EVOLUTION PETROLEUM CORP 10-K

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Executive Overview Liquidity and Capital Resources Results of Operations Critical Accounting Policies Executive Overview General Evolution Petroleum Corporation is an oil and natural gas company focused on delivering a sustainable dividend yield to its stockholders through the ownership, management, and development of oil and natural gas properties. In support of that objective, the Company's long-term goal is to build a diversified portfolio of oil and natural gas assets primarily through acquisitions, while seeking opportunities to maintain and increase production through selective development, production enhancements, and other exploitation efforts on its properties. Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO 2 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. 27 Table of Contents Oil & Natural Gas Liquids Reserves (based on SEC NYMEX WTI oil price of $49.72 per barrel) Proved oil equivalent reserves at June 30, 2021 were 23.4 MMBOE, a 129% increase from the previous year primarily due to the acquisition of interests in the Barnett Shale in May 2021. The Standardized Measure for proved reserves increased 40% to $87.6 million, primarily due to the acquisition of interests in the Barnett Shale and an increase in the SEC mandated trailing twelve month average first day of the month net oil price from $46.37 per barrel of oil and $9.00 per barrel of natural gas liquids (we did not have natural gas reserves as of June 30, 2020) at June 30, 2020 to $49.72 per barrel of oil, $19.81 per barrel of natural gas liquids and $2.46 per MMBtu of natural gas at June 30, 2021. Our proved reserves consist of 36% oil, 29% natural gas liquids and 35% natural gas, 92% are classified as proved developed producing and 8% are proved undeveloped. The following table is a summary of our proved reserves as of June 30, 2021 and 2020: Proved Reserves 2021 2020 Change Reserves MMBOE 23.4 10.2 129 % % Developed 92 % 82 % 12 % Liquids % 65 % 100 % (35) % Standardized Measure ($MM) $ 87.6 $ 62.5 40 % Additional property and project information is included under Item 1 and in Note 6 and Note 20 to our consolidated financial statements in Item 8, and in Exhibit 99.1 of this Form 10-K. Delhi Field At June 30, 2021, we had total net proved reserves of 8.5 MMBOE compared to the prior year's 8.7 MMBOE, or a 3% decline in proved oil reserves. Fiscal year 2021 production of 0.5 MMBOE was partially offset by 0.3 MMBOE positive revisions primarily due to price increases. Gross production at Delhi in the fourth quarter of fiscal 2021 was 5.1 MBOEPD, a 2% increase compared to 5.0 MBOEPD in the third fiscal quarter. Oil production was 4.1 MBOPD, which was flat compared to the third fiscal quarter’s 4.1 MBOPD. NGL production in the fourth quarter was 1.0 MBOEPD, an increase of 9% compared to third fiscal quarter's 0.9 MBOEPD. Annual oil production was significantly impacted by cessation of CO 2 purchases when the CO 2 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 CO 2 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 CO 2 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 CO 2 purchase pipeline shut-in for repairs. This decrease together with a 8% lower price per MCF resulted in a 13% decrease in CO 2 cost compared to the prior year. Our cost of purchased CO 2 , the largest 28 Table of Contents 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 CO 2 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 CO 2 recycle facility. The NGL plant is accomplishing its primary objective of removing the lighter, smaller chain hydrocarbons, thereby increasing the purity of the CO 2 recycle stream and improving the efficiency of the CO 2 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. 29 Table of Contents Impact of Geopolitical Factors and the COVID-19 Pandemic On March 11, 2020, the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States of America declared a national emergency with respect to COVID-19. The virus has continued to spread in the United States of America and abroad. National, state, and local authorities 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. 30 Table of Contents The Board of Directors instituted a cash dividend on common stock in December 2013. The Company has since paid 31 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of the Company’s financial strategy, and it is the Company's long-term goal to increase dividends over time, as appropriate. During the industry downturn, effective in the quarter ended June 30, 2020, the Board of Directors adjusted the quarterly dividend rate from $0.10 per share to $0.025 per share. The reduction in the dividend rate at that time allowed the Company to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield of approximately 3% at stock price levels. On February 2, 2021, considering an improving industry outlook, the Board of Directors increased the dividend rate from $0.025 per share to $0.03 per share effective in the quarter ended March 31, 2021. On May 7, the Board of Directors further increased the dividend rate to $0.05 per share effective in the quarter ended June 30, 2021 due to improved industry conditions and the Barnett Shale acquisition. As in the past, the Company intends to consider higher dividend levels as warranted by industry conditions and any future accretive acquisitions. Capital Expenditures For the year ended June 30, 2021, we incurred $21.7 million on capital projects consisting of $21.1 million for the acquisition of Barnett Shale assets (gross of preliminary purchase price adjustments and $2.8 million in non-cash asset retirement obligations) and $0.6 million at the Delhi field (primarily for plugging costs and capital conformance work). Based on discussions with the Delhi and Hamilton Dome operators, we expect to continue to perform conformance workover projects and will likely incur additional maintenance capital expenditures at Delhi and will resume projects at Hamilton Dome. Such amounts are not known or approved but we expect such expenditures to be in the range of $0.9 million to $1.5 million over the next 12 months. In addition, we have planned for Delhi Phase V development expenditures of approximately $1.9 million to be incurred in the fourth quarter of our fiscal 2023. Phase V development expenditures are expected to total $8.6 million with $3.7 million to be incurred in fiscal 2024 and the remainder over the following two years. Our proved undeveloped reserves are associated only with the Delhi field. At June 30, 2021, our proved undeveloped reserves included 1.86 MMBOE of reserves and approximately $8.6 million of future development costs associated with Phase V development in the eastern portion of the Delhi field. Such development requires participation by both the operator and the Company. Although we expect drilling to commence in fiscal 2023, the timing of Phase V is dependent on the field operator's available funds, capital spending plans, and priorities within its portfolio of properties. Funding for our anticipated capital expenditures over the next 24 months is expected to be met from cash flows from operations and current working capital. Full Cost Pool Ceiling Test At June 30, 2021, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling; however, we could experience an impairment if current price levels worsen. Lower oil prices would reduce the excess, or cushion, of our valuation ceiling over our capitalized costs and may adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and natural gas properties will not be required in the future. Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and natural gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test at June 30, 2021 were $49.72 per barrel of oil, $2.46 per MMBtu of natural gas and $19.81 per barrel of natural gas liquids. At December 31, 2020 and September 30, 2020, the Company recorded ceiling test impairment charges of $15.2 million and $9.6 million, respectively. The ceiling test impairments were driven by decreases in the first-day-of-the-month average for oil used in the ceiling test calculation as outlined below. As of June 30, 2021, a 10% decrease in commodity prices used to determine our proved reserves would not have resulted in an impairment of our oil and natural gas properties. Twelve-Month Period Ended: 6/30/2020 9/30/2020 12/31/2020 3/31/2021 6/30/2021 Crude Oil 47.37 43.63 39.54 39.95 49.72 Natural Gas 2.12 2.02 2.03 2.18 2.46 31 Table of Contents 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. June 30, Increases (Decreases) in Cash: 2021 2020 Difference (In Millions) Net cash provided by operating activities $ 4.7 $ 12.4 $ (7.7) Net cash used in investing activities (18.8) (11.1) (7.7) Net cash used in financing activities (0.3) (13.2) 12.9 Change in cash, cash equivalents and restricted cash $ (14.4) $ (11.9) $ (2.5) Cash provided by operating activities in the current year decreased $7.7 million compared to fiscal 2020. The difference is primarily the result of a decrease in revenues compared to the prior year and the payments related to realized hedge settlement losses of $2.5 million. Cash used in investing activities increased $7.7 million primarily due to the acquisition of the Barnett Shale assets in May 2021 for $18.3 million (net of preliminary purchase price adjustments and $2.8 million in non-cash asset retirement obligations) compared to the acquisition of Hamilton Dome field in November 2019 for $9.3 million. The increase is partially offset by a reduction in capital expenditures of $1.3 million in fiscal 2021 due to the decrease in conformance workover activities from lower oil prices. Cash used in financing activities decreased year over year primarily related to the net borrowing of $4 million on the Senior Secured Credit Facility during fiscal 2021, and the reduction in cash paid for cash dividends as the Company paid $4.3 million in fiscal year 2021 and $10.7 million in fiscal year 2020. In addition, the Company paid $2.5 million more in fiscal year 2020 compared to fiscal year 2021 related to the Company's common share repurchase program. Contractual Obligations and Other Commitments The table below provides estimates of the timing of future payments that, as of June 30, 2021, we are obligated to make under our contractual obligations and commitments. We expect to fund these contractual obligations with cash on hand and cash generated from operations. Payments Due by Period Total Less than 1 Year 1 - 3 Years 3 - 5 Years More than 5 Years Contractual Obligations AFE purchase commitments in connection with joint interest agreements $ 329,827 $ 329,827 $ — $ — $ — Operating lease $ 84,978 59,103 25,875 — — Asset retirement obligations $ 5,583,272 $ 44,520 $ 168,377 $ 158,378 $ 5,211,997 Total Obligations $ 5,998,077 $ 433,450 $ 194,252 $ 158,378 $ 5,211,997 32 Table of Contents Results of Operations Years Ended June 30, 2021 and 2020 Revenues The following table summarizes total production volumes, daily production volumes, average realized prices and revenues for the years ended June 30, 2021 and 2020. Fiscal 2020 includes eight months of Hamilton Dome production. Fiscal 2021 includes approximately two months of Barnett Shale production. Years Ended June 30, 2021 2020 Variance Variance % Oil and gas production Revenues Oil $ 26,411,132 $ 28,578,879 $ (2,167,747) (7.6) % Natural gas liquids 3,662,478 1,018,349 2,644,129 259.6 % Natural gas 2,628,744 2,068 2,626,676 n.m. Total revenues $ 32,702,354 $ 29,599,296 $ 3,103,058 10.5 % Volumes Oil (Bbl) 554,888 638,464 (83,576) (13.1) % Natural gas liquids (Bbl) 171,451 106,159 65,292 61.5 % Natural gas (Mcf) 963,496 1,087 962,409 n.m. Equivalent volumes (BOE) 886,922 744,804 142,118 19.1 % Oil (BOPD, net) 1,520 1,744 (224) (12.8) % NGLs (BOEPD, net) 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 CO 2 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 CO 2 is necessary to maintain reservoir pressure and therefore achieve normal field performance. The shut-in of purchased CO 2 volumes resulted in a decline in reservoir pressure and a temporary exacerbated production decline. The resumption of CO 2 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. 33 Table of Contents (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) CO 2 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 % CO 2 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 % CO 2 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 CO 2 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 % CO 2 costs per mcf $ 0.71 $ 0.77 $ (0.06) (7.8) % CO 2 volumes (MMcf per day, gross) 49.1 51.9 (2.8) (5.4) % The $0.4 million decrease in CO 2 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 CO 2 to the Delhi field was shut-in on February 22, 2020, when a pressure loss was detected. CO 2 purchases were suspended until October 2020 for pipeline repairs. CO 2 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. 34 Table of Contents 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. 35 Table of Contents 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) % 36 Table of Contents Critical Accounting Policies and Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our consolidated financial statements. Our significant accounting policies are included in Note 2 to our consolidated statements in Item 8. Following is a discussion of our most critical accounting estimates, judgments, and uncertainties that are inherent in the preparation of our consolidated financial statements. Oil and Natural Gas Properties . Companies engaged in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and 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. 37 Table of Contents 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.