Item 1A. Risk Factors
Our business involves a high degree of risk. 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 the oil and gas industry and our Company
A substantial or extended decline in oil prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The price we receive for our oil significantly influences our revenue, profitability, access to capital, and future rate of growth. Oil is a commodity and its price is subject to wide fluctuations in response to relatively minor changes in supply and demand. For example, average daily prices for WTI crude oil ranged from a high of $74 per barrel to a low of a negative $38 per barrel over our past few fiscal years. Historically, the markets for oil 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:
• actions of OPEC or other groups of oil producing nations;
• the price and quantity of imports of foreign oil and natural gas;
• the level of global oil and natural gas exploration and production;
• the level of global oil and natural gas inventories;
• weather conditions and natural disasters;
• domestic and foreign governmental regulations;
• price and availability of competitors' supplies of oil and natural gas;
• technological advances affecting energy consumption; and
• the price and availability of alternative fuels.
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 and natural gas liquids 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 and natural gas liquids prices may also reduce the amount of oil and natural gas liquids that we can produce economically, which could lead to a decline in our oil and natural gas liquids reserves. Because approximately 80% of our proved reserves at June 30, 2020 are crude oil reserves and 20% are natural gas liquids reserves, we are heavily impacted by movements in crude oil prices, which also influence natural gas liquids 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 and natural gas liquids prices may adversely affect our financial position.
Our revenues are concentrated in two assets and related declines in production or other events beyond our control could have a material adverse effect on our results of operations and financial results.
Our revenues come from our royalty, mineral and working interests in the Delhi field in Louisiana and the Hamilton Dome field in Wyoming and thus our current revenues are highly concentrated in these fields. Any significant downturn in production, oil 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.
Operating results from oil and natural gas production may decline; we may be unable to acquire and develop the additional oil and natural gas reserves that are required in order to sustain our business operations.
In general, the volumes of production from crude oil and natural gas properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we acquire additional properties containing proved reserves or conduct successful development activities, or both, our proved reserves will decline. Our production is heavily dependent on our interests in EOR production that began during March 2010 in the Delhi field and our newly acquired interests in the
14
Table of Contents
Hamilton Dome field in Wyoming. Environmental or operating problems or lack of extended future investment in either of these fields could cause our net production of oil and natural gas liquids to decline significantly over time, which could have a material adverse effect on our financial condition. In fiscal 2020, our production was impacted by the operators of both fields. Delhi production volumes were negatively impacted as a result of the financial strain Denbury was under and their lack of investment in projects in the field, including the delay of our Phase V, in addition to the purchased CO2 line being shut in for repairs. In the Hamilton Dome field Merit temporarily shut in a portion of the production as it was uneconomic at the historically low prices. As of June 30, 2020, a number of these wells have returned to production and we continue to monitor their performance; however, there is no guarantee that prolonged periods of being shut in or lack of investment would not negatively impact future production.
We have limited control over the activities on properties we do not operate.
Substantially, all of our property interests are not operated by the Company and also 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.
We are materially dependent upon our operators with respect to the successful operation of our principal assets, which consists of our interests Delhi and Hamilton Dome fields. A materially negative change in our operator’s financial condition could negatively affect operations (or timing thereof) in these fields, and consequently our income (or timing thereof) from these fields as well as the value of our interests in these fields.
Our royalty, mineral and working interests in the Delhi field, located in Northeast Louisiana are our primary producing assets. Approximately 90% of our revenues come from the Delhi interests and thus our current revenues are highly concentrated in this field. Any significant downturn in production or other events beyond our control which impact the Delhi field could have a material adverse effect on our results of operations and financial results (or timing thereof). We are not the operator of the Delhi field. It is operated by a subsidiary of Denbury Resources Inc. (“DNR”), an independent oil and gas company specializing in tertiary recovery with CO2. Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.
Further, our CO2 - Enhanced Oil Recovery (“CO2-EOR”) project in the Delhi field requires significant amounts of CO2 reserves and technical expertise, the sources of which have been committed by the operator. Additional capital remains to be invested to fully develop this project, further increase production, and maximize the value of this asset. The operator's failure to manage these and other technical, environmental, operating, strategic, financial and logistical matters could cause ultimate 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 us, and our results of operations and financial condition.
On February 22, 2020, DNR experienced a pressure loss in its CO2 purchase pipeline resulting in an immediate shut down. DNR cut out a section of the failed pipeline and sent it out for analysis on the cause of the failure and remediation procedures. Analysis results, with the consultation the government regulating agency, recommended repairing the damaged section of pipeline. DNR has informed the Company that preparations for this project are underway and the CO2 purchases line should be back in operation October 1, 2020.
Our economic success is thus materially dependent upon the Delhi field operator's ability to: (i) deliver sufficient quantities of CO2 from its reserves in the Jackson Dome source, (ii) secure its share of capital necessary to fund development and operating commitments with respect to the field and (iii) successfully manage related technical, operating, environmental, strategic, and logistical risks, among other things.
In July 2020, Denbury announced that it had entered into a Restructuring Support Agreement (the “RSA”) with holders of 100% of revolving credit facility loans, approximately 67.2% of second lien notes and approximately 70.8% of convertible notes for a “pre-packaged” plan to eliminate $2.1 billion of bond debt and subsequently filed for voluntarily filed petitions for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas. Denbury subsequently announced on September 3rd that its plan to eliminate $2.1 billion of its bond debt has been confirmed by the court which will substantially reduce its debt, strengthen its balance sheet, and position Denbury to free up capital for investment in properties such as Delhi again.
15
Table of Contents
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 reservoirs, naturally fractured, or low permeability reservoirs. Our Delhi and Hamilton Dome assets are productive from relatively shallow reservoirs; we may pursue assets that produce from deeper reservoirs in the future. 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 undepleted fractures to establish commercial production. Depleted reservoirs require successful application of newer technology to produce incremental reserves.
Our CO2-EOR project in the Delhi field, operated by a subsidiary of Denbury Resources Inc., requires significant amounts of CO2 reserves, development capital and technical expertise, the sources of which to date have been committed by the operator. Although initial CO2 injection began at Delhi in November 2009, initial oil production response began in March 2010 and a large part of the capital budget has already been expended. Additional capital remains to be invested to fully develop the EOR project, further increase production, and maximize the value of the asset. The operator's failure to manage these and other technical, environmental, operating, strategic, financial, and logistical risks may cause ultimate enhanced recoveries from the planned CO2-EOR project to fall short of our expectations in volume and/or timing. Such occurrences would have a material adverse effect on the Company, its results of operations and financial condition.
Crude 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 materially dependent upon the success of our future development program. Drilling for crude oil and extracting natural gas liquids and re-working existing wells involve numerous risks. The risk that no commercially productive crude 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:
• unexpected drilling conditions;
• pressure fluctuations or irregularities in reservoir formations;
• equipment failures or accidents;
• regulatory climate;
• inability to obtain or maintain leases on economic terms, where applicable;
• adverse weather conditions;
• compliance with governmental requirements; and
Drilling or re-working is a highly speculative activity. Even when fully and correctly utilized, modern well completion techniques such as horizontal drilling or CO2 injection, do not guarantee that we will find and produce crude oil and/or natural gas in our wells in economic quantities. Our future drilling 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 cannot guarantee that our overall drilling success rate will not decline.
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 assure you that these projects can be successfully developed or that the wells discussed will, if drilled, encounter reservoirs of commercially productive crude oil or natural gas.
The loss of a large single purchaser of our oil and natural gas could reduce the competition of our production.
For the year ended June 30, 2020, one purchaser accounted for approximately 87% of our total oil revenues. We do not currently market our share of crude oil production from the Delhi or Hamilton Dome fields. 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. 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. In addition, the crude oil production from the Delhi and Hamilton Dome fields is transported by pipeline; if either of these pipelines were disrupted and we were forced to use alternative transportation methods, our net realized pricing and potentially our near-term production levels could be adversely affected.
16
Table of Contents
Our crude oil and natural gas reserves are only estimates and may prove to be inaccurate.
There are numerous uncertainties inherent in estimating crude 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 crude oil and natural gas that cannot always be measured in an exact manner. Estimates of economically recoverable crude 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 crude 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 ang and different engineers preparing reserves estimates.
Accordingly, reserve estimates may be subject to downward or upward adjustment. 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 crude 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 crude 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.
Regulatory and accounting requirements may require substantial reductions in reporting proven reserves.
On a periodic basis we review the carrying value of our crude 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 crude oil and natural gas properties when crude 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 crude 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.
Our derivative activities could result in financial losses or could reduce our income.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas liquids, we have, and may in the future, enter into derivative arrangements for a portion of our oil and natural gas liquids production. Derivative arrangements may include costless collars and fixed-price swaps. We have not 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 derivative instruments. Derivative arrangements also expose us to the risk of financial loss in some circumstances, including, but not limited to, if:
• production is less than the volume covered by the derivative instruments;
17
Table of Contents
In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas liquids and may expose us to cash margin requirements.
We may have difficulty managing future growth and the related demands on our resources and may have difficulty in achieving future growth.
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:
• our ability to identify and acquire new development projects;
• our ability to develop new and existing properties;
• our ability to continue to retain and attract skilled personnel;
• the results of our development program and acquisition efforts;
• the success of our technologies;
• hydrocarbon prices;
• drilling, completion, and equipment prices;
• our ability to successfully integrate new properties;
• our access to capital; and
We cannot assure you that we will be able to successfully grow or manage any such growth.
Our operations may require significant amounts of capital and additional financing may be necessary in order for us to continue our exploitation activities, including meeting potential future drilling obligations.
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 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.
We will be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult and may involve unexpected costs or delays.
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 and natural gas prices and their appropriate differentials;
• development and operating costs;
• potential for future drilling and production;
• potential environmental issues, litigation and other liabilities.
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.
18
Table of Contents
Significant acquisitions and other strategic transactions may involve other risks, including, but not limited to:
• difficulty associated with coordinating geographically separate organizations;
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.
Government regulation and liability for oil and gas operations and environmental matters may adversely affect our business and results of operations.
Crude oil and natural gas operations are subject to extensive federal, state, and local government regulations, which may be changed 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 crude oil and natural gas from wells below actual production capacity in order to conserve supplies of crude oil and natural gas. There are federal, state, and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation, and disposal of crude oil and natural gas, by-products thereof, the emission of CO2 or other greenhouse gases, and other substances and materials produced or used in connection with crude oil and natural gas operations. These laws and regulations may affect the costs, manner and feasibility of our operations and require us to make significant expenditures in order to comply. In addition, we may inherit liability for environmental damages, whether actual or not, caused by previous owners of property we purchase or lease or from nearby properties. As a result, failure to comply with these laws and regulations may result in substantial liabilities to third parties or governmental entities. 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 diminishing the demand for our products through legislative enactment of proposed new penalties, fines and/or taxes on carbon that could have the effect of raising prices to the end user.
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 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 gas distribution systems in the United States of America and abroad. Computers are necessary to transport our oil and gas production to market. A cyber attack directed at oil and 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
19
Table of Contents
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.
Our insurance may not protect us against all of the operating risks to which our business is exposed.
The crude oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of crude 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.
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 Robert Herlin, our Chairman of the Board, Jason Brown, our President and Chief Executive Officer, and David Joe, Senior Vice President, Chief Financial Officer, Treasurer and Corporate Secretary, 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.
Oil field 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 crude 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 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 crude 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.
We cannot market the crude oil and natural gas that we produce without the assistance of third parties.
The marketability of the crude 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 crude 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 gas companies.
Our competitors include major integrated crude oil and natural gas companies, numerous larger independent crude 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 crude 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.
20
Table of Contents
We have been, and in the future may become, involved in legal proceedings related to our Delhi interest or other 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 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, gas and mineral production depends on good title to our property.
Good and clear title to our oil, gas, and mineral properties is important to our business. Although title reviews will generally be conducted prior to the purchase of most oil, 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.
Events outside of our control, including a pandemic or broad outbreak of an infectious disease, such as the ongoing global outbreak of a novel strain of the coronavirus identified in late 2019 (“COVID-19”), may materially adversely affect our business.
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 spread globally including in the United States of America. 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 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.
Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, and financial condition.
During the last few years, concerns over inflation, energy costs, declining oil and 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.
Risks Associated with Our Stock
Our stock price has been and may continue to be volatile.
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 ending June 30, 2020, our stock price as traded on the NYSE American ranged from $2.16 to $7.05. 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:
• actual or anticipated variations in our results of operations;
21
Table of Contents
• naked short selling of our common stock and stock price manipulation;
• changes or fluctuations in the commodity prices of crude oil and natural gas;
• general conditions and trends in the crude oil and natural gas industry;
• redemption demands on institutional funds that hold our stock; and
• general economic, political and market conditions.
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, 2020 our executive officers and directors, in the aggregate, beneficially owned approximately 2.7 million shares, or approximately 8.2% of our beneficial common stock base. Blackrock Fund Advisors, et al controlled approximately 3.4 million shares or approximately 10.2% of our outstanding common stock, Arrowmark Colorado Holdings, LLC controlled approximately 2.6 million shares or approximately 7.8% of our outstanding common stock, Renaissance Technologies, LLC controlled approximately 2.4 million shares or approximately 7.3% of our outstanding common stock, Advisory Research, Inc controlled approximately 1.5 million shares or approximately 4.5% of our outstanding common stock and JVL Advisors, LLC controlled approximately 1.5 million shares or approximately 4.5% 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.
The market for our common stock is limited and may not provide adequate liquidity.
Our common stock trades on the NYSE American. Our trading volumes decreased slightly in fiscal 2020 compared to fiscal 2019. Trading volume in our common stock is relatively low compared to larger companies. During the fiscal year ended June 30, 2020, the daily trading volume in our common stock ranged from a low of 42,300 shares to a high of 931,500 shares, with average daily trading volume of 155,610 shares compared to average daily volume of 180,353 in fiscal 2019. 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 there are three independent analysts that 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.
The issuance of additional common stock and preferred stock could dilute existing stockholders.
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:
• delaying, deferring, or preventing a change in control of our company; and
22
Table of Contents
• discouraging bids for our common stock.
Payment of dividends on our common stock has been in the past, and could be in the future, reduced or eliminated.
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 per common share. Accordingly, there is no guarantee that we will be able or choose to continue to pay cash dividends on our common stock.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
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.
Item 3. Legal Proceedings
See Note 16 to our consolidated financial statements in Item 8 for a description of any legal proceedings, which is incorporated herein by reference.
Item 4. Mine Safety Disclosures
Not Applicable.
23
Table of Contents
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock
Our common stock is currently traded on the NYSE American under the ticker symbol "EPM". The following table shows, for each quarter of the fiscal years ended June 30, 2020 and 2019, the high and low sales prices for EPM as reported by the NYSE American.
NYSE American: EPM
Shares Outstanding and Holders
As of June 30, 2020, there were 32,956,469 shares of common stock issued and outstanding. As of September 1, 2020, there were approximately 213 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, the Company made the following cash dividends per share:
Years Ended June 30,
`
As of June 30, 2020, we have paid 27 consecutive quarterly dividends on our common stock. In August 2020, the Company declared a $0.025 per share dividend payable on September 30, 2020. 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. Under our current revolving credit facility, our ability to continue to pay common stock dividends is dependent on compliance with certain financial covenants related to debt service coverage, as defined in the agreement.
Performance Graph
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, 2015 to June 30, 2020 with the cumulative total return of the S&P 500 Index and the S&P
24
Table of Contents
Oil & Gas Exploration and Production Index of publicly traded companies over the same period. The graph assumes that $100 was invested on June 30, 2015 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.
Securities Authorized For Issuance Under Equity Compensation Plans
Equity compensation plans approved by security holders:
Outstanding options — $ —
Outstanding contingent rights to shares 200,000 (1) —
Equity compensation plans not approved by security holders — — —
(1) In December 2016, the Company adopted the Equity Incentive Plan (the "2016 Plan"), which authorized the issuance of 1,100,000 shares of common stock. As of June 30, 2020, the Company has granted 709,511 awards under the 2016 Plan and 390,489 shares of common stock remain available for future grants.
25
Table of Contents
Issuer Purchases of Equity Securities
During the fourth quarter ended June 30, 2020, 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.
Item 6. Selected Financial Data
The selected consolidated financial data, set forth below should be read in conjunction with Item 7 and Item 8.
Income Statement Data
Net loss on derivative contracts 1,383,204 — — — —
Deemed dividend on preferred shares called for redemption — — — 1,002,440 —
Earnings per common share:
Balance Sheet Data
26
Table of Contents
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview
Liquidity and Capital Resources
Results of Operations
Critical Accounting Policies
Executive Overview
General
Evolution Petroleum Corporation is an oil and gas company focused on delivering a sustainable dividend yield to its stockholders through the ownership, management, and development of oil and gas properties. In support of that objective, the Company's long-term goal is to build a diversified portfolio of oil and gas assets primarily through acquisitions, while seeking opportunities to maintain and increase production through selective development, production enhancements, and other exploitation efforts on its properties.
Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO2 enhanced oil recovery project, and our interests in the Hamilton Dome field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, and overriding royalty interests in two onshore Texas wells.
Our interests in the Delhi field consist of a 23.9% working interest, with an associated 19.0% revenue interest and separate overriding royalty and mineral interests of 7.2% yielding a total net revenue interest of 26.2%. The field is operated by Denbury.
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 gas company, who owns the vast majority of the remaining working interest in Hamilton Dome field. Our acquired interest in this field aligned with the Company's strategy of adding long-lived, low decline reserves expected to be supportive of our dividend over the long-term.
Highlights for our Fiscal Year 2020 and Operations Update
27
Table of Contents
Oil & Natural Gas Liquids Reserves (based on SEC average NYMEX WTI oil price of $47.37 per barrel at June 30, 2020)
The following table is a summary of our proved reserves as of June 30, 2020 and 2019:
Proved
% Developed 82 % 82 % — %
Standardized Measure ($MM) $ 62 $ 127 (51 )%
Additional property and project information is included under Item 1 and in Note 6 and Note 21 to our consolidated financial statements in Item 8, and in Exhibit 99.1 of this Form 10-K.
Delhi Field
Proved reserves volumes totaled 8.7 MMBOE compared to the prior year's 9.0 MMBOE. Year over year, decreased oil prices and temporary curtailment of CO2 purchases since February 2020 has led to a 0.2 MMBOE, or a 2% negative revision in proved oil reserves. Adjustment of projecting NGL reserves independent of oil production resulted in a 0.6 MMBOE, or 46% positive revision to NGL reserves.
Gross production at Delhi in the fourth quarter of fiscal 2020 was 6,082 BOEPD, an 8% decrease compared to 6,597 BOEPD in the third fiscal quarter. Oil production was 4,985 BOPD, an 9% decrease from the third fiscal quarter’s 5,499 BOPD. NGL fourth quarter production of 1,097 BOEPD was virtually flat compared to prior quarter production. Oil production was significantly impacted by materially lower CO2 purchases when the CO2 purchase pipeline, upstream of Delhi field, was shut-in for repairs in late February throughout the end of fiscal 2020. The operator has commenced repairs to the pipeline and expects an in service date of October 2020. The loss of CO2 purchases, coupled with the decline in oil prices, led to the operator electing to freeze non-essential capital projects through the end of fiscal 2020.
The average oil price realized by Evolution during the fourth quarter of fiscal 2020 was $23.74 compared to $47.27 during the previous quarter, a decrease of 50%. The average NGL price realized by Evolution during the fourth quarter of fiscal 2020 was $2.11 per barrel compared to $9.56 during the previous quarter, a decrease of 78%. The decline was attributable to the decrease in all realized commodity prices in fiscal fourth quarter. The COVID-19 pandemic, combined with a market share competition between certain members of the OPEC+ member nations, continued to adversely impact demand for commodity products,
28
Table of Contents
which caused a global supply/demand imbalance for oil that resulted in extreme volatility in benchmark oil prices, with prices ranging from a low of a negative price of $37.63 per Bbl to a high of $40.46 per Bbl during our fiscal fourth quarter.
Although we historically benefit from the premium that Delhi field oil receives selling under Louisiana Light Sweet ("LLS") pricing, as compared to the more widely known West Texas Intermediate ("WTI") price, in the fiscal fourth quarter, the field realized a discount to WTI of $4.26. Oil produced from Delhi field is shipped to market directly by pipeline, the most efficient means of transportation from the field. Our received NGL price for royalty production is burdened by a capital recovery charge, which is mostly offset by our working interest share that is reflected as a reduction in lease operating expense.
Our overall lifting costs for the year were $16.50 per BOE, which decreased 14.6% from $19.31 per BOE in the prior year. Gross CO2 purchase volume rates for the fiscal 2020 averaged 51.9 MMcf per day, compared to 85.2 MMcf per day in the prior year, a 39% decrease due to the Delhi CO2 purchase pipeline shut-in for repairs. This decrease together with a 14% lower price per mcf resulted in a 48% decrease in CO2 cost compared to the prior year. Our cost of purchased CO2, the largest single component of operating costs at Delhi, is directly tied to the price of oil sold from the Delhi field. Other lease operating expenses for fiscal 2020 decreased 5.6% compared to the prior year, primarily due to lower fuel gas, parts and workover expenses.
For fiscal 2020, our gross NGL production was 1,106 BOEPD, which sold at an average price of $9.59 per barrel, compared to prior year gross production of 1,171 BOEPD for which we realized $21.87 per barrel. 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. NGL prices have fallen significantly from a peak in late 2018 in response to worldwide supply and demand. Historically, NGL demand has had a seasonal pattern with prices tending to be higher in the cooler months of the year. Accordingly, the relationship between NGL prices and WTI has fluctuated over time and we expect such volatility to continue in the future.
The NGL plant includes an electric turbine that converts methane and part of the ethane processed by the plant into electricity. This turbine generates power primarily for the NGL plant and supplies excess power to the CO2 recycle facility. The NGL plant is accomplishing its primary objective of removing the lighter, smaller chain hydrocarbons (i.e. methane and ethane), thereby increasing the purity of the CO2 recycle stream and improving the efficiency of the CO2 flood throughout the field. Over time, the NGL plant is expected to increase and enhance the recovery of crude oil in the field. The NGL plant is not only providing feedstock to power the electric turbine, it is also producing significant quantities of higher value NGLs to sell to market.
Remaining estimated capital expenditures for our proved undeveloped reserves amount to approximately $6.38 per BOE 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. Development of unquantified volumes is dependent upon the timing of excess capacity within the processing plant and oil price. We continue to believe that this high quality and economically viable project will be executed as planned, subject to oil price volatility.
Hamilton Dome
At June 30, 2020, we had total proved reserves of 1.5 MMBOE which was entirely comprised of oil as estimated by our independent petroleum engineering firm D&M.
Gross oil production at Hamilton Dome in the fourth quarter of fiscal 2020 was 1,642 BOPD, a 29% decrease compared to 2,328 BOPD in the third fiscal quarter quarter primarily due to the operator shutting in uneconomic wells at the extremely low oil price. There were limited capital expenditures in the field during fiscal 2020 due primarily to the decrease in oil prices. Most projects focused on maintenance, but in March 2020, a larger, and more efficient, ESP was installed in the Step Scale 117 which resulted in an increase in average production since completion of 5 BOPD. The average oil price realized by Evolution during the fourth quarter was $16.12 compared to $30.23 during the previous quarter, a decrease of 47%. Production from this field is transported by pipeline to customers in the Western Canadian Select market; prices are discounted from WTI. In the fourth quarter our realized price reflected a $11.88 per barrel discount from the WTI price. For this fiscal year, subsequent to our acquisition, our lifting costs at Hamilton Dome have averaged $28.93 per barrel.
29
Table of Contents
Impact of Geopolitical Factors and the COVID-19 Pandemic
On March 11, 2020, the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States of America declared a national emergency with respect to COVID-19. The virus has continued to spread in the United States of America and abroad. National, state, and local authorities have recommended social distancing, imposed quarantine and isolation measures, as well as mandatory business closures on large portions of the population. These measures, while intended to protect human life, are expected to have serious adverse impacts on domestic and foreign economies of uncertain severity and duration. The effectiveness of economic stabilization efforts, including government payments to affected citizens and industries, is uncertain.
The nature of the COVID-19 pandemic makes it extremely difficult to predict the impact on the Company’s business and operations. However, the likely overall economic impact of the pandemic is viewed as highly negative to the general economy, especially the oil and natural gas industry. During the six months ended June 30, 2020, primarily driven by the COVID-19 pandemic and actions taken by OPEC+, the benchmark price of WTI dropped significantly. Although global outputs can be adjusted to support commodity pricing levels, the Company expects the price of crude oil to remain volatile in the near term. Uncertainty regarding the future actions of foreign oil producers, such as Saudi Arabia and Russia, and the risk that they take actions that will prolong or exacerbate the current over-supply of crude oil is also contributing to the recent decline in oil prices.
Currently, all of the Company’s property interests are not operated by the Company and involve other third-party working interest owners. As a result, the Company has limited ability to influence or control the operation or future development of such properties. In light of the current price and economic environment, the Company continues to be proactive with its third-party operators to review spending and alter plans as appropriate.
The Company is focused on maintaining its operations and system of controls remotely and has implemented its business continuity plans in order to allow its employees to securely work from home. The Company was able to transition the operation of its business with minimal disruption and to maintain its system of internal controls and procedures.
Liquidity and Capital Resources
At June 30, 2020, we had $19.7 million in cash and cash equivalents, primarily impacted by the $9.3 million purchase of certain mineral interests in Hamilton Dome field in November 2019, compared to $31.6 million of cash and cash equivalents at June 30, 2019.
In addition, the Company has a senior secured reserve-based credit facility (the "Facility") with a maximum capacity of $50 million subject to a borrowing base determined by the lender based on the value of our oil and gas properties. The Facility had a $27 million borrowing base on June 30, 2020. However, our ability to access the borrowing base is also limited by our compliance with certain financial covenants, including a debt service ratio covenant, described below. As a consequence of declining oil prices adversely impacting our EBITDA upon which the debt service ratio is calculated, at June 30, 2020 our borrowings would have been limited to approximately $8 million. There are no borrowings outstanding under the Facility, which matures on April 11, 2021. The Facility is secured by substantially all of the reserves associated with the Delhi field.
Any future borrowings bear interest, at the Company's option, at either the London Interbank Offered Rate ("LIBOR") plus 2.75% or the Prime Rate, as defined under the Facility, plus 1.0%. The Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not more than 3.0 to 1.0, (ii) a debt service coverage ratio of not less than 1.1 to 1.0 and (iii) a consolidated tangible net worth of not less than $50.0 million, each as defined in the Facility. The Facility also contains other customary affirmative and negative covenants and events of default. As of June 30, 2020, the Company was in compliance with all covenants contained in the Facility.
The Company has historically funded operations through cash from operations and working capital. The primary source of cash is the sale of produced oil and natural gas liquids. A portion of these cash flows is used to fund capital expenditures. The Company expects to manage future development activities in the Delhi field and the limited capital maintenance requirements of the Hamilton Dome field within the boundaries of its operating cash flow and existing working capital.
The Company is pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, the Company has limited access to an undrawn borrowing base available under its senior secured credit facility, The Company also has an effective shelf registration statement with the SEC under which the Company may issue up to $500 million of new debt or equity securities.
30
Table of Contents
During the fiscal year ended June 30, 2020, the Company funded operations, capital expenditures and cash dividends with cash generated from operations resulting in a decrease of $11.9 million in cash. Uses of cash included the acquisition of the Hamilton Dome field ($9.3 million), cash dividends on common shares ($10.7 million) and repurchasing shares under the buyback program ($2.5 million). As of June 30, 2020, working capital was $21.0 million, a decrease of $9.3 million over working capital of $32.4 million at June 30, 2019.
The Board of Directors instituted a cash dividend payable on shares of our common stock in December 2013. The Company has since paid 27 consecutive quarterly dividends. Distribution of a substantial portion of cash flow in excess of operating and capital requirements through cash dividends is a priority of the Company’s financial strategy. However, due to current depressed price environment and a desire to preserve cash to potentially pursue opportunities that will grow dividends over time, the Board of Directors believed it was in the best interest of the Company to reduce its quarterly dividend rate from $0.10 per share to $0.025 per share, effective in the quarter ending June 30, 2020. The reduced dividend rate will continue to reward shareholders with a yield of approximately 3% at current stock price levels. The Company intends to grow dividend levels as appropriate.
In May 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company’s common stock. The Company monitors its stock price and looks to opportunistically purchase its common stock when market conditions are deemed to be appropriate. During the year ended June 30, 2020, the Company purchased 440,666 shares at an average cost of $5.51 per share bringing its total to $4.0 million to purchase 706,858 common shares at an average price of $5.72 per share.
In early March 2020, oil prices declined rapidly. As a consequence of unprecedented commodity price volatility and uncertainty on April 6, 2020, the Company elected to enter into NYMEX WTI oil swaps covering 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. The fixed price swap contracts will significantly reduce volatility in the Company's near-term realized oil price and resulting revenues, thus supporting its current business plans and objectives. The Company expects to have sufficient liquidity to meet all its identified cash requirements for at least the next 12 months.
Capital Expenditures
For the year ended June 30, 2020, we incurred $11.8 million on capital projects consisting of $9.3 million for the acquisition of Hamilton Dome field, $0.9 million for a non-cash asset addition related to Hamilton Dome asset retirement obligations, $1.5 million at the Delhi field (primarily for the NGL plant and completion of the water curtain) and $0.1 million for capital workovers at Hamilton Dome.
Based on discussions with the Delhi and Hamilton Dome operators, we expect to continue to perform conformance workover projects and will likely incur additional maintenance capital expenditures, primarily at the Delhi field. Such amounts are not known or approved but we expect such expenditures to be in the range of $0.75 million to $1.0 million over the next 12 months. In addition, we have planned for Delhi Phase V development expenditures of approximately $1.9 million to be incurred in the fourth quarter of our fiscal 2021. Phase V development expenditures are expected to total $8.6 million with $3.7 million to be incurred in fiscal 2022 and the remainder over the next two years.
Our proved undeveloped reserves at June 30, 2020 included 1.86 MMBOE of reserves and approximately $8.6 million of future development costs associated with Phase V development in the eastern portion of the field. Such development requires participation by both the operator and the Company. Based on our discussions with the operator, we expect drilling to commence in fiscal 2022, but the timing of Phase V is also dependent, in part, on the field operator's available funds and capital spending plans and priorities within its portfolio of properties.
Funding for our anticipated capital expenditures over the next 24 months is expected to be met from cash flows from operations and current working capital.
Full Cost Pool Ceiling Test
At the year ended June 30, 2020, our capitalized costs of oil and gas properties were below the full cost valuation ceiling; however, we could experience an impairment if current price levels persist or worsen. The trend of lower oil prices reduced the excess, or cushion, of our valuation ceiling over our capitalized costs in the current quarter and may adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and gas properties will not be required in the future. Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and 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 gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the
31
Table of Contents
average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test at June 30, 2020 were $47.37 per barrel of oil and $9.00 per barrel of natural gas liquids. A significant decline from these prices would likely result in a ceiling test impairment charge.
Overview of Cash Flow Activities
The table below compares a summary of our consolidated statements of cash flows for year ended June 30, 2020 and 2019.
Increases (Decreases) in Cash: 2020 2019 Difference
(In Millions)
Net cash provided by operating activities $ 12.4 $ 24.1 $ (11.7 )
Net cash used in investing activities (11.1 ) (6.8 ) (4.3 )
Net cash used in financing activities (13.2 ) (13.4 ) 0.2
Change in cash, cash equivalents and restricted cash $ (11.9 ) $ 3.9 $ (15.8 )
Cash provided by operating activities in the current year decreased $11.7 million compared to fiscal 2019. The difference is primarily as the result of decrease in net income of $9.4 million due to lower realized commodity prices together with a $3.2 million increase in cash used by operating assets and liabilities. Enhanced Oil Recovery credits claimed on income tax returns for fiscal 2019, 2018 and 2017 resulted in an income tax refund receivable that contributed to the use of cash by operating activities.
Cash used in investing activities decreased $4.3 million primarily due to the acquisition of the Hamilton Dome field in November 2019. The decrease is partially offset by a reduction in capital expenditures in fiscal 2020 due to the decrease in realized commodity prices.
Cash used in financing activities remained relatively flat year over year as the reduction in cash used for cash dividends was offset by the Company's common share repurchase program in fiscal 2020. The Company reduced its quarterly dividend rate from $0.10 per share to $0.025 per share for the fourth quarter of fiscal year 2020. The Company spent a total of $2.5 million to purchase 440,666 shares of its common stock at an average price of $5.51.
Contractual Obligations and Other Commitments
The table below provides estimates of the timing of future payments that, as of June 30, 2020, we are obligated to make under our contractual obligations and commitments. We expect to fund these contractual obligations with cash on hand and cash generated from operations.
Payments Due by Period
Total Less than1 Year 1 - 3 Years 3 - 5 Years More than 5 Years
Contractual Obligations
Other Obligations
32
Table of Contents
Results of Operations
Years Ended June 30, 2020 and 2019
Revenues
Compared to the prior fiscal year, fiscal 2020 revenues decreased 31.5% due to 32.1% lower realized commodity prices. The decrease is partially offset by a very slight increase in production volumes. The following table summarizes total production volumes, daily production volumes, average realized prices and revenues:
Years Ended June 30,
Oil and gas production
Natural gas (BOEPD, net) — 1 (1 ) n.m
n. m. Not meaningful.
33
Table of Contents
(Gain) Loss on Derivative Contracts
Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in crude 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.
Years Ended June 30,
Oil Derivative Contracts
Realized (gain) loss on derivatives, net $ (528,139 ) $ — $ (528,139 ) n.m.
Crude oil price per Bbl (including impact of realized derivatives) $ 45.59
n. m. Not meaningful.
Production Costs
Production costs (also referred to as lease operating expenses) are presented in two components: (i) CO2 costs for the Delhi field and (ii) other production costs for both the Delhi and Hamilton Dome fields. The $0.8 million decrease in total production costs was due to a 47.5% decrease in CO2 costs. The decrease is partially offset by a 31.8% increase in other production costs.
Years Ended June 30,
(a) Under our contract with the operator, purchased CO2 is priced at 1% of the realized oil price in the field per Mcf, plus sales taxes and transportation costs as per contract terms.
Years Ended June 30,
The $3.2 million decrease in CO2 costs was due to a 39.1% decrease in rate of purchased volumes together with a 14.4% decrease in price per Mcf associated with the lower realized oil price. The upstream pipeline that supplies CO2 to the Delhi field was shut-in on February 22, 2020, when a pressure loss was detected. CO2 purchases were temporarily suspended through our fiscal year-end. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. The recycle facilities continued to operate as usual during the purchase pipeline suspension. The pipeline is owned and operated by Denbury Resources, and the Company does not have any ownership in the portion of the pipeline under repair. The operator expects the pipeline to be back in service in October 2020.
Compared to fiscal 2019, "Other production costs" increased 31.8% primarily due to the acquisition of the Hamilton Dome field in November 2019. The Delhi field's "Other production costs" decreased slightly by 5.6% impacted by cost control measures as a result of lower oil prices.
Compared to fiscal 2019, Delhi field costs decreased 15% to $16.50 per BOE of Delhi current year production primarily due to lower CO2 costs, as discussed above.
34
Table of Contents
For fiscal 2020, Hamilton Dome field costs per BOE were $28.93.
Depletion, Depreciation and Amortization ("DD&A")
Total DD&A expense was 7.9% lower compared to the same one year-ago period due to an 8.7% decrease in the oil and gas DD&A amortization rate; the volume change between the two periods was very slight. The integration of the Hamilton Dome asset contributed to an overall lower composite DD&A per BOE rate.
Years Ended June 30,
Oil and gas DD&A per BOE $ 7.51 $ 8.29 $ (0.78 ) (9.4 )%
General and Administrative Expenses
Total general and administrative expenses for fiscal 2020 increased $0.2 million, or 3.7%, to $5.3 million from the same year-ago period. The increase is primarily due to higher non-cash stock-based compensation of $0.4 million related to new grants associated with the hiring of a new executive officer and increased consulting expense of $0.1 million, partially offset by a decrease of $0.3 million in bonus expense.
35
Table of Contents
Other Income and Expenses
Other income and expenses (net) decreased due primarily to the non-recurring Enduro transaction breakup fee income received during fiscal 2019. During May 2018, the Company entered into a Purchase and Sale Agreement to acquire, as the "stalking horse" bidder, certain oil and gas assets from an affiliate of Enduro Resource Partners LLC ("Enduro") for a purchase price of $27.5 million, subject to the outcome of Enduro's Chapter 11 process. In the first quarter of 2019, the Company was repaid its deposit together with related earned interest when a higher bidder first emerged in the bidding process. Interest income is lower due to lower invested balances together with declining interest rates.
Years Ended June 30,
Net Income
Net income available to common stockholders for the year ended June 30, 2020 decreased $9.4 million, or 61%, to $5.9 million compared to the last fiscal year. Pre-tax income decreased due to the aforementioned revenue and expense variances. Our income tax provision decreased primarily due to lower pre-tax income as our effective income tax rate was relatively unchanged from the year-ago period. During the current period, we recorded a $2.8 million income tax benefit related to Enhanced Oil Recovery credits claimed on income tax returns for fiscal 2019, 2018 and 2017 .
Years Ended June 30,
36
Table of Contents
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our consolidated financial statements. Our significant accounting policies are included in Note 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.
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 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 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, 2020, we had no unevaluated property costs. Oil and natural gas property costs included represent non-producing leasehold, geological 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 geological, 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 geological and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates prepared by our third party independent engineers represent the most accurate assessments possible, the subjective decisions and variances in available data for the properties make these estimates generally less precise than other estimates included in our financial statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect our estimated future net cash flows of our proved reserves. These changes could affect our quarterly ceiling test calculation and could significantly affect our depletion rate. A 10% decrease in commodity prices used to determine our proved reserves as of June 30, 2020 would not have resulted in an impairment of our oil and natural gas properties. Holding all other factors constant, a reduction in the Company's proved reserve estimates at June 30, 2020 of 5%, 10% and 15% would affect depreciation, depletion, and amortization expense by approximately $290,000, $612,000, and $970,000, respectively.
On December 31, 2008, the SEC issued its final rule on the modernization of reporting oil and 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 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 gas operations, and revises accounting for the limitation on capitalized costs for full cost companies.
Valuation of Deferred Tax Assets. We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared or filed; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carry backs and carry forwards. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets (primarily our net operating loss). If recovery is not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover; this would result in an increase to our income tax expense. As of June 30, 2020, we have recorded a valuation allowance for the portion of our net operating loss that is limited by IRS Section 382.
37
Table of Contents
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. 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, we believe that it is more likely than not that the Company will realize the benefits of its net deferred tax assets at the time of this report. If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax provision would increase in the period it is determined that recovery is not probable.
Stock-based Compensation. The fair value and expected vesting period of the Company's market-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 the Company's 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 market-based awards is based on the Company's total common stock return compared to a peer group of other companies in our industry with comparable market capitalizations and, for certain awards, the Company's share price attaining a set target.
Recent Accounting Pronouncements. Refer to Note 2 to our consolidated financial statements in Item 8. Consolidated Financial Statements and Supplementary Data for discussion of the recent accounting pronouncements issued by the Financial Accounting Standards Board.
Off Balance Sheet Arrangements
The Company has no off-balance sheet arrangements as of June 30, 2020.
Item 7A. Quantitative and Qualitative Disclosures About Market Risks
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. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.
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 natural gas liquids 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 prices.We do not enter into derivative contracts for speculative trading purposes. In early March 2020, oil prices declined rapidly. As a consequence of unprecedented commodity price volatility and uncertainty on April 6, 2020, we elected to enter into NYMEX WTI oil swaps covering 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. The fixed price swap contracts will significantly reduce volatility in our near-term realized oil price and resulting revenues, thus supporting our current business plans and objectives.
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. As of June 30, 2020, we did not post collateral under our derivative contract as it is an uncollateralized trade. 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 20 to our consolidated financial statements for more details.
38
Table of Contents
Item 8. Consolidated Financial Statements and Supplementary Data
Index to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm 40
Notes to Consolidated Financial Statements 45
39
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
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, 2020 and 2019, 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, 2020 and 2019, 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 audits 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.
/s/ Moss Adams LLP
Houston, Texas
September 10, 2020
We have served as the Company’s auditor since 2017.
40
Table of Contents
Evolution Petroleum Corporation and Subsidiaries
Consolidated Balance Sheets
Assets
Current assets
Receivables for federal and state income tax refunds 3,243,271 —
Property and equipment, net of depreciation, depletion, and amortization
Liabilities and Stockholders' Equity
Current liabilities
Derivative contract liabilities 1,911,343 —
Long term liabilities
Operating lease liability 84,978 —
Commitments and contingencies (Note 16)
Stockholders' equity
See accompanying notes to consolidated financial statements.
41
Table of Contents
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
Years Ended June 30,
Revenues
Operating costs
Net loss on derivative contracts 1,383,204 —
Other
Enduro transaction breakup fee — 1,100,000
Net income (loss) attributable to common shareholders $ 5,937,072 $ 15,377,066
Earnings per common share
Weighted average number of common shares outstanding
See accompanying notes to consolidated financial statements.
42
Table of Contents
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Cash Flows
Years Ended June 30,
Cash flows from operating activities
Settlement of asset retirement obligations (76,832 ) —
Net loss on derivative contracts 1,383,204 —
Payments received for derivative settlements 793,327 —
Changes in operating assets and liabilities:
Prepaid expenses and other current assets (33,408 ) 66,229
Accounts payable and accrued expenses (486,010 ) (90,891 )
Cash flows from investing activities
Acquisition of oil and gas properties (9,337,716 ) —
Development of oil and natural gas properties (1,724,829 ) (6,746,142 )
Capital expenditures for other property and equipment — (11,509 )
Cash flows from financing activities
* Neither annual period had any restricted cash balances.
See accompanying notes to consolidated financial statements.
43
Table of Contents
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Changes in Stockholders' Equity
For the Years Ended June 30, 2020 and 2019
Common Stock
AdditionalPaid-inCapital RetainedEarnings TreasuryStock TotalStockholders'Equity
Shares Par Value
Forfeitures of restricted stock — — — — — —
Forfeitures of restricted stock (49,118 ) (49 ) 49 — — —
See accompanying notes to consolidated financial statements.
44
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 – Organization and Basis of Preparation
Nature of Operations.Evolution Petroleum Corporation is an oil and gas company focused on delivering a sustainable dividend yield to its shareholders through the ownership, management, and development of producing oil and gas properties. The Company's long-term goal is to build a diversified portfolio of oil and gas assets primarily through acquisition, while seeking opportunities to maintain and increase production through selective development, production enhancement, and other exploitation efforts on its properties.
Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO2 enhanced oil recovery project, our interests in the Hamilton Dome field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, and overriding royalty interests in two onshore Texas wells.
Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements of prior periods include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported net income or stockholders' equity.
Risk and Uncertainties. The Company is continuously monitoring the current and potential impacts of the COVID-19 pandemic on its business, including how it has and may continue to impact its financial results, liquidity, employees and the operations of the Delhi and Hamilton Dome fields in which we hold non-operated interests. During the six months ended June 30, 2020, primarily driven by the COVID-19 pandemic and actions taken by OPEC+, the benchmark price of WTI has declined to levels that have adversely impacted our earnings and reduced the maximum amount we could borrow under our senior secured facility.
In response to the pandemic, both of our operators have taken actions such as reducing operating and capital expenditures. At Hamilton Dome the operator has also temporarily shut-in some producing wells. In addition to the above, we also believe the pandemic has slowed the repair schedule of the Delhi CO2 supply pipeline which together with the foregoing have negatively impacted our production. All of the Company’s 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. However, the Company has been proactive with its third-party operators to review spend 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.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include (a) reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, (b) asset retirement obligations, (c) stock-based compensation, (d) fair values of derivative assets and liabilities, (e) income taxes and the valuation of deferred tax assets, and (f) commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.
Note 2 – Summary of Significant Accounting Policies
Cash and Cash Equivalents. We consider all highly liquid investments, with original maturities of 90 days or less when purchased, to be cash and cash equivalents.
Restricted Cash. Funds legally designated for a specified purpose are classified as restricted cash. Such a balance is classified on the statement of financial position as either current or non-current depending on its expected use. At June 30, 2020 and 2019, we had no such balances.
45
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable consist of accrued hydrocarbon revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30,2020 and 2019, no allowance for doubtful accounts was considered necessary.
Oil and Natural Gas Properties. We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. 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. Excluded costs represent investments in unproved and unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. We exclude these costs until the project is evaluated and proved reserves are established or impairment is determined. Excluded costs are reviewed at least quarterly to determine if impairment has occurred. The amount of any evaluated or impaired oil and natural gas properties is transferred to capitalized costs being amortized.
Limitation on Capitalized Costs. Under the full-cost method of accounting, we are required, at the end of each fiscal quarter, to perform a test to determine the limit on the book value of our oil and natural gas properties (the "Ceiling Test"). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the "Ceiling", this excess or impairment is charged to expense and reflected as additional accumulated depreciation, depletion, and amortization or as a credit to oil and natural gas properties. The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10 percent and assuming continuation of existing economic conditions, of 1) estimated future gross revenues from proved reserves, which is computed using oil and natural gas prices determined 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 (with consideration of price changes only to the extent provided by contractual arrangements including hedging arrangements pursuant to SAB 103), less 2) estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves; plus (b) the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)); plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; net of (d) the related tax effects related to the difference between the book and tax basis of our oil and natural gas properties. Our Ceiling Tests did not result in an impairment of our oil and natural gas properties during the years ended June 30, 2020 and 2019.
Other Property and Equipment. Other property and equipment includes building leasehold improvements, data processing and telecommunications equipment, office furniture, and office equipment. These items are recorded at cost and depreciated over expected lives of the individual assets or group of assets, which range from three to seven years. The assets are depreciated using the straight-line method. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. Repairs and maintenance costs are expensed in the period incurred.
Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in other assets on the Company's consolidated balance sheet and are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method.
Asset Retirement Obligations. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred. It is associated with an increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The initial recognition or subsequent revision of asset retirement cost is considered a level 3 fair value
46
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
measurement. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment.
Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, and derivative instruments. Except for derivatives, the carrying amounts of these approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates, and volatility factors.
Stock-based Compensation. We estimate the fair value of stock-based compensation awards on the grant date to provide the basis for future compensation expense. Service-based and performance-based Restricted Stock and Contingent Restricted Stock awards are valued using the market price of our common stock on the grant date. Market-based awards are valued using a Monte Carlo simulation and geometric Brownian motion techniques applied to the historical volatility of the Company's total stock return compared to the historical volatilities of other companies or indices to which we compare our performance. This Monte Carlo simulation also provides an expected vesting period. For service-based awards, stock-based compensation is recognized ratably over the service period. For performance-based awards, stock-based compensation is recognized ratably over the expected vesting period when it is deemed probable, for accounting purposes, that the performance goal will be achieved. The expected vesting period may be shorter than the remaining term. For market-based awards, stock-based compensation expense is recognized ratably over the expected vesting period, so long as the award holder remains an employee of the Company. Total compensation expense is independent of vesting or expiration of the awards, except for termination of service.
Revenue Recognition - Oil and Gas. Our revenues are comprised solely of revenues from customers from the sale of crude oil, NGLs and natural gas. The Company believes that the disaggregation of revenue on its consolidated statements of operations into these three major product types appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors based on our geographic locations. Crude oil, NGL, and natural gas revenues are recognized at a point in time when production is sold to a purchaser at an index-based, determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue is a function of the contract billing terms which reference index price sources used by the industry. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required within 30 days for crude oil and 60 days for NGLs after the end of the production month. At the end of each month when the performance obligations have been satisfied, the consideration can be reasonably estimated and amounts due from customers are accrued in “Receivables from oil and gas sales” in our consolidated balance sheets. As of June 30, 2020 and 2019 receivables from contracts with customers were $1.9 million and $3.2 million, respectively.
Derivative Instruments. The Company follows ASC 815, Derivatives and Hedging ("ASC 815").From time to time, in accordance with the Company’s policy, it may hedge a portion of its forecasted oil and natural gas liquids production. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to an ISDA master agreement; the agreement provides for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net (gain) loss on derivative instruments” on the consolidated statements of operations.
Depreciation, Depletion, and Amortization ("DD&A"). The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of DD&A, estimated future development costs, and asset retirement costs (net of salvage values) not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves. Other property, consisting of leasehold building improvements and office and computer equipment, is depreciated as described above in Other Property and Equipment.
47
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Income Taxes. We recognize deferred tax assets and liabilities based on the differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that may result in taxable or deductible amounts in future years. The measurement of deferred tax assets may be reduced by a valuation allowance based upon management's assessment of available evidence if it is deemed more likely than not that some or all of the deferred tax assets will not be realizable. We recognize a tax benefit from an uncertain position when it is more likely than not that the position will be sustained upon examination which is based on the technical merits of the position. We record the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax expense.
Earnings (Loss) Per Share. Basic earnings (loss) per share ("EPS") is computed by dividing earnings or loss available to common stockholders by the weighted-average number of common shares outstanding during the period. The computation of diluted EPS is similar to the computation of basic EPS, except that the denominator is increased to include the number of additional common shares that would have been outstanding if potentially dilutive common shares had been issued. Potentially dilutive common shares are our outstanding stock options and contingent restricted common stock. We use the treasury stock method to determine the effect of potentially dilutive common shares on diluted EPS, unless the effect would be anti-dilutive. Under this method, exercise of stock options and, under certain conditions, contingent restricted common stock is assumed to have occurred at the beginning of the period (or at time of issuance, if later); common shares are assumed to have been issued. The proceeds from exercise of stock options and unamortized stock compensation expense related to restricted common stock are assumed to be used to repurchase common stock at the average market price during the period. The incremental shares (the difference between the number of shares assumed issued and the number of shares assumed repurchased) are included in the denominator of the diluted EPS computation. Contingent restricted stock is included in the computation of diluted shares, if dilutive, when the underlying performance conditions either (i) were satisfied as of the end of the reporting period or (ii) would be considered satisfied if the end of the reporting period were the end of the related contingency period.
Recently Adopted Accounting Pronouncements - Leases
Effective July 1, 2019, the Company adopted the new standard using a modified retrospective approach and elected to use the optional transition methodology whereby reporting periods prior to adoption continue to be presented in accordance with legacy accounting guidance, Accounting Standard Codification 840 - Leases. Upon transition, we recognized a right of use ("ROU") asset (or operating lease right-of-use asset) and an operating lease liability with no retained earnings impact. We applied the following practical expedients as provided in the standards update which provide elections to not reassess:
• Whether an expired or existing pre-adoption date contracts contained leases.
• Lease classification of any expired or existing leases.
• Initial direct costs for any expired or existing leases.
Adoption of the new standard did not impact our consolidated statements of operations, cash flows or stockholders’ equity. At adoption we recorded our operating lease as follows:
Asset (Liability) Balance June 30, 2019 Adjustment at Adoption July 1, 2019
Operating lease right-of-use asset $ — $ 161,125
Accrued liabilities and other:
Operating lease liability $ — $ (26,194 )
Operating lease liabilities - long-term $ — $ (139,269 )
48
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Recently Issued Accounting Pronouncements
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. Early adoption is permitted and entities must adopt the amendment using a modified retrospective approach to the first reporting period in which the guidance is effective. For smaller reporting companies, as provided by Accounting Standards Update 2019-10, Financial Instruments - Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842), ASU 2016-13 is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2022. The adoption of ASU 2016-13 is currently not expected to have a material effect on our consolidated financial statements.
In December 2019, the FASB issued ASU No. 2019-12, Income Taxes ("Topic 740") - Simplifying the Accounting for Income Taxes. ASU 2019-12 is intended to simplify accounting for income taxes. It removes certain exceptions to the general principles in Topic 740 and amends existing guidance to improve consistent application. ASU 2019-12 is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2020. Early adoption is permitted. We are currently evaluating the impact of ASU 2019-12 on our consolidated financial statements.
Note 3 – Revenue Recognition
Our revenue is primarily generated from our interests in the Delhi field in Northeast Louisiana and, our interests in the Hamilton Dome field in Wyoming. Additionally, an overriding royalty interest retained in a past divestiture of Texas properties provided de minimis revenue:
Revenues
We are a non-operator and presently do not take production in kind and do not negotiate contracts with customers. We recognize crude oil, natural gas liquids, and natural gas production revenue at the point in time when custody and title (“control”) of the product transfers to the customer. Transfer of control drives the presentation of post-production expenses such as transportation, gathering, and processing deductions within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within the production costs line item on the accompanying consolidated statements of operations, while fees and other deductions incurred subsequent to control transfer are embedded in the price and effectively recorded as a reduction of crude oil, natural gas liquids, and natural gas production revenue.
Judgments made in applying the guidance in Accounting Standards Codification Topic 606, Revenue from Contracts with Customers, relate primarily to determining the point in time when control of product transfers to the customer. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.
The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied at a point in time upon control transferring to a customer at a specified delivery point. Consideration is allocated to satisfied performance obligations at the end of an accounting period.
Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received one to two months after production has occurred, which is typical in the industry. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for the sale of the product. Estimated revenue due to the Company is recorded within the receivables line item on the accompanying consolidated balance sheets until payment is
49
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
received. The accounts receivable balances from contracts with customers as of June 30, 2020 and 2019, as presented on our respective consolidated balance sheets, were $1.9 million and $3.2 million, respectively. To estimate accounts receivable from operators' contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser. Revenue recognized during the fiscal year ended June 30, 2020 and 2019 related to performance obligations satisfied in prior reporting periods, was immaterial.
Note 4 – Leases
Operating leases are reflected as an operating lease ROU asset included in “Other assets, net”, and as a ROU liability in “Accrued liabilities and other” and “Operating lease liability” on our consolidated balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset would also include any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred, if any. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. For all operating leases, lease and non-lease components are accounted for as a single lease component.
As a non-operator in recent years and having adequate liquidity, the Company has generally not entered into lease transactions. Presently, our only operating lease is for corporate office space in Houston, Texas, effective May 1, 2019 and which expires November 30, 2022. Presently we have one operating lease for office space, no finance leases and no short-term leases.
The Company makes certain assumptions and judgments when evaluating a contract that meets the definition of a lease under Topic 842. At adoption, July 1, 2019, as our lease did not provide an implicit rate, we used our prime-rate-based borrowing rate under our senior secured credit facility as our incremental borrowing as the term facility was based on a similar term and is appropriately risk-adjusted. We determined lease term by considering any option available to extend or to early terminate the lease which we believed was reasonably certain to be exercised.
At June 30, 2020, maturities of our operating lease liability are as follows:
Fiscal Year Operating Lease Liability
Less imputed interest (8,617 )
Total lease liability $ 139,269
50
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Supplemental cash flow, balance sheet, and other disclosures information related to our operating leases are as follows:
As of and For the Year Ended June 30, 2020
Cash Flow:
Cash paid for amounts included in the measurement of lease liabilities $ 4,903
ROU asset added in exchange for lease obligation at adoption 161,125
Balance Sheet:
Operating lease ROU asset (included in other assets) 117,193
Accrued liabilities - current 54,290
Operating lease liability - long-term 84,978
Other:
Weighted average remaining lease term in years 2.66
Weighted average discount rate 5.15 %
Note 5 – Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets $ 491,686 $ 458,278
Note 6 – Property and Equipment
Oil and natural gas properties:
Unproved properties not subject to amortization — —
Other property and equipment:
Furniture, fixtures and office equipment, at cost 154,731 154,731
Other property and equipment, net $ 17,639 $ 26,418
As of June 30, 2020 and 2019, all oil and gas property costs were being amortized.
During the years ended June 30, 2020 and 2019, the Company incurred capital expenditures of $1.5 million and $5.2 million, respectively.
Hamilton Dome Acquisition
On November 1, 2019, and effective as of October 1, 2019, our wholly-owned subsidiary, Evolution Petroleum West, Inc., a Delaware corporation, purchased a 23.5% non-operated working interest and a 19.7% revenue interest in the Hamilton Dome unitized field located in Hot Springs County, Wyoming, from entities owned or controlled by Merit Energy Company ("Merit") of Dallas, Texas. At closing on November 1, 2019, we paid a cash purchase price of $9.5 million subject to customary purchase
51
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
price adjustments, which were settled in December 2019 upon our receipt of a $0.2 million cash payment made by Merit. Given the effective date of the transaction, the purchase price adjustment consisted of our interest's share of sales proceeds from October sales net of our share of operating expenses. Commencing November 1, 2019, we began recording our share of Hamilton Dome revenues, related expenses, and capital costs. In connection with this acquisition, the Company recorded a $0.9 million non-cash addition of asset retirement obligations of wells and related assets.
The unit includes producing and water injection wells and associated facilities producing crude oil from proved developed reserves. There were no proved undeveloped reserves. We accounted for this acquisition transaction as an asset purchase.
Note 7–Other Assets
Less: Accumulated amortization of royalty rights (61,037 ) (47,474 )
Less: Accumulated amortization of deferred loan costs (157,084 ) (141,927 )
Right of use asset under operating lease 161,125 —
Less: Accumulated amortization of right of use asset (43,932 ) —
Less: Accumulated amortization of software license (14,350 ) (7,462 )
Our royalty rights and investment in Well Lift, Inc. ("WLI") resulted from the separation of our artificial lift technology operations in December 2015. We conveyed our patents and other intellectual property to WLI and retained a 5% royalty on future gross revenues associated with the technology. We own 17.5% of the common stock of WLI and account for our investment in this private company at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer, if such were to occur. The Company evaluates the investment for impairment when it identifies any events or changes in circumstances that might have a significant adverse effect on the fair value of the investment.
Note 8–Accrued Liabilities and Other
Asset retirement obligations due within one year — 50,244
Payable for settled derivatives 265,188 —
Operating lease liability, current 54,290 —
52
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 9 – Asset Retirement Obligations
Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon, and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a reconciliation of the beginning and ending asset retirement obligations for the years ended June 30, 2020 and 2019:
Years Ended
Asset retirement obligations — beginning of period $ 1,610,845 $ 1,422,955
Liabilities settled (86,592 ) (b) —
Less: current asset retirement obligations — (50,244 )
Long-term portion of asset retirement obligations $ 2,588,894 $ 1,560,601
(a) Liabilities incurred in fiscal 2020 included $0.9 million from our acquisition of our Hamilton Dome interest and remainder related to facilities at the Delhi field.
(b) We abandoned one well in the Delhi field and four wells in the Hamilton Dome field.
Note 10 – Stockholders' Equity
Common Stock
As of June 30, 2020, we had 32,956,469 shares of common stock outstanding.
The Company began paying quarterly cash dividends on common stock in December 2013. As of June 30, 2020, we have cumulatively paid $70.2 million in cash dividends. We paid dividends of $10,740,754 and $13,272,058 from retained earnings to our common shareholders during the years ended June 30, 2020 and 2019, respectively. The following table reflects the dividends paid per common share in each quarter within the respective two fiscal years:
Fiscal Year
In May 2015, the Board of Directors approved a share repurchase program covering up to 5 million of the Company's common stock. Since inception of the program through June 30, 2020, the Company has spent $4.0 million to repurchase 706,858 common shares at an average price of $5.72 per share. Under the program's terms, shares are repurchased only on the open market and in accordance with the requirements of the SEC. Such shares are initially recorded as treasury stock, then subsequently canceled. The timing and amount of repurchases depends upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and it may be suspended or discontinued at any time.
The Company has also acquired treasury stock from holders of newly vested stock-based awards to fund the recipients' payroll tax withholding obligations. Such shares were valued at fair market value on the date of vesting.
53
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The treasury shares were subsequently canceled. The following summarized the Company's treasury stock purchases in its last two fiscal years.
Common Shares Acquired Average Price per Share Treasury Stock Purchases
Shares surrendered for tax withholding upon vesting 9,255 $5.90 $ 54,565
Shares surrendered for tax withholding upon vesting 17,994 $8.57 $ 154,179
Tax Treatment of Dividends to Recipients
Based on our current projections for the fiscal year ended June 30, 2020, we expect that all common stock dividends for this fiscal year will be treated for tax purposes as qualified dividend income to the recipients. For the fiscal year ended June 30, 2019, all common stock dividends for that fiscal year were treated for tax purposes as qualified dividend income to the recipients.
Note 11—Stock-Based Incentive Plan
At the December 8, 2016 annual meeting, the stockholders approved the adoption of the Evolution Petroleum Corporation 2016 Equity Incentive Plan (the “2016 Plan”), which replaced the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "2004 Plan"). The 2016 Plan authorizes the issuance of 1,100,000 shares of common stock prior to its expiration on December 8, 2026. Incentives under the 2016 Plan may be granted to employees, directors, and consultants of the Company in any one or a combination of the following forms: incentive stock options, non-statutory stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, performance share awards, performance cash awards, and other forms of incentives valued in whole or in part by reference to, or otherwise based on, our common stock, including its appreciation in value. As of June 30, 2020, 390,489 shares remained available for grant under the 2016 Plan.
All remaining outstanding awards granted under the 2004 Plan have vested during the year ended June 30, 2020.
Restricted Stock and Contingent Restricted Stock
The Company may award grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after a maximum of four years if unvested, contain service-based, performance-based, and market-based vesting provisions. The common shares underlying the Restricted Stock grants are issued on the date of grant. Contingent Restricted Stock grants vest only upon the attainment of typically higher performance-based or market-based vesting thresholds and are issued only upon vesting. Shares underlying Contingent Restricted Stock awards are reserved from the Plan under which they were granted under.
In July 2019, the new chief executive officer upon his employment received 48,872 shares of serviced-based restricted common stock which vest in three equal amounts on June 30, 2020, 2021 and 2022. He was also awarded a total of 200,000 market-based restricted stock units consisting of four equal tranches, each of which may vest only if its respective stock price requirement is met before the award term expires. Each tranche has a separate stated price requirement and respective vesting will occur only if, before July 1, 2023, the ninety-day trailing average Company stock share price equals or exceeds its tranche price requirement.
During the year ended June 30, 2020, we also granted 52,119 service-based and 104,236 market-based Restricted Stock awards to our employees as well as 56,395 service-based awards to the Company's directors.
54
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Service-based awards vest with continuous employment by the Company, generally in annual installments over a three- or four-year period. Certain awards may contain other vesting periods, including quarterly installments and one-year vesting. Restricted Stock grants, which vest based on service, are valued at the fair market value on the date of grant and amortized over the service period.
Performance-based grants vest upon the attainment of earnings, revenue, and other operational goals and require that the recipient remain an employee or director of the Company through the vesting date. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period based on the grant date fair value when it is deemed probable, for accounting purposes, that the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the term of the award. As of June 30, 2020, there were no performance-based awards outstanding.
Market-based awards vest if their respective two- or three-year trailing total returns on the Company’s common stock exceed the corresponding total returns of various quartiles of indices consisting of either peer companies or a broad market index of companies in our industry. More recent market-based awards vest if the average of the Company's closing stock prices over defined quarterly measurement periods together with accumulated paid dividends exceeds a defined value. The fair values and expected vesting periods of these awards are determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies in the index. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the holder remains an employee or director of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service.
Assumptions used in the Monte Carlo simulation valuations for the years ended June 30, 2020 and 2019 were:
Year Ended June 30,
Weighted average fair value of market-based awards granted $ 3.79 $ 8.24
Dividend yield 6% to 7.2% 4.0 %
Unvested Restricted Stock awards at June 30, 2020 consisted of the following:
Award Type Number ofRestrictedShares WeightedAverageGrant-DateFair Value
55
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table sets forth the Restricted Stock transactions for the year ended June 30, 2020:
The following is a summary of Restricted Stock that vested during the last two fiscal years:
Year Ended June 30,
Vesting-date intrinsic value of Restricted Stock $ 477,647 $ 1,141,631
Grant-date fair value of vested Restricted Stock $ 748,893 $ 909,678
The following table summarizes Contingent Restricted Stock activity for the year ended June 30, 2020:
All of these outstanding awards at June 30, 2020 are market-based awards.