Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
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.
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 $2.46 per MMBtu of natural gas at June 30, 2021. Our proved reserves consist of 36% oil, 29% natural gas liquids and 35% natural gas, 92% are classified as proved developed producing and 8% are proved undeveloped.
The following table is a summary of our proved reserves as of June 30, 2021 and 2020:
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Proved Reserves
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2021
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2020
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Change
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Reserves MMBOE
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23.4
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10.2
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129
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%
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% Developed
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92
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%
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82
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%
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12
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%
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Liquids %
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65
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%
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100
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%
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(35)
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%
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Standardized Measure ($MM)
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$
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87.6
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$
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62.5
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40
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%
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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
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.
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.
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.
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Twelve-Month Period Ended:
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6/30/2020
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9/30/2020
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12/31/2020
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3/31/2021
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6/30/2021
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Crude Oil
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47.37
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43.63
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39.54
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39.95
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49.72
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Natural Gas
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2.12
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2.02
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2.03
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2.18
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2.46
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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.
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June 30,
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Increases (Decreases) in Cash:
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2021
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2020
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Difference
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(In Millions)
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Net cash provided by operating activities
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$
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4.7
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$
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12.4
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$
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(7.7)
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Net cash used in investing activities
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(18.8)
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(11.1)
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(7.7)
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Net cash used in financing activities
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(0.3)
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(13.2)
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12.9
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Change in cash, cash equivalents and restricted cash
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$
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(14.4)
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$
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(11.9)
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$
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(2.5)
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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 $2.5 million more in fiscal year 2020 compared to fiscal year 2021 related to the Company's common share repurchase program.
Contractual Obligations and Other Commitments
The table below provides estimates of the timing of future payments that, as of June 30, 2021, we are obligated to make under our contractual obligations and commitments. We expect to fund these contractual obligations with cash on hand and cash generated from operations.
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Payments Due by Period
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Total
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Less than
1 Year
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1 - 3 Years
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3 - 5 Years
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More than 5 Years
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Contractual Obligations
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AFE purchase commitments in connection with joint interest agreements
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$
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329,827
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$
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329,827
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$
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—
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$
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—
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$
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—
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Operating lease
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$
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84,978
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59,103
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25,875
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—
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—
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Asset retirement obligations
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$
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5,583,272
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$
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44,520
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$
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168,377
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$
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158,378
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$
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5,211,997
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Total Obligations
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$
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5,998,077
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|
$
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433,450
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$
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194,252
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$
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158,378
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$
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5,211,997
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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.
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Years Ended June 30,
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2021
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2020
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Variance
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Variance %
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Oil and gas production
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Revenues
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Oil
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$
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26,411,132
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$
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28,578,879
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$
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(2,167,747)
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(7.6)
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%
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Natural gas liquids
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3,662,478
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1,018,349
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2,644,129
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259.6
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%
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Natural gas
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2,628,744
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|
|
2,068
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|
|
2,626,676
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n.m.
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Total revenues
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$
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32,702,354
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|
|
$
|
29,599,296
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|
|
$
|
3,103,058
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|
|
10.5
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%
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Volumes
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|
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Oil (Bbl)
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554,888
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638,464
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(83,576)
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(13.1)
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%
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Natural gas liquids (Bbl)
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171,451
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|
|
106,159
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|
65,292
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|
|
61.5
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%
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Natural gas (Mcf)
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963,496
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|
|
1,087
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|
|
962,409
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n.m.
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Equivalent volumes (BOE)
|
886,922
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|
|
744,804
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|
|
142,118
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19.1
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%
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Oil (BOPD, net)
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1,520
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|
|
1,744
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(224)
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(12.8)
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%
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NGLs (BOEPD, net)
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470
|
|
|
290
|
|
|
180
|
|
|
62.1
|
%
|
Natural gas (BOEPD, net)
|
440
|
|
|
—
|
|
|
440
|
|
|
n.m.
|
Equivalent volumes (BOEPD, net)
|
2,430
|
|
|
2,034
|
|
|
396
|
|
|
19.5
|
%
|
|
|
|
|
|
|
|
|
Oil average realized price per Bbl
|
$
|
47.60
|
|
|
$
|
44.76
|
|
|
$
|
2.84
|
|
|
6.3
|
%
|
NGL average realized price per Bbl
|
21.36
|
|
|
9.59
|
|
|
11.77
|
|
|
122.7
|
%
|
Natural gas average realized price per Mcf
|
2.73
|
|
|
1.90
|
|
|
0.83
|
|
|
43.7
|
%
|
Equivalent price per BOE
|
$
|
36.87
|
|
(a)
|
$
|
39.74
|
|
|
$
|
(2.87)
|
|
|
(7.2)
|
%
|
(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.
(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,
|
|
|
|
|
|
2021
|
|
2020
|
|
Variance
|
|
Variance %
|
Oil Derivative Contracts
|
|
|
|
|
|
|
|
Realized (gain) loss on derivatives, net
|
$
|
2,525,988
|
|
|
$
|
(528,139)
|
|
|
$
|
3,054,127
|
|
|
(578.3)
|
|
Unrealized (gain) loss on derivatives
|
(1,911,343)
|
|
|
1,911,343
|
|
|
(3,822,686)
|
|
|
(200.0)
|
|
Loss on derivatives
|
$
|
614,645
|
|
|
$
|
1,383,204
|
|
|
$
|
(768,559)
|
|
|
(55.6)
|
|
|
|
|
|
|
|
|
|
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,
|
|
|
|
|
|
2021
|
|
2020
|
|
Variance
|
|
Variance %
|
CO2 costs (a)
|
$
|
3,061,598
|
|
|
$
|
3,501,507
|
|
|
$
|
(439,909)
|
|
|
(12.6)
|
%
|
Other lease operating costs
|
13,525,454
|
|
|
10,003,995
|
|
|
3,521,459
|
|
|
35.2
|
%
|
Total lease operating costs
|
$
|
16,587,052
|
|
|
$
|
13,505,502
|
|
|
$
|
3,081,550
|
|
|
22.8
|
%
|
|
|
|
|
|
|
|
|
CO2 costs per BOE
|
$
|
3.45
|
|
|
$
|
4.70
|
|
|
$
|
(1.25)
|
|
|
(26.6)
|
%
|
All other lease operating costs per BOE
|
15.25
|
|
|
13.43
|
|
|
1.82
|
|
|
13.6
|
%
|
Lease operating costs per BOE
|
$
|
18.70
|
|
|
$
|
18.13
|
|
|
$
|
0.57
|
|
|
3.1
|
%
|
(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,
|
|
|
|
|
|
2021
|
|
2020
|
|
Variance
|
|
Variance %
|
CO2 costs per mcf
|
$
|
0.71
|
|
|
$
|
0.77
|
|
|
$
|
(0.06)
|
|
|
(7.8)
|
%
|
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.
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,
|
|
|
|
|
|
2021
|
|
2020
|
|
Variance
|
|
Variance %
|
DD&A of proved oil and gas properties
|
$
|
4,901,969
|
|
|
$
|
5,592,651
|
|
|
$
|
(690,682)
|
|
|
(12.3)
|
%
|
Depreciation of other property and equipment
|
7,000
|
|
|
8,779
|
|
|
(1,779)
|
|
|
(20.3)
|
%
|
Amortization of intangibles
|
47,474
|
|
|
13,564
|
|
|
33,910
|
|
|
250.0
|
%
|
Accretion of asset retirement obligations
|
210,183
|
|
|
146,504
|
|
|
63,679
|
|
|
43.5
|
%
|
Total DD&A
|
$
|
5,166,626
|
|
|
$
|
5,761,498
|
|
|
$
|
(594,872)
|
|
|
(10.3)
|
%
|
|
|
|
|
|
|
|
|
Oil and gas DD&A per BOE
|
$
|
5.53
|
|
|
$
|
7.51
|
|
|
$
|
(1.98)
|
|
|
(26.4)
|
%
|
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.
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,
|
|
|
|
|
|
2021
|
|
2020
|
|
Variance
|
|
Variance %
|
Interest and other income
|
39,401
|
|
|
177,418
|
|
|
(138,017)
|
|
|
(77.8)
|
%
|
Interest expense
|
(102,965)
|
|
|
(110,775)
|
|
|
7,810
|
|
|
(7.1)
|
%
|
Total other income (expense), net
|
$
|
(63,564)
|
|
|
$
|
66,643
|
|
|
$
|
(130,207)
|
|
|
(195.4)
|
%
|
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,
|
|
|
|
|
|
2021
|
|
2020
|
|
Variance
|
|
Variance %
|
Income (loss) before income tax provision
|
(21,422,195)
|
|
|
3,756,076
|
|
|
(25,178,271)
|
|
|
(670.3)
|
%
|
Income tax provision (benefit)
|
(4,984,261)
|
|
|
(2,180,996)
|
|
|
(2,803,265)
|
|
|
128.5
|
%
|
Net income (loss) available to common shareholders
|
$
|
(16,437,934)
|
|
|
$
|
5,937,072
|
|
|
$
|
(22,375,006)
|
|
|
(376.9)
|
%
|
Income tax provision (benefit) as a percentage of income before income tax
|
23
|
%
|
|
(58)
|
%
|
|
|
|
|
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.
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.
Item 8. Consolidated Financial Statements and Supplementary Data
Index to Consolidated Financial Statements
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.
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.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2021
|
|
June 30, 2020
|
Assets
|
|
|
|
Current assets
|
|
|
|
Cash and cash equivalents
|
$
|
5,276,510
|
|
|
$
|
19,662,528
|
|
Receivables from oil and gas sales
|
8,686,967
|
|
|
$
|
1,919,213
|
|
Receivables for federal and state income tax refunds
|
3,107,638
|
|
|
3,243,271
|
|
Prepaid expenses and other current assets
|
1,037,259
|
|
|
491,686
|
|
Total current assets
|
18,108,374
|
|
|
25,316,698
|
|
Property and equipment, net of depreciation, depletion, and amortization
|
|
|
|
Oil and natural gas properties—full-cost method of accounting, of which none were excluded from amortization
|
58,515,860
|
|
|
66,512,281
|
|
Other property and equipment, net
|
10,639
|
|
|
17,639
|
|
Total property and equipment, net
|
58,526,499
|
|
|
66,529,920
|
|
Other assets, net
|
70,789
|
|
|
291,618
|
|
Total assets
|
$
|
76,705,662
|
|
|
$
|
92,138,236
|
|
Liabilities and Stockholders' Equity
|
|
|
|
Current liabilities
|
|
|
|
Accounts payable
|
$
|
5,609,367
|
|
|
$
|
1,471,679
|
|
Accrued liabilities and other
|
947,045
|
|
|
716,648
|
|
Derivative contract liabilities
|
—
|
|
|
1,911,343
|
|
State and federal taxes payable
|
37,748
|
|
|
179,189
|
|
Total current liabilities
|
6,594,160
|
|
|
4,278,859
|
|
Long term liabilities
|
|
|
|
Senior secured credit facility
|
4,000,000
|
|
|
—
|
|
Deferred income taxes
|
5,957,202
|
|
|
11,061,023
|
|
Asset retirement obligations
|
5,538,752
|
|
|
2,588,894
|
|
Operating lease liability
|
20,745
|
|
|
84,978
|
|
Total liabilities
|
22,110,859
|
|
|
18,013,754
|
|
Commitments and contingencies
|
|
|
|
Stockholders' equity
|
|
|
|
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 33,514,952 and 32,956,469 shares as of June 30, 2021 and 2020, respectively
|
33,515
|
|
|
32,956
|
|
Additional paid-in capital
|
42,541,224
|
|
|
41,291,446
|
|
Retained earnings
|
12,020,064
|
|
|
32,800,080
|
|
Total stockholders' equity
|
54,594,803
|
|
|
74,124,482
|
|
Total liabilities and stockholders' equity
|
$
|
76,705,662
|
|
|
$
|
92,138,236
|
|
See accompanying notes to consolidated financial statements.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended June 30,
|
|
2021
|
|
2020
|
Revenues
|
|
|
|
Oil
|
$
|
26,411,132
|
|
|
$
|
28,578,879
|
|
Natural gas liquids
|
3,662,478
|
|
|
1,018,349
|
|
Natural gas
|
2,628,744
|
|
|
2,068
|
|
Total revenues
|
32,702,354
|
|
|
29,599,296
|
|
Operating costs
|
|
|
|
Lease operating costs
|
16,587,052
|
|
|
13,505,502
|
|
Depreciation, depletion, and amortization
|
5,166,626
|
|
|
5,761,498
|
|
Impairment of proved property
|
24,792,079
|
|
|
—
|
|
Impairment of Well Lift Inc. - related assets
|
146,051
|
|
|
—
|
|
Net loss on derivative contracts
|
614,645
|
|
|
1,383,204
|
|
General and administrative expenses*
|
6,754,532
|
|
|
5,259,659
|
|
Total operating costs
|
54,060,985
|
|
|
25,909,863
|
|
Income (loss) from operations
|
(21,358,631)
|
|
|
3,689,433
|
|
Other
|
|
|
|
Interest and other income
|
39,401
|
|
|
177,418
|
|
Interest expense
|
(102,965)
|
|
|
(110,775)
|
|
Income (loss) before income tax provision
|
(21,422,195)
|
|
|
3,756,076
|
|
Income tax expense (benefit)
|
(4,984,261)
|
|
|
(2,180,996)
|
|
Net income (loss) attributable to common shareholders
|
$
|
(16,437,934)
|
|
|
$
|
5,937,072
|
|
Earnings (loss) per common share
|
|
|
|
Basic
|
$
|
(0.49)
|
|
|
$
|
0.18
|
|
Diluted
|
$
|
(0.49)
|
|
|
$
|
0.18
|
|
Weighted average number of common shares outstanding
|
|
|
|
Basic
|
33,263,701
|
|
|
33,031,149
|
|
Diluted
|
33,263,701
|
|
|
33,033,091
|
|
* 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.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended June 30,
|
|
2021
|
|
2020
|
Cash flows from operating activities
|
|
|
|
Net income (loss) attributable to common shareholders
|
$
|
(16,437,934)
|
|
|
$
|
5,937,072
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
Depreciation, depletion, and amortization
|
5,166,626
|
|
|
5,761,498
|
|
Impairment of proved property
|
24,792,079
|
|
|
—
|
|
Impairment of Well Lift Inc. - related assets
|
146,051
|
|
|
—
|
|
Stock-based compensation
|
1,257,684
|
|
|
1,285,663
|
|
Settlement of asset retirement obligations
|
(101,311)
|
|
|
(76,832)
|
|
Deferred income taxes
|
(5,103,821)
|
|
|
(261,668)
|
|
Net loss on derivative contracts
|
614,645
|
|
|
1,383,204
|
|
Payments received (paid) for derivative settlements
|
(2,791,176)
|
|
|
793,327
|
|
Other
|
10,316
|
|
|
39,783
|
|
Changes in operating assets and liabilities:
|
|
|
|
Receivables
|
(6,632,121)
|
|
|
(1,994,368)
|
|
Prepaid expenses and other current assets
|
(545,573)
|
|
|
(33,408)
|
|
Accounts payable and accrued expenses
|
4,498,801
|
|
|
(486,010)
|
|
Income taxes payable
|
(141,441)
|
|
|
48,390
|
|
Net cash provided by operating activities
|
4,732,825
|
|
|
12,396,651
|
|
Cash flows from investing activities
|
|
|
|
Acquisition of oil and gas properties
|
(18,297,013)
|
|
|
(9,337,716)
|
|
Development of oil and natural gas properties
|
(472,401)
|
|
|
(1,724,829)
|
|
|
|
|
|
Net cash used by investing activities
|
(18,769,414)
|
|
|
(11,062,545)
|
|
Cash flows from financing activities
|
|
|
|
Common share repurchases, including shares surrendered for tax withholding
|
(7,347)
|
|
|
(2,483,357)
|
|
Common stock dividends paid
|
(4,342,082)
|
|
|
(10,740,754)
|
|
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)
|
|
Net decrease in cash, cash equivalents, and restricted cash
|
(14,386,018)
|
|
|
(11,890,005)
|
|
Cash, cash equivalents, and restricted cash, beginning of year
|
19,662,528
|
|
|
31,552,533
|
|
Cash, cash equivalents, and restricted cash, end of year *
|
$
|
5,276,510
|
|
|
$
|
19,662,528
|
|
* Neither annual period had any restricted cash balances.
See accompanying notes to consolidated financial statements.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Changes in Stockholders' Equity
For the Years Ended June 30, 2021 and 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
|
|
|
|
|
|
|
Additional
Paid-in
Capital
|
|
Retained
Earnings
|
|
Treasury
Stock
|
|
Total
Stockholders'
Equity
|
|
Shares
|
|
Par Value
|
|
Balance, June 30, 2019
|
33,183,730
|
|
|
$
|
33,183
|
|
|
$
|
42,488,913
|
|
|
$
|
37,603,762
|
|
|
$
|
—
|
|
|
$
|
80,125,858
|
|
Issuance of restricted common stock
|
271,778
|
|
|
272
|
|
|
(272)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Forfeitures of restricted stock
|
(49,118)
|
|
|
(49)
|
|
|
49
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Common share repurchases, including shares surrendered for tax withholding
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,483,357)
|
|
|
(2,483,357)
|
|
Retirements of treasury stock
|
(449,921)
|
|
|
(450)
|
|
|
(2,482,907)
|
|
|
—
|
|
|
2,483,357
|
|
|
—
|
|
Stock-based compensation
|
—
|
|
|
—
|
|
|
1,285,663
|
|
|
—
|
|
|
—
|
|
|
1,285,663
|
|
Net income attributable to common shareholders
|
—
|
|
|
—
|
|
|
—
|
|
|
5,937,072
|
|
|
—
|
|
|
5,937,072
|
|
Common stock dividends paid
|
—
|
|
|
—
|
|
|
—
|
|
|
(10,740,754)
|
|
|
—
|
|
|
(10,740,754)
|
|
Balance, June 30, 2020
|
32,956,469
|
|
|
32,956
|
|
|
41,291,446
|
|
|
32,800,080
|
|
|
—
|
|
|
74,124,482
|
|
Issuance of restricted common stock
|
561,115
|
|
|
562
|
|
|
(562)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common share repurchases, including shares surrendered for tax withholding
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,347)
|
|
|
(7,347)
|
|
Retirements of treasury stock
|
(2,632)
|
|
|
(3)
|
|
|
(7,344)
|
|
|
—
|
|
|
7,347
|
|
|
—
|
|
Stock-based compensation
|
—
|
|
|
—
|
|
|
1,257,684
|
|
|
—
|
|
|
—
|
|
|
1,257,684
|
|
Net loss attributable to the Company
|
—
|
|
|
—
|
|
|
—
|
|
|
(16,437,934)
|
|
|
—
|
|
|
(16,437,934)
|
|
Common stock dividends paid
|
—
|
|
|
—
|
|
|
—
|
|
|
(4,342,082)
|
|
|
—
|
|
|
(4,342,082)
|
|
Balance, June 30, 2021
|
33,514,952
|
|
|
$
|
33,515
|
|
|
$
|
42,541,224
|
|
|
$
|
12,020,064
|
|
|
$
|
—
|
|
|
$
|
54,594,803
|
|
See accompanying notes to consolidated financial statements.
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.
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.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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:
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
2021
|
|
2020
|
Revenues
|
|
|
|
Oil
|
$
|
26,411,132
|
|
|
$
|
28,578,879
|
|
Natural gas liquids
|
3,662,478
|
|
|
1,018,349
|
|
Natural gas
|
2,628,744
|
|
|
2,068
|
|
Total revenues
|
$
|
32,702,354
|
|
|
$
|
29,599,296
|
|
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
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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
|
2022
|
61,843
|
|
2023
|
26,098
|
|
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:
|
|
|
|
|
|
|
|
|
|
As of and For the Year Ended June 30, 2021
|
As of and For the Year Ended June 30, 2020
|
Cash Flow:
|
|
|
Cash paid for amounts included in the measurement of lease liabilities
|
$
|
59,945
|
|
$
|
4,903
|
|
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
|
|
Accrued liabilities - current
|
64,234
|
|
54,290
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
June 30,
2020
|
Prepaid insurance
|
$
|
365,922
|
|
|
$
|
289,999
|
|
Prepaid subscription and licenses
|
108,048
|
|
|
67,005
|
|
Prepaid federal and state income taxes
|
97,470
|
|
|
86,208
|
|
Carryback of EOR tax credit
|
416,441
|
|
|
—
|
|
Prepaid other
|
49,378
|
|
|
48,474
|
|
Total prepaid expenses and other current assets
|
$
|
1,037,259
|
|
|
$
|
491,686
|
|
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 6 – Property and Equipment, Net of Depreciation, Depletion, and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
June 30,
2020
|
Oil and natural gas properties:
|
|
|
|
Property costs subject to amortization
|
$
|
129,123,227
|
|
|
$
|
107,390,379
|
|
Less: Accumulated depreciation, depletion, and amortization and impairment (a)
|
(70,607,367)
|
|
|
(40,878,098)
|
|
Unproved properties not subject to amortization
|
—
|
|
|
—
|
|
Oil and natural gas properties, net
|
58,515,860
|
|
|
66,512,281
|
|
Other property and equipment:
|
|
|
|
Furniture, fixtures, and office equipment, at cost
|
154,731
|
|
|
154,731
|
|
Less: Accumulated depreciation (b)
|
(144,092)
|
|
|
(137,092)
|
|
Other property and equipment, net
|
$
|
10,639
|
|
|
$
|
17,639
|
|
(a) Depletion on oil and natural gas properties was $4,901,969 for fiscal 2021 and $5,592,651 for fiscal 2020. Impairment on oil and natural gas properties was $24,792,079 for fiscal 2021, and there was no impairment in fiscal 2020.
(b) Depreciation was $7,000 for fiscal 2021 and $8,779 for fiscal 2020.
As of June 30, 2021 and 2020, all oil and gas property costs were being amortized.
During the years ended June 30, 2021 and 2020, the Company incurred capital expenditures of $0.6 million and $1.5 million, respectively.
On May 7, 2021, the Company acquired an approximate 17% working interest and a 14% revenue interest in non-operated oil and gas assets in the Barnett Shale from Tokyo Gas Americas for $18.3 million, net of preliminary purchase price adjustments, and also recognized $2.8 million in non-cash asset retirement obligations. The Company accounted for this transaction as an asset acquisition with an effective of January 1, 2021.
On November 1, 2019, the Company acquired a 23.5% non-operated working interest and a 19.7% revenue interest in the Hamilton Dome unitized field located in Hot Springs County, Wyoming, from the Merit Energy Company. As a result of this cash purchase combined with its subsequent purchase adjustments, the Company recorded a purchase cost of $9.3 million, net of purchase price adjustments, and also recognized $0.9 million in non-cash asset retirement obligations. The Company accounted for this transaction as an asset acquisition.
In accordance with the Financial Accounting Standards Board’s authoritative guidance on asset acquisitions, the Company allocated the cost of the acquisition to the assets acquired and liabilities assumed based on a relative fair value basis of the assets acquired and liabilities assumed, with no recognition of goodwill or bargain purchase gain recorded. Incremental legal and professional fees related directly to the Acquisition were capitalized as part of the Acquisition cost. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize market assumptions of market participants.
The Company uses the full cost method of accounting for its investments in oil and natural gas properties. All costs of acquisition, exploration, and development of oil and natural gas reserves are capitalized as the cost of oil and natural gas and properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs result in an impairment charge.
At June 30, 2021, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended June 30, 2021 of the West Texas Intermediate (WTI) oil spot price of $49.72 per barrel and Henry Hub natural gas spot price of $2.46 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $19.81, which does not have any single comparable reference index price. The NGL price was based on historical prices received. Using these prices, the Company’s net book value of oil and natural gas properties at June 30, 2021 did not exceed the current ceiling.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, from $47.37 per barrel at June 30, 2020 to $43.63 per barrel at September 30, 2020 to $39.54 per barrel at December 31, 2020.
Note 7 – Other Assets, Net
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
June 30,
2020
|
Royalty rights
|
—
|
|
|
108,512
|
|
Less: Accumulated amortization of royalty rights
|
—
|
|
|
(61,037)
|
|
Investment in Well Lift Inc., at cost
|
—
|
|
|
108,750
|
|
Deferred loan costs
|
168,972
|
|
|
168,972
|
|
Less: Accumulated amortization of deferred loan costs
|
(168,972)
|
|
|
(157,084)
|
|
Right of use asset under operating lease
|
161,125
|
|
|
161,125
|
|
Less: Accumulated amortization of right of use asset
|
(90,336)
|
|
|
(43,932)
|
|
Software license
|
20,662
|
|
|
20,662
|
|
Less: Accumulated amortization of software license
|
(20,662)
|
|
|
(14,350)
|
|
Other assets, net
|
$
|
70,789
|
|
|
$
|
291,618
|
|
Our royalty rights and investment in WLI resulted from the separation of our artificial lift technology operations in December 2015. We conveyed our patents and other intellectual property to WLI and retained a 5% royalty on future gross revenues associated with the technology. We own 17.5% of the common stock and 100% of the preferred stock of WLI and account for our investment in this private company at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer, if such were to occur. The Company evaluates the investment for impairment when it identifies any events or changes in circumstances that might have a significant adverse effect on the fair value of the investment. At March 31, 2021, we reviewed our investment and technology rights in WLI for potential impairment and, as a result, recorded an impairment expense of $0.1 million. This impairment charge was recorded based on a variety of factors including the lack of current revenue generated and the outlook for future activity associated with this technology primarily due to a reduction in drilling activities across the industry.
Note 8 – Accrued Liabilities and Other
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
2021
|
|
June 30,
2020
|
Accrued incentive and other compensation
|
$
|
630,744
|
|
|
$
|
176,636
|
|
Accrued retirement costs
|
52,786
|
|
|
—
|
|
Accrued franchise taxes
|
35,207
|
|
|
100,978
|
|
Accrued ad valorem taxes
|
108,000
|
|
|
108,000
|
|
Payable for settled derivatives
|
—
|
|
|
265,188
|
|
Operating lease liability, current
|
64,234
|
|
|
54,290
|
|
Asset retirement obligations due within one year
|
44,520
|
|
|
—
|
|
Accrued - other
|
11,554
|
|
|
11,556
|
|
Total Accrued liabilities and other
|
$
|
947,045
|
|
|
$
|
716,648
|
|
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 9 – Asset Retirement Obligations
Our asset retirement obligations represent the estimated present value of the amount we expect to incur to plug, abandon, and remediate our producing properties at the end of their productive lives in accordance with applicable laws and regulations. During the year ended June 30, 2021, the Delhi field operator abandoned two wells. Presently, we expect the Hamilton Dome operator to plug four wells during the next twelve months. The following is a reconciliation of the beginning and ending asset retirement obligations for the years ended June 30, 2021 and 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended
|
|
2021
|
|
2020
|
Asset retirement obligations — beginning of period
|
$
|
2,588,894
|
|
|
$
|
1,610,845
|
|
Liabilities incurred
|
—
|
|
|
40,698
|
|
Liabilities settled
|
(99,231)
|
|
(a)
|
(86,592)
|
|
Liabilities acquired
|
2,806,331
|
|
(b)
|
903,580
|
|
Accretion of discount
|
210,182
|
|
|
146,504
|
|
Revisions of previous estimates
|
77,096
|
|
(c)
|
(26,141)
|
|
Asset retirement obligations — end of period
|
5,583,272
|
|
|
2,588,894
|
|
Less: current asset retirement obligations
|
44,520
|
|
|
—
|
|
Long-term portion of asset retirement obligations
|
$
|
5,538,752
|
|
|
$
|
2,588,894
|
|
(a) Abandonment of two non-scheduled Delhi field wells in fiscal 2021, and abandonment of one Delhi field well and four Hamilton Dome field wells in fiscal 2020.
(b) Liabilities acquired in fiscal 2021 and 2020 were primarily due to our acquisition of the Barnett Shale interest and the Hamilton Dome interest, respectively.
(c) Primarily related to upward revisions for two difficult-to-plug Delhi field wells in fiscal 2021.
Note 10 – Stockholders' Equity
Common Stock
As of June 30, 2021, we had 33,514,952 shares of common stock outstanding.
The Company began paying quarterly cash dividends on common stock in December 2013. As of June 30, 2021, we have cumulatively paid over $74.5 million in cash dividends. We paid dividends of $4,342,082 and $10,740,754 to our common stockholders during the years ended June 30, 2021 and 2020, respectively. The following table reflects the dividends paid within the respective three-month periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year
|
|
2021
|
|
2020
|
Fourth quarter ended June 30,
|
$0.050
|
|
$0.025
|
Third quarter ended March 31,
|
$0.030
|
|
$0.100
|
Second quarter ended December 31,
|
$0.025
|
|
$0.100
|
First quarter ended September 30,
|
$0.025
|
|
$0.100
|
In May 2015, the Board of Directors approved a share repurchase program covering up to $5.0 million of the Company's common stock. Since inception of the program through June 30, 2021, the Company has spent $4.0 million to repurchase 706,858 common shares at an average price of $5.72 per share. There were no shares purchased under this program during the year ended June 30, 2021. Under the program's terms, shares are repurchased only on the open market and in accordance with the requirements of the SEC. Such shares are initially recorded as treasury stock, then subsequently canceled. The timing and amount of repurchases depends upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and it may be suspended or discontinued at any time.
During the year ended June 30, 2021 and 2020, the Company also acquired treasury stock from holders of newly vested stock-based awards to fund the recipients' payroll tax withholding obligations. The treasury shares were subsequently canceled. Such
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
shares were valued at fair market value on the date of vesting. The following table shows all treasury stock purchases in the last two fiscal years:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Shares Acquired
|
|
Average Price per Share
|
|
Treasury Stock Purchases
|
Year Ended June 30, 2021:
|
|
|
|
|
|
Shares surrendered for tax withholding upon vesting
|
2,632
|
|
|
$
|
2.79
|
|
|
$
|
7,347
|
|
Share repurchase program
|
—
|
|
|
$
|
—
|
|
|
—
|
|
Total
|
2,632
|
|
|
$
|
2.79
|
|
|
$
|
7,347
|
|
|
|
|
|
|
|
Year Ended June 30, 2020:
|
|
|
|
|
|
Shares surrendered for tax withholding upon vesting
|
9,255
|
|
|
$
|
5.90
|
|
|
$
|
54,565
|
|
Share repurchase program
|
440,666
|
|
|
$
|
5.51
|
|
|
2,428,792
|
|
Total
|
449,921
|
|
|
$
|
5.52
|
|
|
$
|
2,483,357
|
|
Expected Tax Treatment of Dividends
For the fiscal year ended June 30, 2020, all common stock dividends for that fiscal year were treated for tax purposes as qualified dividend income to the recipients. Based on our current projections for the fiscal year ended June 30, 2021, we expect all common stock dividends for such period to be treated as qualified dividend income to the recipients.
Note 11—Stock-Based Incentive Plan
The Evolution Petroleum Corporation 2016 Equity Incentive Plan (“2016 Plan”), approved in the December 2016 annual meeting, authorized the issuance of 1,100,000 shares of common stock prior to its expiration on December 8, 2026. Incentives under the 2016 Plan may be granted to employees, directors, and consultants of the Company in any one or a combination of the following forms: incentive stock options and non-statutory stock options, stock appreciation rights, restricted stock awards and restricted stock unit awards, performance share awards, performance cash awards, and other forms of incentives valued in whole or in part by reference to, or otherwise based on, our common stock, including its appreciation in value. On December 9, 2020, an amendment to the 2016 Plan was approved by our stockholders which increased the number of shares available for issuance by 2,500,000 shares. There were 2,206,294 shares available for grant under the 2016 Plan as of June 30, 2021.
Restricted Stock and Contingent Restricted Stock
The Company has awarded grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after a maximum of four years if unvested, contain service-based, performance-based, and market-based vesting provisions. The common shares underlying the Restricted Stock grants are issued on the date of grant. Contingent Restricted Stock grants vest only upon the attainment of higher performance-based or market-based vesting thresholds and are issued only upon vesting. Shares underlying Contingent Restricted Stock awards are reserved from the Plan they were granted under.
During the year ended June 30, 2021, the Company granted 314,955 service-based restricted stock awards primarily to employees under its long term incentive program together with annual awards to its directors. In addition, under this program, the Company granted 246,160 market-based restricted stock awards and 123,080 Contingent Restricted Stock awards to employees. In addition to the foregoing, in connection with the retirement of the Company's former Chief Financial Officer, vesting was accelerated as to 50,524 aggregate shares of service- and market-based equity awards (with a weighted average fair value of $5.15 per share) which, for accounting purposes, was treated as a cancellation and replacement of the same number of awards which had a fair value of $2.79 per share.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
During the year ended June 30, 2020, the Chief Executive Officer upon his July 2019 employment received 48,872 shares of service-based restricted common stock which vests in three equal amounts on June 30, 2020, 2021, and 2022; he was also awarded a total of 200,000 market-based Contingent Restricted Stock units consisting of four equal tranches, each of which may vest only if its respective stock price requirement is met before the award term expires. Each tranche has a separate stated price requirement and respective vesting will occur only if, before July 1, 2023, the ninety-day trailing average Company stock share price equals or exceeds its tranche price requirement. We also granted 52,119 service-based and 104,236 market-based Restricted Stock awards to our employees as well as 56,395 serviced-based awards to the company's directors.
Service-based awards vest with continuous employment by the Company, generally in annual installments over terms of three to four years. Awards to the Company's directors have one-year cliff vesting. Restricted Stock grants, which vest based on service, are valued at the fair market value of the Company’s common stock on the date of grant and amortized over the service period.
Performance-based grants vest upon the attainment of earnings, revenue, and other operational goals and require that the recipient remain an employee or director of the Company through the vesting date. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period based on the grant date fair value of the Company’s common stock and when it is deemed probable, for accounting purposes, that the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the term of the award. As of June 30, 2021, there were no performance-based awards outstanding.
Many of our past market-based awards could vest if their respective two- or three-year trailing total returns on the Company’s common stock exceed the corresponding total returns of various quartiles of indices consisting of peer companies. Additionally, more recent market-based awards vest when the average of the Company's closing stock price over a defined quarterly measurement period meets or exceeds a required stock price. The third-party independent assessment of fair values and expected vesting periods of these awards are determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies in the index. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the holder remains an employee or director of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service.
For market-based awards granted during the years ended June 30, 2021 and 2020, the assumptions used in the Monte Carlo simulation valuations, expected lives and fair values were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30,
|
|
2021
|
|
2020
|
|
|
|
|
Weighted average fair value of market-based awards granted
|
$
|
3.08
|
|
|
$
|
3.79
|
|
Risk-free interest rate
|
0.23
|
%
|
|
1.65% to 1.87%
|
Expected life in years
|
2.56
|
|
1.35 to 2.56
|
Expected volatility
|
56.9
|
%
|
|
38.6% to 43.7%
|
Dividend yield
|
3.2
|
%
|
|
6% to 7.2%
|
Unvested Restricted Stock awards at June 30, 2021 consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
Award Type
|
Number of
Restricted
Shares
|
|
Weighted
Average
Grant-Date
Fair Value
|
Service-based awards
|
348,762
|
|
|
$
|
3.37
|
|
|
|
|
|
Market-based awards
|
320,533
|
|
|
3.38
|
|
Unvested at June 30, 2021
|
669,295
|
|
|
$
|
3.37
|
|
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table sets forth the Restricted Stock transactions for the year ended June 30, 2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
Restricted
Shares
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
Unamortized Compensation Expense at June 30, 2021
|
|
Weighted Average Remaining Amortization Period (Years)
|
Unvested at July 1, 2020
|
285,028
|
|
|
$
|
5.53
|
|
|
$
|
—
|
|
|
|
Service-based shares granted
|
365,479
|
|
|
2.97
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market-based shares granted
|
246,160
|
|
|
3.07
|
|
|
|
|
|
Vested
|
(176,848)
|
|
|
5.09
|
|
|
|
|
|
Forfeited
|
(50,524)
|
|
|
5.15
|
|
|
|
|
|
Unvested at June 30, 2021
|
669,295
|
|
|
$
|
3.37
|
|
|
$
|
1,530,550
|
|
|
1.88
|
The following is a summary of Restricted Stock that vested during the last two fiscal years:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30,
|
|
2021
|
|
2020
|
Vesting-date intrinsic value of Restricted Stock
|
$
|
570,711
|
|
|
$
|
477,647
|
|
Grant-date fair value of vested Restricted Stock
|
$
|
900,007
|
|
|
$
|
748,893
|
|
Number of awards that vested
|
176,848
|
|
|
104,159
|
|
Unvested Contingent Restricted stock awards table below consists solely of market-based awards for the year ended June 30, 2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
Restricted
Stock Units
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
Unamortized Compensation Expense at June 30, 2021
|
|
Weighted Average Remaining Amortization Period (Years)
|
Unvested at July 1, 2020
|
200,000
|
|
|
$
|
3.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market-based awards granted
|
123,080
|
|
|
1.76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested
|
—
|
|
|
—
|
|
|
|
|
|
Unvested at June 30, 2021
|
323,080
|
|
|
$
|
2.84
|
|
|
$
|
169,257
|
|
|
2.00
|
All of these outstanding awards at June 30, 2021 are market-based awards.
The following is a summary of Contingent Restricted Stock vestings for the last two fiscal years:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30,
|
|
2021
|
|
2020
|
Vest-date intrinsic value of Contingent Restricted Stock
|
$
|
—
|
|
|
$
|
60,225
|
|
Grant-date fair value of vested Contingent Restricted Stock
|
$
|
—
|
|
|
$
|
34,734
|
|
Number of awards that vested
|
—
|
|
|
10,156
|
|
Stock-based Compensation Expense
For the years ended June 30, 2021, and 2020, we recognized stock-based compensation expense related to Restricted Stock and Contingent Restricted Stock grants of $1,257,684 and $1,285,663, respectively.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 12 – Supplemental Disclosure of Cash Flow Information
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
2021
|
|
2020
|
|
Interest paid on the Senior Secured Credit Facility
|
$
|
86,347
|
|
|
$
|
76,390
|
|
|
Income taxes paid
|
757,963
|
|
1,241,538
|
|
Income tax refunds
|
141,848
|
|
|
—
|
|
|
Non-cash transactions:
|
|
|
|
|
Decrease in accrued purchases of property and equipment
|
80,008
|
|
|
(212,456)
|
|
|
Oil and natural gas property costs attributable to the recognition of asset retirement obligations
|
2,883,426
|
|
|
918,137
|
|
|
Note 13 – Income Taxes
We file a consolidated federal income tax return in the United States of America in addition to various combined and separate filings in several state and local jurisdictions.
There were no unrecognized tax benefits, nor any accrued interest or penalties associated with unrecognized tax benefits during the years ended June 30, 2021 and 2020. We believe that we have appropriate support for the income tax positions taken and to be taken on the Company's tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations for the years ended June 30, 2017 through June 30, 2020 for federal tax purposes and for the years ended June 30, 2016 through June 30, 2020 for state tax purposes. To the extent we utilize net operating losses generated in earlier years, such earlier years may also be subject to audit.
The components of our income tax provision (benefit) are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2021
|
|
June 30, 2020
|
Current:
|
|
|
|
Federal
|
$
|
(334,473)
|
|
|
$
|
(2,264,850)
|
|
State
|
454,033
|
|
|
345,522
|
|
Total current income tax provision (benefit)
|
119,560
|
|
|
(1,919,328)
|
|
Deferred:
|
|
|
|
Federal
|
(3,987,211)
|
|
|
(266,482)
|
|
State
|
(1,116,610)
|
|
|
4,814
|
|
Total deferred income tax provision (benefit)
|
(5,103,821)
|
|
|
(261,668)
|
|
Total income tax provision (benefit)
|
$
|
(4,984,261)
|
|
|
$
|
(2,180,996)
|
|
For the years ended June 30, 2021 and 2020, respectively, we recognized an income tax benefit of $5.0 million and an income tax benefit of $2.2 million reflecting corresponding effective tax rates of 23.3% and (58.1)%, respectively. During the fiscal 2020 year we undertook a project to seek potential cash tax savings opportunities identifying available Enhanced Oil Recovery credits (“EOR credits”) related to our interests in the Delhi field. To take advantage of the EOR credits, we amended federal and state tax returns for the years ended June 30, 2017 and 2018 and incorporated the associated impacts into our 2019 tax returns. Principally as a result of the EOR credits, the Company recorded a net tax benefit of $2.8 million during fiscal 2020. Relative to the foregoing, the Company has a $3.1 million receivable for income tax refunds at June 30, 2021, which the Company currently anticipates to receive in the next twelve months based on inquiries and communication with the IRS, although no assurances can be made as to the actual date of receipt. During fiscal 2021, we recognized an income tax benefit of $0.3 million attributable to the EOR credit.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Our effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the State of Louisiana, and differences related to percentage depletion in excess of basis, stock-based compensation, valuation allowance on deferred tax assets, and other permanent differences. The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate to the income tax provision (benefit) in our financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2021
|
|
% of Income Before Income Taxes
|
|
June 30, 2020
|
|
% of Income Before Income Taxes
|
|
|
|
|
|
Income tax provision (benefit) computed at the statutory federal rate:
|
$
|
(4,498,661)
|
|
|
21.0
|
%
|
|
$
|
788,776
|
|
|
21.0
|
%
|
|
|
|
|
|
Reconciling items:
|
|
|
|
|
|
|
|
|
|
|
|
|
Return to provision adjustments
|
20,036
|
|
|
(0.1)
|
%
|
|
(2,823,527)
|
|
|
(75.2)
|
%
|
|
|
|
|
|
Depletion in excess of tax basis
|
(175,840)
|
|
|
0.8
|
%
|
|
(412,215)
|
|
|
(11.0)
|
%
|
|
|
|
|
|
State income taxes, net of federal tax benefit
|
(523,436)
|
|
|
2.4
|
%
|
|
272,962
|
|
|
7.3
|
%
|
|
|
|
|
|
Permanent differences related to stock-based compensation and other
|
55,278
|
|
|
(0.3)
|
%
|
|
22,408
|
|
|
0.6
|
%
|
|
|
|
|
|
Federal valuation allowance
|
570,064
|
|
|
(2.7)
|
%
|
|
—
|
|
|
—
|
%
|
|
|
|
|
|
EOR credit benefit
|
(335,717)
|
|
|
1.6
|
%
|
|
—
|
|
|
—
|
%
|
|
|
|
|
|
Other
|
(95,985)
|
|
|
0.6
|
%
|
|
(29,400)
|
|
|
(0.8)
|
%
|
|
|
|
|
|
Income tax provision (benefit)
|
$
|
(4,984,261)
|
|
|
23.3
|
%
|
|
$
|
(2,180,996)
|
|
|
(58.1)
|
%
|
|
|
|
|
|
Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset (Liability)
|
|
June 30, 2021
|
|
June 30, 2020
|
Deferred tax assets:
|
|
|
|
Non-qualified stock-based compensation
|
$
|
309,671
|
|
|
$
|
234,559
|
|
Net operating loss carry-forwards and other carry-forwards
|
365,279
|
|
|
78,197
|
|
Derivative losses
|
—
|
|
|
401,382
|
|
Asset retirement obligations (a)
|
1,284,907
|
|
|
650,042
|
|
Other deferred tax assets
|
160,313
|
|
|
53,159
|
|
Gross deferred tax assets
|
2,120,170
|
|
|
1,417,339
|
|
Valuation allowance
|
(861,838)
|
|
|
(53,218)
|
|
Net deferred tax assets
|
1,258,332
|
|
|
1,364,121
|
|
Deferred tax liability:
|
|
|
|
Oil and natural gas properties (a)
|
(7,215,534)
|
|
|
(12,425,144)
|
|
Total deferred tax liability
|
(7,215,534)
|
|
|
(12,425,144)
|
|
|
|
|
|
Net deferred tax liability
|
$
|
(5,957,202)
|
|
|
$
|
(11,061,023)
|
|
(a) Certain deferred tax assets related to asset retirement obligations have been reclassified from the June 30, 2020 oil and natural gas properties deferred tax liability balance in order to conform to the current year presentation.
As of June 30, 2021, we had a federal tax loss carryforward of approximately $0.6 million that we acquired through a reverse merger in May 2004. The majority of the tax loss carryforwards from the reverse merger expired without being utilized. We will be able to utilize a maximum of $0.2 million of these carryforwards in equal annual amounts of $39,648 through 2023 and the balance is not able to be utilized based on the provisions of Internal Revenue Code (“IRC”) Section 382. We have recorded a valuation allowance for the portion of our net operating loss that is limited by IRC Section 382.
In addition, we must assess the likelihood that we will be able to realize our deferred tax assets. Realization is dependent on generating sufficient taxable income over the period the deferred tax assets are deductible. Given the Company is in a cumulative loss position, Management considered the reversal of deferred tax liabilities and tax planning strategies in making
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
the assessment of the realization of deferred tax assets. Based upon the weight of available evidence, the Company believes that some of the deferred tax assets are not likely to be realized at the time of this report and have recorded an increase in the valuation allowance during the current year related to the federal and state deferred tax assets of $0.6 million and $0.2 million respectively.
Note 14 – Earnings (Loss) per Common Share
The following table sets forth the computation of basic and diluted net income per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
2021
|
|
2020
|
Numerator
|
|
|
|
Net income (loss) attributable to common stockholders
|
$
|
(16,437,934)
|
|
|
$
|
5,937,072
|
|
Denominator
|
|
|
|
Weighted average number of common shares – Basic
|
33,263,701
|
|
|
33,031,149
|
|
Effect of dilutive securities:
|
|
|
|
Contingent restricted stock grants
|
—
|
|
|
1,942
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares and dilutive potential common shares used in diluted earnings (loss) per share
|
33,263,701
|
|
|
33,033,091
|
|
Net earnings (loss) per common share – Basic
|
$
|
(0.49)
|
|
|
$
|
0.18
|
|
Net earnings (loss) per common share – Diluted
|
$
|
(0.49)
|
|
|
$
|
0.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding Potentially Dilutive Securities
|
Weighted
Average
Exercise Price
|
|
Outstanding at June 30, 2021
|
Contingent Restricted Stock grants
|
$
|
—
|
|
|
323,080
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding Potential Dilutive Securities
|
Weighted
Average
Exercise Price
|
|
Outstanding at June 30, 2020
|
Contingent Restricted Stock grants
|
$
|
—
|
|
|
200,000
|
|
Note 15 – Senior Secured Credit Agreement
On April 11, 2016, the Company entered into a three-year, senior secured reserve-based credit facility (the “Senior Secured Credit Facility”) in an amount up to $50 million. On May 25, 2018, we entered into the third amendment to our credit agreement governing the Facility to, among other things, extend the maturity date to April 11, 2021. On December 31, 2018, we entered into the fourth amendment to our credit agreement governing the Senior Secured Credit Facility to broaden the definition for the Use of Proceeds.
Under the Senior Secured Credit Facility the borrowing base is redetermined semiannually. On November 2, 2020, the Company completed its Fall redetermination of the Senior Secured Credit Facility, resulting in a borrowing base of $23 million, and entered into the fifth amendment to the Senior Secured Credit Facility extending the maturity to April 9, 2024.
On January 5, 2021 and effective as of December 28, 2020, we entered into the sixth amendment of our Senior Secured Credit Facility which replaced the Debt Service Coverage Ratio (as defined therein) maintenance covenant with a new covenant requiring Current Ratio (as defined therein) of not less than 1.00 to 1.00.
On March 30, 2021, the Company completed its spring redetermination of the Senior Secured Credit Facility, resulting in a borrowing base increase to $30 million.
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.
We were in compliance with all financial covenants and there was $4 million outstanding under the Senior Secured Credit Facility at June 30, 2021 which is secured by substantially all of the Company's assets.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Borrowings from the Senior Secured Credit Facility may be used for the acquisition and development of oil and natural gas properties, investments in cash flow generating assets complimentary to the production of oil and natural gas, and for letters of credit and other general corporate purposes.
The Senior Secured Credit Facility included a placement fee of 0.50% on the initial borrowing base amounting to $50,000,000 and carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Senior Secured Credit Facility will bear interest, at the Company’s 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%. The Senior Secured Credit Facility contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (a) a maximum total leverage ratio of not more than 3.00 to 1.00, (b) a current ratio of not less than 1.00 to 1.00, and (c) a consolidated tangible net worth of not less than $40 million, all as defined under the Senior Secured Credit Facility.
In connection with the Senior Secured Credit Facility, the Company has incurred $168,972 of past debt issuance costs. Such costs were capitalized in "Other assets, net" and have been completely amortized to expense as of June 30, 2021.
Note 16 – Commitments and Contingencies
We are subject to various claims and contingencies in the normal course of business. In addition, from time to time, we receive communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdictions in which we operate. At a minimum, we disclose such matters if we believe it is reasonably possible that a future event or events will confirm a material loss through impairment of an asset or the incurrence of a liability. We accrue a material loss if we believe it is probable that a future event or events will confirm a loss, we can reasonably estimate such loss, and we do not accrue future legal costs related to that loss. Furthermore, we will disclose any matter that is unasserted if we consider it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable and material in amount. We expense legal defense costs as they are incurred.
Note 17 – Concentrations of Credit Risk
Major Customers. As a non-operator, we presently market our production through the field operators. The majority of our natural gas, oil, and condensate production is sold to purchasers under short-term (less than 12 months) contracts at market-based prices. The following table identifies customers from whom we derived 10 percent or more of our net oil and natural gas revenues during the years ended June 30, 2021 and 2020. The loss of either one of our oil purchasers or disruption to their respective pipelines could adversely affect our net realized pricing and potentially our near-term production levels. The loss of our NGL purchaser, who trucks NGLs from the field, would not be expected to have a material adverse effect on our operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30,
|
Customer
|
2021
|
|
2020
|
Plains Marketing L.P. (Delhi field oil)
|
62
|
%
|
|
87
|
%
|
Merit Energy Company (Hamilton Dome field oil)
|
19
|
%
|
|
10
|
%
|
All others
|
19
|
%
|
|
3
|
%
|
Total
|
100
|
%
|
|
100
|
%
|
Accounts Receivable. Substantially all of our accounts receivable from field operators result from oil and natural gas sales to third-parties in the oil and natural gas industry. Our concentration of customers in this industry may impact our overall credit risk.
Cash and Cash Equivalents. We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents in high quality money market funds. At times, cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation (“FDIC”).
Note 18 – Derivatives
It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of June 30, 2021, the Company did not have any remaining open derivative contracts.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Company has in the past and may utilize in the future fixed-price swaps or costless put/call collars to hedge a portion of its anticipated future production. Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for the volumes under contract. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract, and a purchased put that establishes a minimum price. The Company has elected not to designate its open derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of the derivative contracts and all payments and receipts on settled derivative contracts in “Net (gain) loss on derivative contracts” on the consolidated statements of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended June 30,
|
|
|
2021
|
|
2020
|
Realized (gain) loss
|
|
$
|
2,525,988
|
|
|
$
|
(528,139)
|
|
Unrealized (gain) loss
|
|
(1,911,343)
|
|
|
1,911,343
|
|
Net (gain) loss on derivative contracts
|
|
$
|
614,645
|
|
|
$
|
1,383,204
|
|
The Company’s derivative contract is recorded at fair market value and is included in the consolidated balance sheets as an asset or a liability. The Company did not have any open positions as of June 30, 2021.
The following sets forth a summary of the Company’s oil derivative positions during the year ended June 30, 2021.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period
|
|
Type of Contract
|
|
Volumes in Barrels
|
|
Price / Price Range
|
|
Weighted Average Floor Price per Bbl.
|
|
Weighted Average Ceiling Price per Bbl.
|
July 2020 to December 2020
|
|
Fixed-Price Swap
|
|
257,600
|
|
|
$32
|
|
$32
|
|
$—
|
The Company nets its derivative instrument fair value amounts executed with the same counterparty. The Company enters into an ISDA with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.
Note 19 – Fair Value Measurement
Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.
The three levels are defined as follows:
Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.
Level 2—Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3—Unobservable inputs for which there are little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.
Fair Value of Derivative Instruments. The Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 – Fair Value Measurement (“ASC 820”) establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs are generally market corroborated (Level 2), and the Company classifies fair value balances as such. There were no open positions as of June 30, 2021, and there were $1.9 million of open positions as of June 30, 2020 which were all settled during the current fiscal year.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment; this may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented in this report. The Company did not have any open positions as of June 30, 2021.
Other Fair Value Measurements. The initial measurement and any subsequent revision of asset retirement obligations at fair value are calculated using discounted future cash flows of internally estimated costs. Significant Level 3 inputs used in the calculation of asset retirement obligations include the costs of plugging and abandoning wells, surface restoration, and reserve lives. Subsequent to initial recognition, revisions to estimated asset retirement obligations are made when changes occur for input values.
Note 20 – Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited)
Costs incurred for oil and natural gas property acquisition, exploration, and development activities
The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration, and development activities. Property acquisition costs are those costs incurred to lease property, including both undeveloped leasehold, and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination, examining specific areas that are considered to have prospects containing oil and natural gas reserves, costs of drilling exploratory wells, geologic and geophysical assessment costs, and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling. Development costs also include amounts incurred due to the recognition of asset retirement obligations of $2,883,426 and $918,137 during the years ended June 30, 2021 and 2020, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended June 30,
|
|
2021
|
|
2020
|
Oil and Natural Gas Activities
|
|
|
|
Property acquisition costs:
|
|
|
|
Proved property
|
$
|
18,297,013
|
|
|
$
|
9,337,716
|
|
Unproved property
|
—
|
|
|
—
|
|
Exploration costs
|
—
|
|
|
—
|
|
Development costs
|
3,435,836
|
|
|
2,430,510
|
|
Total costs incurred for oil and natural gas activities
|
$
|
21,732,849
|
|
|
$
|
11,768,226
|
|
Estimated Net Quantities of Proved Oil and Natural Gas Reserves
The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the United States of America are based on evaluations prepared by third-party reservoir engineers, D&M. Reserve volumes and values were determined under the method prescribed by the SEC for our fiscal years ended June 30, 2021 and 2020. SEC methodology requires the application of the previous 12 months unweighted arithmetic average first-day-of-the-month price, and current costs held constant throughout the projected reserve life, when estimating whether reserve quantities are economical to produce.
Proved oil and natural gas reserves are estimated quantities of oil, natural gas, and natural gas liquids that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in estimating quantities of proved oil and natural gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Estimated quantities of proved oil, natural gas, and natural gas liquids reserves and changes in quantities of proved developed and undeveloped reserves for each of the periods indicated are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
(Bbls)
|
|
NGLs
(Bbls)
|
|
Natural Gas
(Mcf)
|
|
BOE
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
June 30, 2019
|
7,615,731
|
|
|
1,364,761
|
|
|
—
|
|
|
8,980,492
|
|
Revisions of previous estimates (a)
|
(2,177,787)
|
|
|
734,169
|
|
|
—
|
|
|
(1,443,618)
|
|
Improved recovery, extensions and discoveries
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Sales of minerals in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchase of reserves in place (c)
|
3,426,756
|
|
|
—
|
|
|
|
|
3,426,756
|
|
Production (sales volumes)
|
(638,464)
|
|
|
(106,340)
|
|
|
—
|
|
|
(744,804)
|
|
June 30, 2020
|
8,226,236
|
|
|
1,992,590
|
|
|
—
|
|
|
10,218,826
|
|
Revisions of previous estimates (b)
|
661,711
|
|
|
93,139
|
|
|
330
|
|
|
754,905
|
|
Improved recovery, extensions and discoveries
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchase of reserves in place (c)
|
86,608
|
|
|
4,957,226
|
|
|
49,533,801
|
|
|
13,299,468
|
|
Sales of minerals in place
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Production (sales volumes)
|
(554,888)
|
|
|
(171,451)
|
|
|
(963,496)
|
|
|
(886,922)
|
|
June 30, 2021
|
8,419,667
|
|
|
6,871,504
|
|
|
48,570,635
|
|
|
23,386,277
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
June 30, 2019
|
6,273,907
|
|
|
1,124,302
|
|
|
—
|
|
|
7,398,209
|
|
June 30, 2020
|
6,577,731
|
|
|
1,777,236
|
|
|
—
|
|
|
8,354,967
|
|
June 30, 2021
|
6,815,126
|
|
|
6,662,952
|
|
|
48,570,634
|
|
|
21,573,184
|
|
Proved undeveloped reserves:
|
|
|
|
|
|
|
|
June 30, 2019
|
1,341,824
|
|
|
240,459
|
|
|
—
|
|
|
1,582,283
|
|
June 30, 2020
|
1,648,505
|
|
|
215,354
|
|
|
—
|
|
|
1,863,859
|
|
June 30, 2021
|
1,604,541
|
|
|
208,551
|
|
|
—
|
|
|
1,813,092
|
|
(a) Revisions in fiscal year 2020 were primarily due to negative revisions at Hamilton Dome field reflecting the impact of pricing on future economic production. In March 2020 when the oil price decreased, the operator began to shut-in wells that were not economic at those lower prices to try and keep the field cash flow positive. The use of an SEC price deck for our reserves at June 30, 2020, precludes volumes that are uneconomic at such prices. Positive NGL revisions at Delhi field reflect adjusted methodology of forecasting NGLs independently from the oil production as forecasted by our independent reservoir engineering firm.
(b) Revisions in fiscal year 2021 were primarily due to positive revisions at Hamilton Dome reflecting the impact of increased oil pricing in the field on future production and extension of reserves economic limit. Positive NGL revisions at Delhi field reflect the impact of increased pricing on future production and the extension of reserves economic limit. Positive natural gas revisions in the Barnett Shale reflect the impact of increased natural gas prices from the date of the Barnett Shale Acquisition on May 7, 2021 to the end of the fiscal year on June 30, 2021.
(c) On May 7, 2021, the Company acquired the Barnett Shale assets from Tokyo Gas Americas for $18.3 million, net of preliminary purchase price adjustments. On November 1, 2019, the Company acquired certain mineral interests in the Hamilton Dome field from Merit, who owns the vast majority of the remaining working interest in the field.
Standardized Measure of Discounted Future Net Cash Flows
Future oil and natural gas sales, production, and development costs have been estimated using prices and costs in effect at the end of the years indicated, as required by ASC 932, Extractive Activities - Oil and Gas (“ASC 932”). ASC 932 requires that net cash flow amounts be discounted at 10%. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing our proved oil and natural gas reserves and for asset retirement obligations, assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to our proved oil and natural gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
impact of general and administrative costs of ongoing operations relating to the Company's proved oil and natural gas reserves. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. The table below should not be construed to be an estimate of the current market value of our proved reserves.
The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2021 and 2020 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30,
|
|
2021
|
|
2020
|
Future cash inflows
|
$
|
632,620,246
|
|
|
$
|
399,358,481
|
|
Future production costs and severance taxes
|
(398,021,728)
|
|
|
(240,399,715)
|
|
Future development costs
|
(29,339,399)
|
|
|
(24,623,426)
|
|
Future income tax expenses
|
(42,368,085)
|
|
|
(21,982,469)
|
|
Future net cash flows
|
162,891,034
|
|
|
112,352,871
|
|
10% annual discount for estimated timing of cash flows
|
(75,308,483)
|
|
|
(49,862,035)
|
|
Standardized measure of discounted future net cash flows
|
$
|
87,582,551
|
|
|
$
|
62,490,836
|
|
Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the previous 12 months unweighted arithmetic average first-day-of-the-month commodity prices for each year and reflect adjustments for lease quality, transportation fees, energy content, and regional price differentials.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended June 30,
|
|
2021
|
|
2020
|
|
Oil
(Bbl)
|
|
Gas
(MMBtu)
|
|
Oil
(Bbl)
|
|
Gas
(MMBtu)
|
NYMEX prices used in determining future cash flows
|
$
|
49.72
|
|
|
$
|
2.46
|
|
|
$
|
47.37
|
|
|
n/a
|
There were no natural gas reserves in 2020. The NGL prices utilized for future cash inflows were based on historical prices received, where available. For the Delhi NGL plant, we utilized historical prices for the expected mix and net pricing of natural gas liquid products projected to be produced by the plant.
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil, natural gas, and natural gas liquids reserves is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended June 30,
|
|
2021
|
|
2020
|
Balance, beginning of the fiscal year
|
$
|
62,490,836
|
|
|
$
|
126,732,042
|
|
Net changes in sales prices and production costs related to future production
|
11,538,209
|
|
|
(83,857,342)
|
|
Changes in estimated future development costs
|
403,109
|
|
|
(4,099,792)
|
|
Sales of oil and gas produced during the period, net of production costs
|
(16,115,302)
|
|
|
(16,093,794)
|
|
Net change due to extensions, discoveries, and improved recovery
|
—
|
|
|
—
|
|
Net change due to revisions in quantity estimates
|
6,840,767
|
|
|
(6,746,316)
|
|
Net change due to purchase of minerals in place
|
31,461,405
|
|
|
10,364,875
|
|
Development costs incurred during the period
|
—
|
|
|
1,431,444
|
|
Accretion of discount
|
7,529,289
|
|
|
16,266,663
|
|
Net change in discounted income taxes
|
(10,678,450)
|
|
|
17,078,591
|
|
Net changes in timing of production and other
|
(5,887,312)
|
|
|
1,414,465
|
|
Balance, end of the fiscal year
|
$
|
87,582,551
|
|
|
$
|
62,490,836
|
|
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 21 – Selected Quarterly Financial Data (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
First (a)
|
|
Second (b)
|
|
Third
|
|
Fourth (c)
|
Revenues
|
$
|
5,595,376
|
|
|
$
|
5,768,152
|
|
|
$
|
7,635,748
|
|
|
$
|
13,703,078
|
|
Income (loss) from operations
|
$
|
(9,429,720)
|
|
|
$
|
(15,910,266)
|
|
|
$
|
980,605
|
|
|
$
|
3,000,750
|
|
Net income (loss) attributable to common shareholders
|
$
|
(7,135,148)
|
|
|
$
|
(12,710,007)
|
|
|
$
|
1,191,001
|
|
|
$
|
2,216,220
|
|
Basic earnings (loss) per common share
|
$
|
(0.22)
|
|
|
$
|
(0.38)
|
|
|
$
|
0.04
|
|
|
$
|
0.07
|
|
Diluted earnings (loss) per common share
|
$
|
(0.22)
|
|
|
$
|
(0.38)
|
|
|
$
|
0.04
|
|
|
$
|
0.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
First
|
|
Second
|
|
Third (d)
|
|
Fourth
|
Revenues
|
$
|
9,152,215
|
|
|
$
|
9,381,615
|
|
|
$
|
7,712,619
|
|
|
$
|
3,352,847
|
|
Income (loss) from operations
|
$
|
3,274,019
|
|
|
$
|
2,249,764
|
|
|
$
|
951,814
|
|
|
$
|
(2,786,164)
|
|
Net income (loss) attributable to common shareholders
|
$
|
2,792,820
|
|
|
$
|
1,764,918
|
|
|
$
|
3,710,159
|
|
|
$
|
(2,330,825)
|
|
Basic earnings per common share
|
$
|
0.08
|
|
|
$
|
0.05
|
|
|
$
|
0.11
|
|
|
$
|
(0.07)
|
|
Diluted earnings per common share
|
$
|
0.08
|
|
|
$
|
0.05
|
|
|
$
|
0.11
|
|
|
$
|
(0.07)
|
|
(a) The first quarter of fiscal 2021 included a ceiling test impairment charge of $9.6 million.
(b) The second quarter of fiscal 2021 included a ceiling test impairment charge of $15.2 million.
(c) The fourth quarter of fiscal 2021 includes approximately two months of production and related revenues and expenses from the Barnett Shale assets.
(d) The third quarter of fiscal 2020 was impacted by a $2.8 million tax benefit attributable to the EOR tax credits.
Note 22 – Subsequent Events
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.
On September 9, 2021, the Company declared a quarterly cash dividend of $0.075 per share of common stock to shareholders of record on September 20, 2021 and payable on September 30, 2021.