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 natural gas industry and our Company
A substantial or extended decline in oil and natural gas 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 and natural gas significantly influences our revenue, profitability, access to capital, and future rate of growth. Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. For example, average daily prices for WTI oil ranged from a high of $74 per barrel to a low of a negative $38 per barrel, and Henry Hub natural gas prices ranged from a high of $23.86 to a low of $1.33 per MMBTU over our last two fiscal years. Historically, the markets for oil, natural gas, and natural gas liquids have been volatile and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control, including, but not limited to the following:
•changes in global supply and demand for oil and natural gas, which has been negatively affected by concerns about the impact of COVID-19;
•worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
•actions of OPEC+ or other groups of oil producing nations;
•the price and quantity of imports of foreign oil and natural gas;
•political conditions in or affecting other oil-producing and natural gas-producing countries;
•governmental, scientific, and public concern over the threat of climate change arising from greenhouse emissions;
•the level of global oil and natural gas exploration and production;
•the level of global oil and natural gas inventories;
•localized supply and demand fundamentals of regional, domestic, and international transportation availability;
•weather conditions, natural disasters, and seasonal trends;
•domestic and foreign governmental regulations;
•speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
•price and availability of competitors' supplies of oil and natural gas;
•technological advances affecting energy consumption; and
•the price 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, natural gas, and NGL prices will reduce our cash flows, borrowing ability, the present value of our reserves, and our ability to develop future reserves. We may be unable to obtain needed capital or financing on satisfactory terms. Low oil, natural gas, and NGL prices may also reduce the amount of oil, natural gas, and NGL that we can produce economically, which could lead to a decline in our oil, natural gas and NGL reserves. At June 30, 2021, approximately 36% of our proved reserves are oil reserves, 35% are natural gas and 29% are NGL reserves. As such, we are heavily impacted by movements in natural gas and oil prices, the latter also influencing NGL prices. To the extent that we have not hedged our production with derivative contracts or fixed-price contracts, any significant and extended decline in oil, natural gas, and NGL prices may adversely affect our financial position.
Our revenues are concentrated in three 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, the Hamilton Dome field in Wyoming, and the Barnett Shale in Texas and thus our current revenues are concentrated from these fields. Any significant downturn in production, oil, natural gas, and NGL prices, or other events beyond our control which impact these fields could have a material adverse effect on our results of operations and financial results. We are not the operator of these fields, and our revenues and future growth are heavily dependent on the success of operations, which we do not control.
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.
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In general, the volumes of production from 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 naturally decline. Our production is heavily dependent on our interests in EOR production that began during March 2010 in the Delhi field and our interests in the Hamilton Dome field in Wyoming and Barnett Shale in Texas. Environmental or operating problems or lack of extended future investment in any of these assets could cause our net production of oil, natural gas, and NGLs to decline significantly over time, which could have a material adverse effect on our financial condition. In fiscal 2021, our production was impacted by the operators of the Delhi and Hamilton Dome 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, 2021, Merit has reactivated the inventory of shut-in wells capable of supporting their expenses 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 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 consist of our interests in Delhi field, Hamilton Dome field, and the Barnett Shale. A materially negative change in any of our operator’s financial condition could negatively affect operations (or timing thereof) in these assets, and consequently our income (or timing thereof) from these assets as well as the value of our interests in these assets.
Any significant downturn in production or other events beyond our control which impact our assets could have a material adverse effect on our results of operations and financial results (or timing thereof).
We are not the operator of the Delhi field. It is operated by a subsidiary of Denbury 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.
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 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 substantially reduced its debt, strengthened its balance sheet, and positioned Denbury to free up capital for investment in properties such as Delhi again.
We are not the operator of the Hamilton Dome field. It is operated by Merit, a private oil and natural gas company. Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.
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We are not the operator of the Barnett Shale assets. At the time of acquisition, approximately 90% of the wells in the Barnett Shale field were operated by Blackbeard, and the remaining 10% of wells were operated by seven other operators. Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.
In May 2021, Blackbeard announced an agreement to sell its interest in the Barnett Shale assets to Diversified Energy. The transaction closed in July 2021, with Diversified Energy taking over as operator. Our revenues and future growth are heavily dependent on a smooth transition of operations from Blackbeard to Diversified Energy and the success of operations under Diversified Energy, which we do not control.
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, while our Barnett Shale assets produce from deeper reservoirs. Shallower reservoirs usually have lower pressure, which generally translates into lower reserve volumes in place. Deeper reservoirs have higher pressures and usually more reserve volumes, but capturing those reserves often comes at increased drilling and completion cost and risk. Low permeability reservoirs require more wells and substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of sufficient un-depleted fractures to establish commercial production. Depleted reservoirs require successful application of newer technology to produce incremental reserves.
Our CO2-EOR project in the Delhi field, operated by Denbury, 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 ultimately cause 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.
Oil and natural gas development, re-completion of wells from one reservoir to another reservoir, restoring wells to production, and drilling and completing new wells are speculative activities which involve numerous risks and substantial uncertain costs.
Our growth will be partially dependent upon the success of our future development program. Drilling for oil and natural gas and extracting NGLs and re-working existing wells involve numerous risks. The risk that no commercially productive oil or natural gas reservoirs will be encountered is paramount. The cost of drilling, completing, and operating wells is substantial and uncertain; drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including, but not limited to:
•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
•shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.
Drilling or re-working is a highly speculative activity. Even when fully and correctly utilized, modern well completion and production techniques such as horizontal drilling or CO2 injection, do not guarantee that we will find and produce oil 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 ensure that these projects can be successfully developed or that the wells discussed will, if drilled, encounter reservoirs of commercially productive oil or natural gas.
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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, 2021, one purchaser accounted for approximately 62% of our total oil revenues. We do not currently market our share of oil, natural gas, and NGLs production from the Delhi field, the Hamilton Dome field, or the Barnett Shale. Although we have the right to take our working interest production in-kind, we are currently accepting terms under the operators' agreements for the delivery and pricing of our oil, natural gas and NGLs. The loss of a large purchaser for our oil production could negatively impact the revenue we receive. We cannot guarantee that we could readily find other purchasers for our oil and natural gas production.
Our oil and natural gas reserves are only estimates and may prove to be inaccurate.
There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values. Our reserves are only estimates that may prove to be inaccurate because of these inherent uncertainties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot always be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves depend upon a number of variable factors. These factors include historical production from the area compared with production from other comparable producing areas, assumptions concerning effects of regulations by governmental agencies, future oil and natural gas product prices, future operating costs, severance and excise taxes, development costs, work-over costs, and remedial costs. Some or all of these assumptions utilized in estimating reserve volumes may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of reserves, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected from reserves may vary substantially depending on the timing and different engineers preparing reserves estimates.
Accordingly, reserve estimates may be subject to downward or upward adjustments. Actual production, revenue, and expenditures with respect to our reserves will likely vary from estimates; such variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated oil and natural gas reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor. Interest rates in effect vary from time to time based on risks associated with us or the oil and natural gas industry in general. The Standardized Measure does not necessarily correspond to market value.
Regulatory and accounting requirements may require substantial reductions in reporting proven reserves.
On a periodic basis, we review the carrying value of our oil and natural gas properties under the applicable rules of various regulatory agencies, including the SEC. Under the full cost method of accounting that we use, the after-tax carrying value of our oil and natural gas properties may not exceed the present value of estimated future net after-tax cash flows from proved reserves, discounted at 10%. Application of this “ceiling” test requires pricing future revenues at the previous 12-month average beginning-of-month price and requires a write-down of the carrying value for accounting purposes if the ceiling is exceeded. We may in the future be required to write down the carrying value of our oil and natural gas properties when oil and natural gas prices are depressed or unusually volatile. Whether we will be required to take such a charge will depend in part on the prices of oil and natural gas during the previous period and the effect of reserve additions or revisions and capital expenditures during such period. If a write-down is required, it would result in a current charge to our earnings but would not impact our current cash flow from operating activities. A large write-down could adversely affect our compliance with the current financial covenants under our credit facility, could limit our access to future borrowings under that facility, or require repayment of any amounts that might be outstanding at the time.
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 NGLs, we have, and may in the future, enter into derivative arrangements for a portion of our oil, natural gas, and NGLs production. Derivative arrangements may include costless collars and fixed-price swaps. We have not historically designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our future derivative instruments. Derivative arrangements may also expose us to the risk of financial loss in some circumstances, including, but not limited to, if:
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•production is less than the volume covered by the derivative instruments;
•the counterparty to the derivative instrument defaults on its contract obligations; or
•there is a change in the expected differential between the underlying price in the derivative instrument and actual price received.
In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil, natural gas and NGLs and may expose us to cash margin requirements.
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
•the Delhi field operator's ability to: (i) deliver sufficient quantities of CO2 from its reserves in the Jackson Dome, (ii) secure all of the development capital necessary to fund its and our cost interests, and further develop the Delhi field, such as advancement of Phase V development in the undeveloped eastern part of the field, (iii) successfully manage technical, operating, environmental, strategic and logistical development and operating risks, and (iv) maintain its own financial stability.
We cannot ensure 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.
Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times. From time to time, we may require additional financing in order to carry out our oil and natural gas acquisitions, exploitation, and development activities. Certain portions of our undeveloped leasehold acreage may be subject to expiration unless production is established. If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our current production. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available to us on favorable terms.
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;
•validity of the seller's title to properties, which may be less than expected at closing; and
•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
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necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Moreover, in the event of such an acquisition, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions, which could materially adversely affect our financial condition, results of operations, or cash flows.
Significant acquisitions and other strategic transactions may involve other risks, including, but not limited to:
•our management team's capacity could be challenged by the demands of evaluating, negotiating, integrating significant acquisitions, and strategic transactions in concert with the Company's ongoing business demands;
•the challenge and cost of integrating acquired operations, information management, other technology systems, and business cultures with those of our operations while carrying on our ongoing business;
•difficulty associated with coordinating geographically separate organizations;
•an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded operations and unknown liabilities; and
•the challenge of attracting and retaining personnel associated with acquired operations.
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 natural gas operations and environmental matters may adversely affect our business and results of operations.
Oil and natural gas operations are subject to extensive federal, state, and local government regulations, which may 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 oil and natural gas from wells below actual production capacity in order to conserve supplies of oil and natural gas. There are federal, state, and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling, storage, transportation, and disposal of 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 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.
The risks arising out of concerns regarding the threat of climate change, including regulatory, political, litigation, and financial risks may adversely affect our business and results of operations.
The Company’s operations are subject to a number of risks arising out of concerns regarding the threat of climate change, including regulatory, political, litigation, and financial risks, that could result in increased operating costs and costs of compliance, limit the areas in which oil and natural gas production may occur and reduce the demand for oil and natural gas.
The threat of climate change continues to attract considerable attention. Numerous initiatives have been proposed and more are expected to come that focus on monitoring and limiting existing sources of greenhouse gas emissions as well as to restrict or eliminate emissions from new sources. As a result, the Company is subject to numerous risks associated with the production and processing of fossil fuels and emission of greenhouse gas.
Governmental, scientific, and public concern over the threat of climate change arising from greenhouse emissions has resulted in increasing political risks in the United States. Proposals to ban hydraulic fracturing of oil and natural gas wells and ban new leases for production of minerals on federal properties, including onshore lands and offshore waters have already been made. Other actions that could be pursued may include more restrictive requirements for drilling or construction permits, the reversal of the United States’ withdrawal from the Paris Agreement in November 2020, and reinstatement of the ban on oil exports. Litigation risks are also increasing as a number of suits against oil and natural gas exploration and production companies have
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been brought in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects.
There are also financial risks for the energy industry as it may become more difficult to access the capital markets as the threat of climate change may impact decisions made by potential investors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Limitation of investments in and financings for the energy industry could result in the restriction, delay or cancellation of drilling programs or development or production activities.
Our business could be negatively affected by security threats. A cyber-attack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation, and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, and financial activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third-party partners. Our technologies, systems, networks, seismic data, reserves information, or other proprietary information, and those of our operators, vendors, suppliers, customers, and other business partners may become the target of cyber-attacks or information security breaches. Cyber-attacks or information security breaches could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyber-attacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation, or potential liability. Also, computers control nearly all of the oil and natural gas distribution systems in the United States of America and abroad. Computers are necessary to transport our oil and natural gas production to market. A cyber-attack directed at oil and natural gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the United States of America government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.
Our insurance may not protect us against all of the operating risks to which our business is exposed.
The oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of oil, natural gas, or well fluids, fires, formations with abnormal pressures, hurricanes, 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 Ryan Stash, Senior Vice President, Chief Financial Officer, and Treasurer, to source, evaluate, and close deals, raise capital, and oversee our development activities and operations. Presently, the Company is not a beneficiary of any key man life insurance.
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 oil and natural gas resources requires third-party oilfield service vendors and various material providers, which we do not control. We also rely on third-party carriers for the transportation and distribution of our oil and natural gas production. As our production increases, so does our need for such services and materials. Generally, we do not have long-term agreements with our service and materials providers. Accordingly, there is a risk that any of our service providers could discontinue servicing our oil and natural gas fields for any reason or we may not be able to source the materials
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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 oil and natural gas that we produce without the assistance of third-parties.
The marketability of the oil and natural gas that we produce depends upon the proximity of our reserves to, and the capacity of, facilities and third-party services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities necessary to make the products marketable for end use. The unavailability or lack of capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in, delay, or discontinuance could adversely affect our financial condition.
We face strong competition from larger oil and gas companies.
Our competitors include major integrated oil and natural gas companies, numerous larger independent oil and natural gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources. We may not be able to successfully conduct our operations, evaluate and select suitable properties, or consummate transactions in this highly competitive environment. Specifically, these larger competitors may be able to pay more for development projects and productive oil and natural gas properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources on hiring contract service providers, obtaining oilfield equipment, and acquiring the existing and changing technologies that we believe are, and will be, increasingly important to attaining success in our industry.
We have been, and in the future may become, involved in legal proceedings related to our properties or operations and, as a result, may incur substantial costs in connection with those proceedings.
From time to time we may be a defendant or plaintiff in various lawsuits. The nature of our 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, natural gas, and mineral properties is important to our business. Although title reviews will generally be conducted prior to the purchase of most oil, natural gas, and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim. This could result in a reduction or elimination of the revenue received by us from such properties.
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”) and subsequent variants, 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 have a material impact globally. These and other actions could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide telecommuting, and lead to disruptions in our permitting activities and critical business relationships. Additionally, the COVID-19 outbreak and governmental restrictions have significantly impacted economic activity and markets and have dramatically reduced current and anticipated demand for oil and natural gas, adversely impacting the prices we receive for our production. The severity and duration of the current COVID-19 outbreak and the subsequent variants in addition to the potential for future outbreaks are uncertain and difficult to predict.
The extent to which COVID-19 impacts our business will depend on future developments, which are highly uncertain and cannot be predicted, including new information which may emerge concerning the severity of the coronavirus and the actions to contain the coronavirus or treat its impact, among others. We are unable to predict the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments, including the length of time that the
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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 natural gas prices, geopolitical issues, the availability and cost of credit, the United States of America mortgage market, uncertainties with regard to European sovereign debt, the slowdown in economic growth in large emerging and developing markets, such as China, regional or worldwide increases in tariffs or other trade restrictions, and other issues have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic conditions have had a significant adverse impact on domestic and international financial markets and commodity prices. If uncertain or poor economic, business, or industry conditions in the United States of America or abroad remain prolonged, demand for petroleum products could diminish or stagnate, and production costs could increase. These situations could impact the price at which we can sell our oil, natural gas, and NGLs, affect our vendors', suppliers', and customers' ability to continue operations, and ultimately adversely impact our results of operations, liquidity, and financial condition.
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 ended June 30, 2021, our stock price as traded on the NYSE American ranged from $2.75 to $5.15. The variance in our stock price makes it difficult to forecast with certainty the stock price at which an investor may be able to buy or sell shares of our common stock. The market price for our common stock could be subject to fluctuations as a result of factors that are out of our control, such as:
•actual or anticipated variations in our results of operations;
•naked short selling of our common stock and stock price manipulation;
•changes or fluctuations in the commodity prices of oil and natural gas;
•general conditions and trends in the oil and natural gas industry;
•redemption demands on institutional funds that hold our stock; and
•general economic, political and market conditions.
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, 2021 our executive officers and directors, in the aggregate, beneficially owned approximately 2.7 million shares, or approximately 8.0% of our beneficial common stock base. Blackrock Fund Advisors, et al controlled approximately 2.0 million shares or approximately 6.1% of our outstanding common stock, Arrowmark Colorado Holdings, LLC controlled approximately 2.0 million shares or approximately 6.1% of our outstanding common stock and Renaissance Technologies, LLC controlled approximately 2.2 million shares or approximately 6.5% of our outstanding common stock. As a result, any of these holders could potentially exercise significant influence over matters submitted to our stockholders for approval (including the election and removal of directors and any merger, consolidation or sale of all or substantially all of our assets). This concentration of ownership may have the effect of delaying, deferring or preventing a change in control of our company, impede a merger, consolidation, takeover, or other business combination involving our company or discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of our company, which in turn could have an adverse effect on the market price of our common stock.
The market for our common stock is limited and may not provide adequate liquidity.
Our common stock trades on the NYSE American stock exchange. Trading volume in our common stock is relatively low compared to larger companies. During the fiscal year ended June 30, 2021, the daily trading volume in our common stock ranged from a low of 38,100 shares to a high of 4,596,300 shares, with average daily trading volume of 169,054 shares compared to average daily volume of 155,691 in fiscal 2020. Our holders may find it more difficult to sell their shares, should they desire to do so, based on the trading volume and price of our stock at that time relative to the quantity of shares to be sold.
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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, three independent analysts cover our company. The limited number of published reports by independent securities analysts could limit the interest in our common stock and negatively affect our stock price. We do not have any control over the research and reports these analysts publish or whether they will be published at all. If any analyst who does cover us downgrades our stock, our stock price could decline. If any analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price to decline.
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:
•exercising voting, redemption, and conversion rights to the detriment of the holders of common stock;
•receiving preferences over the holders of common stock regarding our surplus funds in the event of our dissolution, liquidation, or the payment of dividends to preferred stockholders;
•delaying, deferring, or preventing a change in control of our company; and
•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. The quarterly dividend was $0.05 for the fourth quarter of fiscal 2021 as a result of an improving financial and industry outlook. There is no guarantee that we will be able or choose to continue to pay cash dividends on our common stock.
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.
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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 stock exchange under the ticker symbol “EPM”. The following table shows, for each quarter of the fiscal years ended June 30, 2021 and 2020, the high and low sales prices for EPM as reported by the NYSE American stock exchange.
NYSE American: EPM
Shares Outstanding and Holders
As of June 30, 2021, there were 33,514,952 shares of common stock issued and outstanding. As of September 1, 2021, there were approximately 216 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, 2021, we have paid 31 consecutive quarterly dividends on our common stock. In September 2021, the Company declared a $0.075 per share dividend payable on September 30, 2021. Any future determination with regard to the payment of dividends will be at the discretion of the Board of Directors and will be dependent upon our future earnings, financial condition, results of operations, applicable dividend restrictions, capital requirements, and other factors deemed relevant by the Board of Directors.
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, 2016 to June 30, 2021 with the cumulative total return of the S&P 500 Index and the S&P Oil & Gas Exploration and Production Index of publicly traded companies over the same period. The graph assumes that $100 was invested on June 30, 2016 in our common stock at the closing market price at the beginning of this period and in each of
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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 323,080 (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. On December 9, 2020, an amendment to the 2016 Plan was approved by our stockholders that increased the number of shares available for issuance by 2,500,000 shares. As of June 30, 2021, the Company has granted 1,444,230 awards under the 2016 Plan and 2,206,294 shares of common stock remain available for future grants.
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Issuer Purchases of Equity Securities
During the fourth quarter ended June 30, 2021, the Company did not purchase any common stock in the open market under the previously announced share repurchase program and no shares of common stock were surrendered by its employees to pay their share of payroll taxes arising from vesting of restricted stock.
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
Impairment of proved property 24,792,079 — — — —
Impairment of Well Lift Inc. - related assets 146,051 — — — —
Restructuring charges — — — — 4,488
Dividends on preferred stock — — — — 250,990
Deemed dividend on preferred shares called for redemption — — — — 1,002,440
Earnings per common share:
Balance Sheet Data
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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview
Liquidity and Capital Resources
Results of Operations
Critical Accounting Policies
Executive Overview
General
Evolution Petroleum Corporation is an oil and natural gas company focused on delivering a sustainable dividend yield to its stockholders through the ownership, management, and development of oil and natural gas properties. In support of that objective, the Company's long-term goal is to build a diversified portfolio of oil and natural gas assets primarily through acquisitions, while seeking opportunities to maintain and increase production through selective development, production enhancements, and other exploitation efforts on its properties.
Our 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, our interests in the Barnett Shale located in North Texas, a natural gas producing shale reservoir, and overriding royalty interests in two onshore central 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, a subsidiary of Denbury, Inc.
On November 1, 2019, the Company acquired mineral interests in the Hamilton Dome field consisting of a 23.5% working interest, with an associated 19.7% revenue interest (inclusive of a small overriding royalty interest). The field is operated by Merit, a private oil and natural gas company, who owns the vast majority of the remaining working interest in Hamilton Dome field. Our acquired interest in this field aligns with the Company's strategy of adding long-lived, low decline reserves expected to be supportive of our dividend over the long-term.
On May 7, 2021, the Company acquired non-operated working interests in the Barnett Shale consisting of approximately 21,000 net acres held by production across nine North Texas counties in the Barnett Shale. The acreage has an average working interest of 17.3% and associated average revenue interest of 14.2%. At the time of the Barnett Shale acquisition, approximately 90% of the wells acquired were operated by Blackbeard, while the remaining 10% were operated by the seven other operators. After the close of the Barnett Shale Acquisition, Blackbeard announced the sale of its interest to Diversified Energy, which closed in July of 2021. At present, Blackbeard is still the operator of the assets under a transition services agreement with Diversified Energy. However, after the transition, Diversified Energy will take over operations of the assets.
Highlights for our Fiscal Year 2021 and Operations Update
•Closed the Barnett Shale Acquisition on May 7, 2021 which included total proved reserves of 13.1 MMBOE as of June 30, 2021 as estimated by DeGolyer & MacNaughton (“D&M”), an independent reservoir engineering firm.
•Returned to shareholders $4.3 million in cash dividends in fiscal 2021. The Company has paid out to shareholders more than $74.5 million in cash dividends since inception of the dividend program in December 2013.
•Generated $3.7 million in operating income before impairments.
•Funded our fiscal year operations, capital expenditures, and dividends out of operating cash flow.
•Proved oil equivalent reserves at June 30, 2021 were 23.4 MMBOE, a 129% increase from the previous year primarily due to the acquisition of interests in the Barnett Shale in May 2021.
•We completed the NYMEX WTI oil swaps entered into during fiscal year 2020, and we have not entered into any new oil and gas derivatives as of June 30, 2021.
•Denbury, whose subsidiary operates the Delhi Field, emerged from bankruptcy on September 18, 2020 and returned to conformance projects with a refreshed capital budget after a period of no conformance spending.
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Oil & Natural Gas Liquids Reserves (based on SEC NYMEX WTI oil price of $49.72 per barrel)
Proved oil equivalent reserves at June 30, 2021 were 23.4 MMBOE, a 129% increase from the previous year primarily due to the acquisition of interests in the Barnett Shale in May 2021. The Standardized Measure for proved reserves increased 40% to $87.6 million, primarily due to the acquisition of interests in the Barnett Shale and an increase in the SEC mandated trailing twelve month average first day of the month net oil price from $46.37 per barrel of oil and $9.00 per barrel of natural gas liquids (we did not have natural gas reserves as of June 30, 2020) at June 30, 2020 to $49.72 per barrel of oil, $19.81 per barrel of natural gas liquids and $2.46 per MMBtu of natural gas at June 30, 2021. Our proved reserves consist of 36% oil, 29% natural gas liquids and 35% natural gas, 92% are classified as proved developed producing and 8% are proved undeveloped.
The following table is a summary of our proved reserves as of June 30, 2021 and 2020:
Proved Reserves
Standardized Measure ($MM) $ 87.6 $ 62.5 40 %
Additional property and project information is included under Item 1 and in Note 6 and Note 20 to our consolidated financial statements in Item 8, and in Exhibit 99.1 of this Form 10-K.
Delhi Field
At June 30, 2021, we had total net proved reserves of 8.5 MMBOE compared to the prior year's 8.7 MMBOE, or a 3% decline in proved oil reserves. Fiscal year 2021 production of 0.5 MMBOE was partially offset by 0.3 MMBOE positive revisions primarily due to price increases.
Gross production at Delhi in the fourth quarter of fiscal 2021 was 5.1 MBOEPD, a 2% increase compared to 5.0 MBOEPD in the third fiscal quarter. Oil production was 4.1 MBOPD, which was flat compared to the third fiscal quarter’s 4.1 MBOPD. NGL production in the fourth quarter was 1.0 MBOEPD, an increase of 9% compared to third fiscal quarter's 0.9 MBOEPD. Annual oil production was significantly impacted by cessation of CO2 purchases when the CO2 purchase pipeline, upstream of the Delhi field, was shut-in for repairs in late February until October 2020 combined with constrained purchase volumes after the pipeline was returned to service. The loss of CO2 purchases, coupled with the decline in oil prices and bankruptcy filing, led to the operator electing to freeze non-essential capital projects through the end of calendar year 2020. During the fourth quarter of fiscal 2021, the operator resumed limited capital conformance projects within the field. We continue to monitor and evaluate the effectiveness of these projects.
The average oil price realized by Evolution at the Delhi field during the fourth quarter of fiscal 2021 was $64.68 compared to $56.02 during the previous quarter, an increase of 15%. The average NGL price realized by Evolution at the Delhi field during the fourth quarter of fiscal 2021 was $28.69 per barrel compared to $26.00 during the previous quarter, an increase of 10%. The increase was attributable to the broad recovery of commodity prices in fiscal fourth quarter. The uncertain demand outlook due to the ongoing COVID-19 pandemic has resulted in continued volatility in benchmark oil prices, with prices ranging from a low of a price of $58.73 per Bbl to a high of $74.21 per Bbl during our fiscal fourth quarter.
We historically have benefited from the premium that the Delhi field oil receives selling under Louisiana Light Sweet (“LLS”) pricing, as compared to the more widely known West Texas Intermediate (“WTI”) price. The LLS index correlates more closely to the Brent Crude oil price index (“Brent”) and, as such typically trades at a premium to the WTI index. Among other factors, the impacts of the COVID-19 pandemic caused global demand reduction and resulted in the Brent to WTI price spread to tighten, thus also resulting in a lower LLS to WTI price spread. In the fiscal fourth quarter 2021, the Delhi field realized a discount to WTI of $1.51, after deducting marketing and transportation costs. Oil produced from the Delhi field is shipped to market directly by pipeline, the most cost-effective means of transportation from the field. In addition, our received NGL price for royalty production varies because our royalty interests are burdened by a capital recovery charge, which is mostly offset by our working interest share that is reflected as a reduction in lease operating expense.
Our overall lifting costs per BOE for the year were $18.80 per BOE, which increased 14% from $16.50 per BOE in the prior year. Gross CO2 purchase volume rates for fiscal 2021 averaged 49.1 MMcf per day, compared to 51.9 MMcf per day in the prior year, a 5% decrease primarily due to the Delhi CO2 purchase pipeline shut-in for repairs. This decrease together with a 8% lower price per MCF resulted in a 13% decrease in CO2 cost compared to the prior year. Our cost of purchased CO2, the largest
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single component of operating costs at Delhi, is directly tied to the price of oil sold from the field. Other lease operating expenses for fiscal 2021 decreased 10% compared to the prior year, primarily due to lower fuel gas, parts and workover expenses. The decrease in CO2 cost and other lease operating expenses, paired with a decrease in production of 22% for the current year, resulted in the increase in lifting costs per BOE.
For fiscal 2021, our gross NGL production was 1.0 MBOEPD, which sold at an average price of $21.36 per barrel, compared to prior year gross production of 1.1 MBOEPD for which we realized $9.59 per barrel. In addition, the previously mentioned the capital recovery charge affects the NGL price in that if oil prices are below a realized NGL price of $60, the Company's royalty interests in Delhi do not benefit from NGL sales, partially offset by a reduction in the plant operating costs representing our working interest share of the cost recovery fee. This contributed to a lower price per barrel in the prior fiscal year, and the higher price per barrel in fiscal year 2021. Production from the NGL plant is transported by truck to a processing plant in East Texas, and therefore bears a material transportation charge. Our current mix of products is very rich, containing higher value NGLs, such as pentanes and butane. Historically, NGL demand has had a seasonal pattern with prices tending to be higher in the cooler months of the year. Accordingly, the relationship between NGL prices and WTI has fluctuated over time and we expect such volatility to continue in the future.
The NGL plant includes a gas turbine driven generator 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, 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 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 $6.44 per BOE of PUD reserves for Phase V. Looking forward, the timing of plans for continued development of the eastern part of the Delhi field are dependent on the operator’s schedule for capital allocation within their portfolio but is projected to occur in the next few years. Development of unquantified volumes is dependent upon the timing of excess capacity within the processing plant and oil price. Over the past decade, we, along with the operator, have invested significant resources and capital demonstrating our commitment to the development of the Delhi field and believe that we will collectively continue to do so.
Hamilton Dome
At June 30, 2021, we had total net proved reserves of 1.9 MMBOE, entirely comprised of oil, compared to prior year net proved reserves of 1.5 MMBOE. The positive revision of 0.4 MMBOE, or 26%, in proved oil reserves is primarily related to improved oil pricing, decreased expenses and restoration of shut-in production from the global pandemic.
Gross oil production at Hamilton Dome in the fourth quarter of fiscal 2021 was 2,035 BOPD, a 3% increase compared to 1,985 BOPD in the third fiscal quarter due to the operator restoring previously shut-in production and maintenance within the field. There were limited capital expenditures in the field during fiscal 2021 due primarily to the decrease in oil prices. Most projects in the field focused on maintenance or restoring shut-in production.
The average oil price realized by Evolution at Hamilton Dome during the fourth quarter was $55.93 compared to $46.61 during the previous quarter, an increase of 20% attributable to the recovery in commodity prices in the fiscal fourth quarter. Production from this field is transported by pipeline to customers and is priced on the Western Canadian Select index, which generally trades at a discount to WTI. In the fourth quarter, our realized price reflected a $7.58 per barrel discount from the WTI price. For fiscal 2021, realized oil price averaged $42.28 compared to $29.19 for the prior year. For this fiscal year, our lifting costs at Hamilton Dome averaged $28.57 per barrel.
Barnett Shale
At June 30, 2021, we had total net proved reserves of 13.1 MMBOE, comprised of 62% natural gas, 37% natural gas liquids, and 1% oil as estimated by our independent petroleum engineering firm D&M. The Barnett Shale asset was acquired on May 7, 2021.
Blackbeard, the primary Barnett Shale operator has yet to formalize a budget, as they are currently under a transition services agreement with Diversified Energy following the sale of their interests to Diversified Energy in July 2021. Diversified Energy has expressed interest in identifying and performing remedial workovers to maintain and restore production.
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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 continue to recommend social distancing, imposed quarantine and isolation measures, as well as periodic business closures on large portions of the population as the Delta variant of COVID-19 has emerged in the current fiscal year. These measures, while intended to protect human life, are expected to have continued impacts on domestic and foreign economies, potentially resulting in the volatility of commodity prices. The effectiveness of economic stabilization efforts, including government payments to affected citizens and industries, is uncertain.
Currently, all of the Company’s property interests are not operated by the Company and involve other third-party working interest owners. As a result, the Company has limited ability to influence or control the operation or future development of such properties. In light of the current price and economic environment, the Company continues to be proactive with its third-party operators to review spending and alter plans as appropriate.
The Company is focused on maintaining its operations and system of controls remotely and has implemented its business continuity plans in order to allow its employees to securely work from home. The Company was able to transition the operation of its business with minimal disruption and to maintain its system of internal controls and procedures.
Liquidity and Capital Resources
At June 30, 2021, we had $5.3 million in cash and cash equivalents, primarily impacted by the $18.3 million purchase (net of preliminary purchase price adjustments and $2.8 million in non-cash asset retirement obligations) of certain mineral interests in the Barnett Shale in May 2021, compared to $19.7 million of cash and cash equivalents at June 30, 2020.
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 $30 million borrowing base, with $4 million drawn as of June 30, 2021. The borrowing base does not yet include any portion of the Barnett Shale properties. There are $4 million in borrowings outstanding under the Facility, which matures on April 9, 2024. The Facility is secured by substantially all of the reserves associated with the Company's assets.
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 current ratio of not less than 1.0 to 1.0, and (iii) a consolidated tangible net worth of not less than $40 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, 2021, the Company was in compliance with all covenants contained in the Facility.
On August 5, 2021, and effective as of June 30, 2021, we entered into the seventh amendment of our Senior Secured Credit Facility which added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the Consolidated Tangible Net Worth was reduced to $40 million from $50 million.
The Company has historically funded operations through cash from operations and working capital. The primary source of cash is the sale of produced oil, natural gas, 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 and Barnett Shale assets 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 access to the undrawn portion of the 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.
During the fiscal year ended June 30, 2021, the Company funded operations, capital expenditures, and cash dividends with cash generated from operations resulting in a decrease of $14.4 million in cash. Uses of cash included the acquisition of the Barnett Shale assets ($18.3 million) and cash dividends on common shares ($4.3 million). As of June 30, 2021, working capital was $11.5 million, a decrease of $9.5 million from working capital of $21.0 million at June 30, 2020.
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The Board of Directors instituted a cash dividend on common stock in December 2013. The Company has since paid 31 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of the Company’s financial strategy, and it is the Company's long-term goal to increase dividends over time, as appropriate. During the industry downturn, effective in the quarter ended June 30, 2020, the Board of Directors adjusted the quarterly dividend rate from $0.10 per share to $0.025 per share. The reduction in the dividend rate at that time allowed the Company to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield of approximately 3% at stock price levels. On February 2, 2021, considering an improving industry outlook, the Board of Directors increased the dividend rate from $0.025 per share to $0.03 per share effective in the quarter ended March 31, 2021. On May 7, the Board of Directors further increased the dividend rate to $0.05 per share effective in the quarter ended June 30, 2021 due to improved industry conditions and the Barnett Shale acquisition. As in the past, the Company intends to consider higher dividend levels as warranted by industry conditions and any future accretive acquisitions.
Capital Expenditures
For the year ended June 30, 2021, we incurred $21.7 million on capital projects consisting of $21.1 million for the acquisition of Barnett Shale assets (gross of preliminary purchase price adjustments and $2.8 million in non-cash asset retirement obligations) and $0.6 million at the Delhi field (primarily for plugging costs and capital conformance work).
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 at Delhi and will resume projects at Hamilton Dome. Such amounts are not known or approved but we expect such expenditures to be in the range of $0.9 million to $1.5 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 2023. Phase V development expenditures are expected to total $8.6 million with $3.7 million to be incurred in fiscal 2024 and the remainder over the following two years.
Our proved undeveloped reserves are associated only with the Delhi field. At June 30, 2021, our proved undeveloped reserves 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 Delhi field. Such development requires participation by both the operator and the Company. Although we expect drilling to commence in fiscal 2023, the timing of Phase V is dependent on the field operator's available funds, 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 June 30, 2021, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling; however, we could experience an impairment if current price levels worsen. Lower oil prices would reduce the excess, or cushion, of our valuation ceiling over our capitalized costs and may adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future. Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test at June 30, 2021 were $49.72 per barrel of oil, $2.46 per MMBtu of natural gas and $19.81 per barrel of natural gas liquids. At December 31, 2020 and September 30, 2020, the Company recorded ceiling test impairment charges of $15.2 million and $9.6 million, respectively. The ceiling test impairments were driven by decreases in the first-day-of-the-month average for oil used in the ceiling test calculation as outlined below.As of June 30, 2021, a 10% decrease in commodity prices used to determine our proved reserves would not have resulted in an impairment of our oil and natural gas properties.
Twelve-Month Period Ended:
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Overview of Cash Flow Activities
The table below compares a summary of our consolidated statements of cash flows for year ended June 30, 2021 and 2020.
Increases (Decreases) in Cash: 2021 2020 Difference
(In Millions)
Net cash provided by operating activities $ 4.7 $ 12.4 $ (7.7)
Net cash used in investing activities (18.8) (11.1) (7.7)
Net cash used in financing activities (0.3) (13.2) 12.9
Change in cash, cash equivalents and restricted cash $ (14.4) $ (11.9) $ (2.5)
Cash provided by operating activities in the current year decreased $7.7 million compared to fiscal 2020. The difference is primarily the result of a decrease in revenues compared to the prior year and the payments related to realized hedge settlement losses of $2.5 million.
Cash used in investing activities increased $7.7 million primarily due to the acquisition of the Barnett Shale assets in May 2021 for $18.3 million (net of preliminary purchase price adjustments and $2.8 million in non-cash asset retirement obligations) compared to the acquisition of Hamilton Dome field in November 2019 for $9.3 million. The increase is partially offset by a reduction in capital expenditures of $1.3 million in fiscal 2021 due to the decrease in conformance workover activities from lower oil prices.
Cash used in financing activities decreased year over year primarily related to the net borrowing of $4 million on the Senior Secured Credit Facility during fiscal 2021, and the reduction in cash paid for cash dividends as the Company paid $4.3 million in fiscal year 2021 and $10.7 million in fiscal year 2020. In addition, the Company paid $2.5 million more in fiscal year 2020 compared to fiscal year 2021 related to the Company's common share repurchase program.
Contractual Obligations and Other Commitments
The table below provides estimates of the timing of future payments that, as of June 30, 2021, 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
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Results of Operations
Years Ended June 30, 2021 and 2020
Revenues
The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the years ended June 30, 2021 and 2020. Fiscal 2020 includes eight months of Hamilton Dome production. Fiscal 2021 includes approximately two months of Barnett Shale production.
Years Ended June 30,
Oil and gas production
Revenues
Volumes
Natural gas (BOEPD, net) 440 — 440 n.m.
Natural gas average realized price per Mcf 2.73 1.90 0.83 43.7 %
(a) Equivalent price per BOE has decreased in the current fiscal year despite a 6.3% increase in oil price per Bbl and a 122.7% increase in NGL price per Bbl. With the Barnett Shale Acquisition, the Company added significant natural gas sales compared to the prior year. Natural gas sales are realized at a lower price per BOE than oil and NGLs, and the Company’s total weighted average price per BOE declined by approximately 7% from the prior year.
n. m. Not meaningful.
Fiscal year 2021 revenues increased 10% compared to the prior fiscal year primarily due to increased realized commodity prices and the addition of the Barnett Shale Acquisition, which primarily drove the increase in natural gas and NGL sales revenues and production volumes compared to the prior fiscal year. This increase was partially offset by an 8% decrease in oil revenues primarily driven by an expected temporary increase in production decline and weaker price differentials in the Delhi field. The shut-in of the CO2 supply pipeline from late February 2020 through the end of October 2020, as discussed in “Lease Operating Costs” below, as well as a suspension of field conformance capital expenditures drove the expected temporary increase in production declines in the Delhi field. Purchased CO2 is necessary to maintain reservoir pressure and therefore achieve normal field performance. The shut-in of purchased CO2 volumes resulted in a decline in reservoir pressure and a temporary exacerbated production decline. The resumption of CO2 purchases during the current fiscal year is expected to gradually restore reservoir pressure and lead to a gradual increase in oil production rates. Also contributing to the decrease of production in the current fiscal year was the loss of production associated with the severe winter storm in February 2021. The Company’s average realized oil price was higher primarily due to the recovery of WTI pricing in 2021, as the demand for oil has begun to recover primarily as a result of the roll-out of the COVID -19 vaccines and concerns surrounding the perceived surplus of oil supplies has begun to retract.
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(Gain) Loss on Derivative Contracts
Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil prices. This amount represents the (i) (gain) loss related to fair value adjustments on our open, or unrealized, derivative contracts and (ii) (gains) losses on settlements of derivative contracts for positions that have settled or been realized. No positions remain outstanding as of June 30, 2021.
Years Ended June 30,
Oil Derivative Contracts
Oil price per Bbl (including impact of realized derivatives) $ 43.05 $ 45.59
Lease Operating Costs
Lease operating costs (also referred to as production expenses) are presented in two components: (i) CO2 purchase costs for the Delhi field and (ii) other lease operating costs for both the Delhi, Hamilton Dome, and Barnett Shale fields.
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,
CO2 volumes (MMcf per day, gross) 49.1 51.9 (2.8) (5.4) %
The $0.4 million decrease in CO2 costs was due to a 5.4% decrease in rate of purchased volumes together with a 7.8% 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 suspended until October 2020 for pipeline repairs. 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 Inc, and the Company does not have any ownership in the portion of the pipeline that was repaired.
Compared to fiscal 2020, “Other lease operating costs” increased 35.2% primarily due to the additional four months of production costs at the Hamilton Dome field in fiscal 2021 compared to eight months of production costs in fiscal 2020 following acquisition in November 2019 and, to a lesser extent, the closing of the Barnett Shale Acquisition in May 2021. The Delhi field's “Other lease operating costs” decreased 10.5% impacted by cost control measures resulting from lower oil prices.
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Compared to fiscal 2020, Delhi field costs increased 14% to $18.80 per BOE of Delhi current year production primarily due to lower production volumes.
For fiscal 2021, Hamilton Dome field costs per BOE were $28.57, a decrease of 1.3% from fiscal year 2020 due to increased production and cost control measures implemented following the pandemic resulting from lower prices.
For fiscal 2021, Barnett Shale field costs per BOE were $12.61 compared to no field costs in the prior year as the Company completed the Barnett Shale Acquisition in the current fiscal year.
Depletion, Depreciation and Amortization (“DD&A”)
Total DD&A expense was 10.3% lower compared to the same one year-ago period due to an 12.3% decrease in the oil and natural gas DD&A amortization rate. The integration of the Barnett Shale assets together with the ceiling test impairments contributed to an overall lower composite DD&A per BOE rate. Additionally, accretion of asset retirement obligations increased 43.5% in the current fiscal year as a result of the asset retirement obligation additions from Barnett Shale Acquisition. Amortization of intangibles increased as a result of amortization of $37.3 thousand of our Well Lift, Inc. (“WLI”) assets during fiscal year 2021.
Years Ended June 30,
General and Administrative Expenses
Total general and administrative expenses for fiscal 2021 increased $1.5 million, or 28.4%, to $6.8 million from the same year-ago period. The increase is primarily due to higher legal and professional fees of $0.8 million related to consulting on various potential business transactions, an increase in accrued bonus expense of $0.5 million and an increase in salaries of $0.2 million due to additional employees.
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Other Income and Expenses
Interest income is lower in fiscal year 2021 compared to fiscal year 2020 primarily due to the decrease in cash as a result of the closing of the Barnett Shale Acquisition in May 2021 and lower realized oil prices.
Years Ended June 30,
Net Income
Net income available to common stockholders for the year ended June 30, 2021 decreased $22.4 million, to a loss of $16.4 million compared to the last fiscal year primarily driven by proved oil and gas property impairments of $9.6 million and $15.2 million recorded during the first and second fiscal quarters of 2021, respectively. Our income tax benefit increased primarily due to a pre-tax loss in the current period compared to pre-tax income in the prior year. During the fiscal year 2020, 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 compared to a $0.3 million EOR credit benefit in fiscal 2021.
Years Ended June 30,
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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 natural gas industry. We apply the full cost accounting method for our oil and natural gas properties as prescribed by SEC Regulation S-X Rule 4-10. Under this method of accounting, the costs of unsuccessful and successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration, and development activities but does not include any costs related to production, general corporate overhead, or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties. We exclude these costs until the property has been evaluated. Costs are transferred to the full cost pool as the properties are evaluated. As of June 30, 2021, we had no unevaluated property costs. Oil and natural gas properties include costs that are excluded from depletion and amortization, which represent investments in unproved and unevaluated properties and include non-producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs.
Estimates of Proved Reserves. The estimated quantities of proved oil and natural gas reserves have a significant impact on the underlying financial statements. The estimated quantities of proved reserves are used to calculate depletion expense and the estimated future net cash flows associated with those proved reserves is the basis for determining impairment under the quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex and requires significant decisions in the evaluation of all available geologic, geophysical, engineering, and economic data. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information; this includes reservoir performance, additional development activity, new geologic and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates prepared by our third-party independent engineers represent the most accurate assessments possible, the subjective decisions and variances in available data for the properties make these estimates generally less precise than other estimates included in our financial statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect our estimated future net cash flows of our proved reserves. These changes could affect our quarterly ceiling test calculation and could significantly affect our depletion rate. A 10% decrease in commodity prices used to determine our proved reserves as of June 30, 2021 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, 2021 of 5%, 10% and 15% would affect depreciation, depletion, and amortization expense by approximately $64,500, $136,000, and $216,000, respectively.
On December 31, 2008, the SEC issued its final rule on the modernization of reporting oil and natural gas reserves. The rule allows consideration of new technologies in evaluating reserves, generally limits the designation of proved reserves to those projects forecast to be drilled five years from the initial recognition date of such reserves, allows companies to disclose their probable and possible reserves to investors, requires reporting of oil and natural gas reserves using an average price based on the previous 12-month unweighted arithmetic average first-day-of-the-month price rather than year-end prices, revises the disclosure requirements for oil and natural gas operations, and revises accounting for the limitation on capitalized costs for full cost companies.
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. 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.
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As of June 30, 2021, we have recorded a valuation allowance for the portion of our net operating loss that is limited by Internal Revenue Code Section 382.
Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making the assessment of the ultimate realization of deferred tax assets. The Company establishes a valuation allowance against net operating losses and other deferred tax assets to the extent it believes the future benefit from these assets will not be realized in the statutory carryforward periods, based upon the level of historical taxable income and projections for future taxable income over the periods for which the deferred tax assets are deductible. At the time of this report, we have recorded a valuation allowance for our expected inability to realize the future benefits of certain federal and state deferred tax assets as further discussed in Note 13 - Income Taxes. If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax provision would change in the period it is determined that recovery is probable.
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 for discussion of the recent accounting pronouncements issued by the Financial Accounting Standards Board.
Off-Balance Sheet Arrangements
The Company had no off-balance sheet arrangements as of June 30, 2021.
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. Additionally, any borrowings under the Senior Secured Credit Facility will bear interest, at our option, at either LIBOR plus 2.75%, subject to a minimum LIBOR of 0.25%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%. LIBOR rates are sensitive to the period of contract and market volatility, as well as changes in forward interest rate yields. 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 per barrel. The fixed price swap contracts significantly reduced 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. For the derivative contracts settled during fiscal 2021, we did not post collateral as it was 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 19 to our consolidated financial statements for more details.
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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
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
Evolution Petroleum Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Evolution Petroleum Corporation and Subsidiaries (the “Company”) as of June 30, 2021 and 2020, 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, 2021 and 2020, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Oil and Natural Gas Reserves on Depreciation, Depletion and Amortization (“DD&A”) and Full Cost Ceiling Test Impairment Calculation (“Ceiling Test”)
As described in Note 2, the Company follows the full cost method of accounting, pursuant to which oil and natural gas properties are amortized using the unit-of-production method over total proved reserves. The Company’s proved oil and natural gas properties are evaluated for impairment by the Ceiling Test, utilizing the Company’s proved oil and natural gas reserves in accordance with accounting principles generally accepted in the United States of America and SEC guidelines. For the year ended June 30, 2021, the Company recorded DD&A related to its proved oil and natural gas properties of approximately $4.9 million and a ceiling test impairment of approximately $24.8 million.
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The Company engages an independent reservoir engineering firm, to serve as a management specialist, to assist with the estimation of proved oil and natural gas reserves. To estimate the volume of proved oil and natural gas reserves and associated future net cash flows, management and their specialist make significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties (“PUDs”). The estimation of proved oil and natural gas reserves is impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required. Changes in significant assumptions or engineering data could have a significant impact on the amount of DD&A and impairment recorded for the Company’s proved oil and natural gas properties.
We identified the impact of proved oil and natural gas reserves on DD&A and the Ceiling Test as a critical audit matter due to use of significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the significant assumptions used in developing those estimates of proved oil and natural gas reserves.
The primary procedures we performed to address this critical audit matter included:
•Evaluated significant assumptions used by management and its specialist in developing the estimates of proved oil and natural gas reserves, including pricing differentials, future operations costs, future production rates and capital expenditures. The procedures performed included:
◦tests of the data inputs used by specialist for completeness and accuracy,
◦an evaluation of the specialist’s findings,
◦testing specialist’s findings for mathematical accuracy and
◦analytical procedures on pricing, reserve quantities and cost estimates developed by management and its specialist. Those procedures entailed comparisons of:
(i) prices to historical benchmark prices, adjusted for pricing differentials,
(ii) production forecasts to recent historical actual production,
(iii) projections of lease operating costs to fiscal year end costs, and
(iv) projected production taxes to recent historical taxes incurred and to statutory tax rates.
•Evaluated the experience, qualifications and objectivity of management’s specialist, an independent reservoir engineering firm.
•Evaluated the accuracy of revenue and working interest percentages used in the reserve report by comparing a sample of such interests to the land records.
•Evaluated the Company’s evidence supporting the amount of PUDs reflected in the reserve report by (i) considering the field operator’s intent to develop PUDs and (ii) testing the Company’s financial capability to participate in development of those reserves by comparing estimated development costs to the sources of capital available to the Company.
•Performed retrospective review of historical estimates of proved oil and natural gas reserves to identify potential management bias in estimates.
/s/ Moss Adams LLP
Houston, Texas
September 14, 2021
We have served as the Company’s auditor since 2017.
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Evolution Petroleum Corporation and Subsidiaries
Consolidated Balance Sheets
Assets
Current assets
Receivables for federal and state income tax refunds 3,107,638 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
Senior secured credit facility 4,000,000 —
Commitments and contingencies
Stockholders' equity
See accompanying notes to consolidated financial statements.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
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Years Ended June 30,
Revenues
Operating costs
Impairment of proved property 24,792,079 —
Impairment of Well Lift Inc. - related assets 146,051 —
Other
Net income (loss) attributable to common shareholders $ (16,437,934) $ 5,937,072
Earnings (loss) per common share
Weighted average number of common shares outstanding
* General and administrative expenses for the years ended June 30, 2021 and 2020 included non-cash stock-based compensation expense of $1,257,684 and $1,285,663, respectively.
See accompanying notes to consolidated financial statements.
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Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Cash Flows
Years Ended June 30,
Cash flows from operating activities
Net income (loss) attributable to common shareholders $ (16,437,934) $ 5,937,072
Impairment of proved property 24,792,079 —
Impairment of Well Lift Inc. - related assets 146,051 —
Settlement of asset retirement obligations (101,311) (76,832)
Payments received (paid) for derivative settlements (2,791,176) 793,327
Changes in operating assets and liabilities:
Prepaid expenses and other current assets (545,573) (33,408)
Cash flows from investing activities
Development of oil and natural gas properties (472,401) (1,724,829)
Cash flows from financing activities
Borrowings under credit facility 7,000,000 —
Repayments of credit facility (3,000,000) —
Net cash provided by (used in) financing activities (349,429) (13,224,111)
* Neither annual period had any restricted cash balances.
See accompanying notes to consolidated financial statements.
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Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Changes in Stockholders' Equity
For the Years Ended June 30, 2021 and 2020
Common Stock
AdditionalPaid-inCapital RetainedEarnings TreasuryStock TotalStockholders'Equity
Shares Par Value
Forfeitures of restricted stock (49,118) (49) 49 — — —
Net income attributable to common shareholders — — — 5,937,072 — 5,937,072
See accompanying notes to consolidated financial statements.
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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 1 – Organization and Basis of Preparation
Nature of Operations.Evolution Petroleum Corporation is an oil and natural gas company focused on delivering a sustainable dividend yield to its stockholders through the ownership, management, and development of producing oil and natural gas properties. The Company's long-term goal is to build a diversified portfolio of oil and natural gas assets primarily through acquisitions while seeking opportunities to maintain and increase production through selective development, production 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 (“EOR”) 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, our interests in the Barnett Shale located in North Texas, a natural gas producing shale reservoir, and overriding royalty interests in two onshore Texas wells.
Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of Evolution Petroleum Corporation and its wholly-owned subsidiaries (the “Company”). All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year may include certain reclassifications to conform to the current presentation. Any such reclassifications have no impact on previously reported net income or stockholders' equity.
Risk and Uncertainties. The Company is continuously monitoring 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 field, Hamilton Dome fields, and its Barnett Shale assets in which it holds non-operated interests.
In response to the pandemic, the operator at Hamilton Dome temporarily shut-in some producing wells. In addition to the above, the pandemic slowed the repair schedule of the Delhi CO2 supply pipeline which, together with the foregoing, 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, the Company has 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 putting long term measures to prevent future disruptions, 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 or in the corporate office. The Company was able to transition the operation of its business with minimal disruption and has maintained 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 may 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, (f) commitments and contingencies and (g) oil, natural gas, and NGL revenues. 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.
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EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 2021 and 2020, we had no such balances.
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, 2021 and 2020, 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 depletion and amortization, which represent investments in unproved and unevaluated properties and include non-producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. These costs are excluded until the project is evaluated and proved reserves are established or impairment is determined. As of June 30, 2021 and 2020, we did not have any costs excluded from depletion and amortization.
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. See Note 6 - Property and Equipment for further information about impairment for the year ended June 30, 2021.
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.
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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 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, derivative instruments, and debt. Except for derivatives, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable are short-term instruments and approximate fair value due to their highly liquid nature. The carrying amount of debt approximates fair value as the variable rates on the Senior Secured Credit Facility are market interest rates. 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 natural 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 (as defined in Note 11 - Stock-Based Incentive Plan) 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 Natural Gas. Our revenues are comprised solely of revenues from customers from the sale of oil, natural gas, and natural gas liquids. 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. Oil, natural gas, and natural gas liquids 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 oil and 60 days for natural gas and natural gas liquids 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 (remitted to us by field operators) are accrued in “Receivables from oil and gas sales” in our consolidated balance sheets. As of June 30, 2021 and 2020 receivables from contracts with customers were $8.7 million and $1.9 million, respectively. This increase was related primarily to approximately two months of accrued revenue from the Barnett Shale Acquisition. For additional revenue recognition information see Note 3 - Revenue Recognition.
Estimates of Proved Reserves. The estimated quantities of proved oil and natural gas reserves have a significant impact on
the underlying financial statements. The estimated quantities of proved reserves are used to calculate depletion expense and the
estimated future net cash flows associated with those proved reserves is the basis for determining impairment under the
quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex and requires significant
decisions in the evaluation of all available geologic, geophysical, engineering, and economic data. Estimated reserves are often
subject to future revisions, which could be substantial, based on the availability of additional information; this includes
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reservoir performance, additional development activity, new geologic and geophysical data, additional drilling, technological
advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may
occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates prepared by our
third-party independent engineers represent the most accurate assessments possible, the subjective decisions and variances in
available data for the properties make these estimates generally less precise than other estimates included in our financial
statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect our
estimated future net cash flows of our proved reserves. These changes could affect our quarterly ceiling test calculation and
could significantly affect our depletion rate.
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, natural gas, 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 International Swap Dealers Association Master Agreement (“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.
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 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 contingent restricted common stock, under certain condition, 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 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.
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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:
•Not to apply the recognition requirements in the lease standard to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option that the Company is reasonably certain to exercise).
•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.
•Not to separate lease components from non-lease components in a contract and accounting for the combination as a lease (reflected by asset class).
Adoption of the new standard did not impact our consolidated statements of operations, cash flows or stockholders’ equity.
Income Taxes. In December 2019, the FASB issued Accounting Standards Update (ASU) 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (ASU 2019-12) as part of its initiative to reduce complexity in the accounting standards. The amendments in ASU 2019-12 remove certain exceptions related to the incremental approach for intraperiod tax allocation and the general methodology for calculating income taxes in an interim period and reducing diversity in practice for the recognition of enacted changes in tax law. ASU 2019-12 also clarifies and simplifies other aspects of accounting for income taxes. ASU 2019-12 is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2020; however, early adoption is permissible for periods for which financial statements have not yet been issued. Effective October 1, 2020, the Company prospectively adopted this new standard. Adoption of this standard had no impact on our consolidated financial statements nor would it have had if we had adopted the standard on July 1, 2020.
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.
Other accounting pronouncements that have recently been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company's financial position, results of operations, or cash flows.
Note 3 – Revenue Recognition
Our revenue is primarily generated from our interests in the Delhi field in Northeast Louisiana, the Barnett Shale assets of North Texas, and the Hamilton Dome field in Wyoming. Additionally, an overriding royalty interest retained in a past divestiture of Texas properties provided de minimis revenue:
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Revenues
We are a non-operator and presently do not take production in-kind and do not negotiate contracts with customers. We recognize oil, natural gas, and natural gas liquids 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 lease operating 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 oil, natural gas, and natural gas liquids production revenue. Transfer of control related to the Barnett Shale production does not occur until after the marketing, transportation and processing services have been performed, and as such, fees related to these services are recorded within the lease operating costs line item and do not reduce the oil, natural gas, and natural gas liquids production revenue. Transfer of control related to the Hamilton Dome and Delhi production occurs prior to the fees and other deductions, and as such, these fees are recorded as a reduction to the oil and natural gas liquids 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 completed 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 by field operators before distributing the Company’s share 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 from oil and gas sales” line item on the accompanying consolidated balance sheets until payment is received from field operators. The accounts receivable balances from contracts with customers as of June 30, 2021 and 2020, as presented on our respective consolidated balance sheets, were $8.7 million and $1.9 million, respectively. The increase between fiscal 2020 and fiscal 2021 is primarily due to the Barnett Shale Acquisition. 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 as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser as remitted to us by field operators. Revenue recognized during the fiscal year ended June 30, 2021 and 2020 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
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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, 2021, maturities of our operating lease liability are as follows:
Fiscal Year Operating Lease Liability
Total lease payments 87,941
Less imputed interest (2,962)
Total lease liability $ 84,979
Supplemental cash flow, balance sheet, and other disclosures information related to our operating leases are as follows:
Cash Flow:
ROU asset added in exchange for lease obligation at adoption — 161,125
Balance Sheet:
Operating lease ROU asset (included in other assets) 70,789 117,193
Operating lease liability - long-term 20,745 84,978
Other:
Weighted average remaining lease term in years 1.34 2.66
Weighted average discount rate 5.15 % 5.15 %
Note 5 – Prepaid Expenses and Other Current Assets
Prepaid federal and state income taxes 97,470 86,208
Carryback of EOR tax credit 416,441 —
Total prepaid expenses and other current assets $ 1,037,259 $ 491,686
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Note 6 – Property and Equipment, Net of Depreciation, Depletion, and Amortization
Oil and natural gas properties:
Unproved properties not subject to amortization — —
Other property and equipment: