett Shale field were operated by Blackbeard, and the remaining 10% of wells were operated by seven other operators. Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.

Our business plan focuses on the acquisition and development of known resources in partially depleted reservoirs, naturally fractured, or low permeability reservoirs. Our Delhi and Hamilton Dome assets are productive from relatively shallow reservoirs, while our Barnett Shale assets produce from deeper reservoirs. Shallower reservoirs usually have lower pressure, which generally translates into lower reserve volumes in place. Deeper reservoirs have higher pressures and usually more reserve volumes, but capturing those reserves often comes at increased drilling and completion cost and risk. Low permeability reservoirs require more wells and 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 technology to produce incremental reserves.

Our growth will be partially dependent upon the success of our future development program. Drilling for oil and natural gas and extracting NGLs and re-working existing wells involve numerous risks. The risk that no commercially productive oil or natural gas reservoirs will be encountered is paramount. 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:

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 the wells discussed will, if drilled, encounter reservoirs of commercially productive oil or natural gas.

For the year ended June 30, 2021, one purchaser accounted for approximately 62% of our total oil revenues. We do not currently market our share of oil, natural gas, and NGLs production from the Delhi field, the Hamilton Dome field, or the Barnett Shale. Although we have the right to take our working interest production in-kind, we are currently accepting terms under the operators' agreements for the delivery and pricing of our oil, natural gas and NGLs. The loss of a large purchaser for our oil production could negatively impact the revenue we receive. We cannot guarantee that we could readily find other purchasers for our oil and natural gas production.

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 and natural gas product prices, future operating costs, severance and excise taxes, development costs, work-over 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.

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 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.

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 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.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and NGLs, we have, and may in the future, enter into derivative arrangements for a portion of our oil, natural gas, and NGLs production. Derivative arrangements may include costless collars and fixed-price swaps. 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:

In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs and may expose us to cash margin requirements.

Although we plan to experience growth through acquisitions and development activity, any such growth may place a significant strain on our financial, technical, operational, and administrative resources. Our ability to grow will depend upon a number of factors, including, but not limited to the following:

We cannot ensure that we will be able to successfully grow or manage any such growth.

Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times. From time to time, we may require additional financing in order to carry out our oil and natural gas acquisitions, exploitation, and development activities. Certain portions of our undeveloped leasehold acreage may be subject to expiration unless production is established. If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our current production. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available to us on favorable terms.

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 even when an inspection is undertaken. 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, which could materially adversely affect our financial condition, results of operations, or cash flows.

Significant acquisitions and other strategic transactions may involve other risks, including, but not limited to:

The process of integrating assets could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. In addition, even if we successfully integrate the assets acquired in an acquisition, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volumes, cost savings from operating synergies, other benefits anticipated from an acquisition, or realize these benefits within the expected time frame.

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 partners. 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 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 of America 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 of America 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.

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, flooding, pollution, releases of toxic gas, and other environmental hazards and risks, which can result in (i) damage to or destruction of wells and/or production facilities, (ii) damage to or destruction of formations, (iii) injury to persons, (iv) loss of life, or (v) 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. Environmental events similar to that experienced in the Delhi field in June 2013 could defer revenue, increase operating costs, and/or increase maintenance and repair capital expenditures.

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 Robert Herlin, our Chairman of the Board, Jason Brown, our President and Chief Executive Officer, and Ryan Stash, Senior Vice President, Chief Financial Officer, and Treasurer, to source, evaluate, and close deals, raise capital, and oversee our development activities and operations. Presently, the Company is not a beneficiary of any key man life insurance.

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 servicing our oil and natural gas fields for any reason or we may not be able to source the 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.

The marketability of the oil and natural gas that we produce depends upon the proximity of our reserves 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.

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.

From time to time we may be a defendant or plaintiff in various lawsuits. The nature of our 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.

Good and clear title to our oil, natural gas, and mineral properties 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 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.

We face risks related to pandemics, outbreaks, or other public health events that are outside of our control and could significantly disrupt our operations and adversely affect out financial condition. In December 2019, a novel strain of a coronavirus, COVID-19, was identified in Wuhan, China. This virus continues to have a material impact globally. These and other actions could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide telecommuting, and lead to disruptions in our permitting activities and critical business relationships. Additionally, the COVID-19 outbreak and governmental restrictions have significantly impacted economic activity and markets and have dramatically reduced current and anticipated demand for oil and natural gas, adversely impacting the prices we receive for our production. The severity and duration of the current COVID-19 outbreak and the subsequent variants in addition to the potential for future outbreaks are uncertain and difficult to predict.

The extent to which COVID-19 impacts our business will depend on future developments, which are highly uncertain and cannot be predicted, including new information which may emerge concerning the severity of the coronavirus and the actions to contain the coronavirus or treat its impact, among others. We are unable to predict the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments, including the length of time that the

pandemic continues, its ongoing effect on the demand for oil and natural gas and the response of the overall economy and the financial markets after governmental restrictions are eased.

During the last few years, concerns over inflation, energy costs, declining oil and natural gas prices, geopolitical issues, the availability and cost of credit, the United States of America 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 of America or abroad remain prolonged, demand for petroleum products could diminish or stagnate, and production costs could increase. These situations could impact the price at which we can sell our oil, natural gas, and NGLs, affect our vendors', suppliers', and customers' ability to continue operations, and ultimately adversely impact our results of operations, liquidity, and financial condition.

Our common stock has relatively low trading volume and the market price has been, and is likely to continue to be, volatile. For example, during the fiscal year ended June 30, 2021, our stock price as traded on the NYSE American ranged from $2.75 to $5.15. The variance in our stock price makes it difficult to forecast with certainty 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:

As of June 30, 2021 our executive officers and directors, in the aggregate, beneficially owned approximately 2.7 million shares, or approximately 8.0% of our beneficial common stock base. Blackrock Fund Advisors, et al controlled approximately 2.0 million shares or approximately 6.1% of our outstanding common stock, Arrowmark Colorado Holdings, LLC controlled approximately 2.0 million shares or approximately 6.1% of our outstanding common stock and Renaissance Technologies, LLC controlled approximately 2.2 million shares or approximately 6.5% of our outstanding common stock. As a result, any of these holders 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 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.

Our common stock trades on the NYSE American stock exchange. Trading volume in our common stock is relatively low compared to larger companies. During the fiscal year ended June 30, 2021, the daily trading volume in our common stock ranged from a low of 38,100 shares to a high of 4,596,300 shares, with average daily trading volume of 169,054 shares compared to average daily volume of 155,691 in fiscal 2020. 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.

Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry or securities analysts publish. To our knowledge, three independent analysts cover our company. The limited number of published reports by independent 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.

We currently have in place an effective registration statement which allows the company to publicly issue up to $500 million of additional securities, including debt, common stock, preferred stock, and warrants. At any time we may make private offerings of our securities. The shelf registration is intended to provide greater flexibility to the company in financing growth or changing our capital structure. We are authorized to issue up to 100,000,000 shares of common stock. To the extent of such authorization, our board of directors has the ability, without seeking stockholder approval, to issue additional shares of common stock in the future for such consideration as our board may consider sufficient. The issuance of additional common stock in the future would reduce the proportionate ownership and voting power of the common stock now outstanding. We are also authorized to issue up to 5,000,000 shares of preferred stock, the rights and preferences of which may be designated in series by our Board of Directors. Such designation of any new series of preferred stock may be made without stockholder approval and could create additional securities which would have dividend and liquidation preferences over the common stock now outstanding. Preferred stockholders could adversely affect the rights of holders of common stock by:

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. However, there is no certainty that dividends will be declared by the Board of Directors in the future. Any payment of cash dividends on our common stock in the future will be dependent upon the amount of funds legally available, our earnings, if any, our financial condition, our business plan, restrictions contained in current or future debt instruments, contractual covenants or arrangements we may enter into, our anticipated capital requirements, and other factors that our Board of Directors may think are relevant. Although it is our intent to maintain a steady dividend for our shareholders, there is no guarantee that we will be able to do so. For example, during the 3rd quarter of fiscal 2020, we reduced our quarterly dividend from $0.10 per common share to $0.025. The quarterly dividend was $0.05 for the fourth quarter of fiscal 2021 as a result of an improving financial and industry outlook. There is no guarantee that we will be able or choose to continue to pay cash dividends on our common stock.    

None.

Information regarding our properties is included in Item 1 above and in Note 6 to our consolidated financial statements in Item 8, which information is incorporated herein by reference.

See Note 16 to our consolidated financial statements in Item 8 for a description of any legal proceedings, which is incorporated herein by reference.

Not Applicable.

As of June 30, 2021, we have paid 31 consecutive quarterly dividends on our common stock. In September 2021, the Company declared a $0.075 per share dividend payable on September 30, 2021. 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.

The following graph presents a comparison of the yearly percentage change in the cumulative total return on our Common Stock over the period from June 30, 2016 to June 30, 2021 with the cumulative total return of the S&P 500 Index and the S&P Oil & Gas Exploration and Production Index of publicly traded companies over the same period. The graph assumes that $100 was invested on June 30, 2016 in our common stock at the closing market price at the beginning of this period and in each of

the other two indices and the reinvestment of all dividends, if any. The graph is presented in accordance with requirements of the SEC. Shareholders are cautioned against drawing any conclusions from the data contained therein, as past results are not necessarily indicative of future financial performance.

During the fourth quarter ended June 30, 2021, the Company did not purchase any common stock in the open market under the previously announced share repurchase program and no shares of common stock were surrendered by its employees to pay their share of payroll taxes arising from vesting of restricted stock.

The selected consolidated financial data, set forth below should be read in conjunction with Item 7 and Item 8.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil prices. This amount represents the (i) (gain) loss related to fair value adjustments on our open, or unrealized, derivative contracts and (ii) (gains) losses on settlements of derivative contracts for positions that have settled or been realized. No positions remain outstanding as of June 30, 2021.

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

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

Total general and administrative expenses for fiscal 2021 increased $1.5 million, or 28.4%, to $6.8 million from the same year-ago period. The increase is primarily due to higher legal and professional fees of $0.8 million related to consulting on various potential business transactions, an increase in accrued bonus expense of $0.5 million and an increase in salaries of $0.2 million due to additional employees.

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our consolidated financial statements. Our significant accounting policies are included in Note 2 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.

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 forecast 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.

As of June 30, 2021, we have recorded a valuation allowance for the portion of our net operating loss that is limited by Internal Revenue Code Section 382.

Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making the assessment of the ultimate realization of deferred tax assets. The Company establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods, based upon the level of historical taxable income and projections for future taxable income over the periods for which the deferred tax assets are deductible. At the time of this report, we have recorded a valuation allowance for our expected inability to realize the future benefits of certain federal and state deferred tax assets as further discussed in Note 13 - Income Taxes. If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax provision would change in the period it is determined that recovery is probable.

The Company had no off-balance sheet arrangements as of June 30, 2021.