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 independent energy company focused on maximizing total returns to its shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States. In support of that objective, our long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisitions and through selective development opportunities, production enhancements, and other exploitation efforts on our oil and natural gas properties.
Our oil and natural gas properties consist of non-operated interests in the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO2 enhanced oil recovery (“EOR”) project; non-operated interests in the Hamilton Dome Field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir; non-operated interests in the Barnett Shale located in North Texas, a natural gas producing property; non-operated interests in the Williston Basin in North Dakota, a producing oil and natural gas property; non-operated interests in the Jonah Field in Sublette County, Wyoming, a natural gas producing field; and small overriding royalty interests in four onshore central Texas wells.
Our non-operated interests in the Delhi Field, a CO2-EOR project, consist of approximately 24% average net working interest, with an associated 19% revenue interest and separate overriding royalty and mineral interests of approximately 7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC (“Denbury”). The Delhi Field is located in northeast Louisiana in Franklin, Madison, and Richland Parishes and encompasses approximately 14,000 gross unitized acres, or approximately 3,200 net acres.
Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to pressurize the reservoir, consists of approximately 24% average net working interest, with an associated 20% average net revenue interest (inclusive of a small overriding royalty interest). The approximately 5,900 gross acre unitized field, of which we hold approximately 1,400 net acres, is operated by Merit Energy Company (“Merit”), who owns the vast majority of the remaining working interest in the Hamilton Dome Field. The Hamilton Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming.
Our non-operated interests in the Barnett Shale, a natural gas producing shale reservoir, consists of approximately 17% average net working interest with an associated 14% average net revenue interest (inclusive of small overriding royalty interests). The approximately 21,000 net acres are held by production across nine North Texas counties. The oil and natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by seven other operators.
On January 14, 2022, we acquired non-operated working interests in 73 producing wells in the Williston Basin with an average net working interest of approximately 39% and average net revenue interest of approximately 33% located on approximately 45,000 net acres (approximately 90% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota (the “Williston Basin Acquisition”). After taking into account customary closing adjustments and an effective date of June 1, 2021, cash consideration was $25.2 million which includes $0.3 million of transaction costs related to the acquisition. The properties are operated by Foundation Energy Management (“Foundation”), an established operator in the geographic region.
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On April 1, 2022, we acquired non-operated working interests in the Jonah Field in Sublette County, Wyoming (the “Jonah Field Acquisition”). After taking into account the deposit on the acquisition, customary closing adjustments and an effective date of February 1, 2022, cash consideration at closing was $26.4 million (including $0.2 million of transaction costs). The acquired properties include an average net working interest of approximately 20% and an average net revenue interest of approximately 15% in 595 producing wells and 950 net acres. The properties are operated by Jonah (“Jonah”), an established operator in the geographic region.
Recent Developments
Dividend Declaration and Share Repurchase Program
On September 12, 2022, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common share payable September 30, 2022. This represents a 20% increase over the $0.10 per common share dividend paid in the fourth quarter of fiscal year 2022. Also, on September 8, 2022, the Board of Directors authorized a share repurchase program, under which we are approved to repurchase up to $25 million of our common stock through December 31, 2024. We intend to fund repurchases from available working capital and cash provided by operating activities. As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors along with the management team believe that a share repurchase program is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the intrinsic value of our shares, the market price of our common stock, general market and economic conditions, and applicable legal requirements. The value of shares authorized for repurchase by our Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the program may be suspended, modified, or discontinued at any time without prior notice.
Highlights for our Fiscal Year 2022 and Operations Update
● Generated revenue of $108.9 million and net income of $32.6 million.
● Production averaged 5,953 net BOEPD.
● Maintained a strong financial position with low leverage.
Proved Reserves
Proved oil equivalent reserves as of June 30, 2022 were 36.2 MMBOE, a 55% increase from the previous year primarily due to the acquisitions of properties in the Williston Basin and Jonah Field in January 2022 and April 2022, respectively. The Standardized Measure for proved reserves increased 259% to $314.8 million, primarily due to the acquisitions of
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properties in the Williston Basin and Jonah Field and an increase in the SEC mandated trailing 12-month average first day of the month prices for oil and natural gas. Prices increased from $49.72 per barrel of oil, $2.46 per MMBtu of natural gas and $19.81 per barrel of NGLs at June 30, 2021 to $85.82 per barrel of oil, $5.19 per MMBtu of natural gas and $44.24 per barrel of NGLs at June 30, 2022. Our proved reserves consist of 32% oil, 49% natural gas, and 19% NGLs; 90% are classified as proved developed producing and 10% are proved undeveloped.
The following table is a summary of our proved reserves as of June 30, 2022 and 2021:
Proved Reserves
Reserves MMBOE 36.2 23.4 55 %
% Developed 90 % 92 % (2) %
Liquids % 51 % 65 % (14) %
Standardized Measure ($MM) $ 314.8 $ 87.6 259 %
Additional property and project information is included under Item 1. Business and in Note 5, “Property and Equipment” and our Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data, and in Exhibit 99.1 and 99.2 of this Form 10-K.
At June 30, 2022, we had total net proved reserves of 36.2 MMBOE, a 12.8 MMBOE increase from the previous year of 23.4 MMBOE. The net increase in total proved reserves was the result of acquisitions of 9.3 MMBOE, additions and extensions of 3.6 MMBOE and net positive revisions of 2.1 MMBOE, partially offset by production of 2.2 MMBOE. Net positive revisions of 2.1 MMBOE increased primarily due to improvement in SEC trailing 12-month pricing partially offset by the removal of 1.8 MMBOE of PUDs related to Test Site V and 0.7 MMBOE of PDP at our Delhi Field property.
Impact of the COVID-19 Pandemic and Geopolitical factors
The global economy has been deeply impacted by the effects of the novel coronavirus (“COVID-19”) pandemic and related efforts to mitigate the spread of the disease. These events led to crude oil prices falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020.
In 2021, the demand for oil and natural gas began to recover primarily as a result of the roll-out of the COVID-19 vaccine and lessening of pandemic related government restrictions on individuals and businesses. In addition, the recent special military operation of Russia into Ukraine and the subsequent sanctions imposed on Russia and other actions have created significant market uncertainties, including uncertainties around potential supply disruptions for oil and natural gas, which has further enhanced volatility in global commodity prices in the first half of 2022. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist.
Currently, none of our oil and natural gas properties are operated by us. As a result, in the past we have had limited ability to influence or control the operation or future development of such properties. Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-party operators to review capital expenditures and alter plans as appropriate to increase shareholder value.
Liquidity and Capital Resources
As of June 30, 2022, we had $8.3 million in cash and cash equivalents compared to $5.3 million at June 30, 2021. Our primary sources of liquidity and capital resources during the year ended June 30, 2022 were cash provided by operations as well as net borrowings under our Senior Secured Credit Facility. Our primary uses of liquidity and capital resources for the year ended June 30, 2022 were acquisitions of oil and natural gas properties and cash dividend payments to our common stockholders. As of June 30, 2022, working capital was $6.1 million, a decrease of $5.4 million from working capital of $11.5 million as of June 30, 2021.
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The Senior Secured Credit Facility has a maximum capacity of $50.0 million subject to a borrowing base determined by the lender based on the value of our oil and natural gas properties. The Senior Secured Credit Facility has a current borrowing base of $50.0 million, with $21.3 million drawn as of June 30, 2022. Since year-end, we have paid down another $9.0 million under our Senior Secured Credit Facility and as of August 31, 2022, we have $12.3 million outstanding. The Senior Secured Credit Facility is secured by substantially all of our reserves associated with our oil and natural gas properties and matures on April 9, 2024.
Any future borrowings bear interest, at our option, at either the London Interbank Offered Rate (“LIBOR”) plus 2.75% or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.0%. The Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. It also contains other customary affirmative and negative covenants and events of default. As of June 30, 2022, we were in compliance with all covenants under the Senior Secured Credit Facility.
We are currently working on our annual redetermination with MidFirst Bank. We expect that our borrowing base will remain at $50.0 million and the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, will be set at $125.0 million. We are required to enter into hedges on a rolling 12-month basis when the borrowings under the Senior Secured Credit Facility exceed 25% of the Margined Collateral Value. Based on the current amount outstanding, the utilization percentage under the required hedging covenant is below the minimum utilization threshold of 25% and as a result we are not required to enter into additional hedges at this time. At each redetermination, our Margined Collateral Value takes into account the estimated value of our oil and natural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria.
On February 7, 2022, we entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as defined in the agreement, to the extent it exceeds the borrowing base then in effect. This amendment also required us to enter into hedges for the next 12-month period ending February 2023, covering 25% of expected oil and natural gas production over that period.
On November 9, 2021, we entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby we must hedge a certain amount of our future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in the Ninth Amendment, as discussed above.
On August 5, 2021, we entered into the Seventh Amendment of our Senior Secured Credit Facility which, among other things, added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the consolidated tangible net worth covenant level was reduced to $40.0 million from $50.0 million.
We have historically funded operations through cash from operations and working capital. The primary source of cash is the sale of produced crude oil, natural gas, and NGLs. A portion of these cash flows is used to fund capital expenditures and pay cash dividends to shareholders. We expect to manage near-future development activities for our properties with cash flows from operating activities and existing working capital.
We are pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, we have access to the undrawn portion of the borrowing base available under our Senior Secured Credit Facility. We also have an effective shelf registration statement with the SEC under which we may issue up to $500.0 million of new debt or equity securities.
The Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 35 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 our financial strategy, and it is our long-term goal to increase
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dividends over time, as appropriate. During the industry downturn primarily due to COVID-19, 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 us to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield of approximately 3% at the then current stock price levels. In light of our improving financial performance and industry outlook, the Board of Directors has since increased the dividend rate, with the most recent increase occurring on September 12, 2022, when the Board of Directors declared a dividend of $0.12 per share payable on September 30, 2022.
Also, on September 8, 2022, our Board of Directors authorized a share repurchase program, under which we are approved to repurchase up to $25 million of our common stock through December 31, 2024. We intend to fund any repurchases from working capital and cash provided by operating activities. As we continue to focus on our goal of maximizing total shareholder return, the Board of Directors along with the management team believe that a share repurchase program is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder return. Refer to Note 15, “Subsequent Events,” for a further discussion of our share repurchase program.
Capital Expenditures
For the year ended June 30, 2022, we incurred $2.6 million on development capital expenditures, $26.4 million for the Jonah Field Acquisition (net of customary purchase price adjustments, excluding $3.0 million in non-cash asset retirement obligations), and $25.2 million for the Williston Basin Acquisition (net of customary purchase price adjustments, excluding $2.4 million in non-cash asset retirement obligations) and less than $0.1 million at the Delhi Field and Hamilton Dome Field, for plugging and abandoning costs.
Based on discussions with our operators, we expect capital workover projects to continue in all the fields. At Delhi Field, we anticipate capital costs for a NGL plant heat exchanger project which is currently underway. Overall, for fiscal year 2023, we expect budgeted capital expenditures to be in the range of $6.5 million to $9.5 million, which excludes any potential acquisitions. Our expected capital expenditures for the next 12 months include Foundation, the operator of our Williston Basin properties, drilling two sidetrack locations targeting the Birdbear formation. Our fiscal year 2023 budget does not include any capital expenditures for drilling at our Pronghorn and Three Forks locations.
As of June 30, 2022, our PUD reserves included 3.6 MMBOE of reserves and approximately $61.7 million of future development costs associated with the Williston Basin properties.
Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations and current working capital, as well as borrowings under our Senior Secured Credit Facility as needed for future acquisitions or development of PUD reserves at our Pronghorn and Three Forks locations.
Full Cost Pool Ceiling Test
As of June 30, 2022, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling; however, we could experience an impairment if commodity price levels were to substantially decline. Lower commodity 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 depletion, depreciation, and amortization 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 as of June 30, 2022 were $85.82 per barrel of oil, $5.19 per MMBtu of natural gas and $44.24 per barrel of NGLs. At December 31, 2020 and September 30, 2020, we 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 price for oil used in the ceiling test calculation. At June 30, 2022, a 10% decrease in commodity
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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:
Overview of Cash Flow Activities
Years Ended June 30,
Cash flows provided by operating activities $ 52,460 $ 4,733 $ 47,727
Cash flows used in investing activities (54,873) (18,769) (36,104)
Cash provided by operating activities increased $47.7 million during the fiscal year ended June 30, 2022 compared to fiscal year ended June 30, 2021 primarily due to an increased average daily production and an approximate $13.26 per BOE average realized price increase which both contributed to higher revenues in fiscal year 2022.
Cash used in investing activities increased $36.1 million primarily due to the acquisition of the Jonah Field properties in April 2022 totaling $26.4 million (net of customary purchase price adjustments) and Williston Basin properties in January 2022 totaling $25.8 million (net of customary purchase price adjustments), compared to the acquisition of the Barnett Shale properties in May 2021 for $18.3 million (net of customary purchase price adjustments). In addition, capital expenditures increased $1.0 million in fiscal year 2022 due to increased capital workovers for certain return-to-production projects now viable with the increase in commodity prices.
Net cash flows provided by financing activities were $5.4 million for the year ended June 30, 2022, compared to $0.3 million of net cash flows used in financing activities for the year ended June 30, 2021. As of June 30, 2021, we had borrowings of $4.0 million outstanding under our Senior Secured Credit Facility. During the year ended June 30, 2022, we increased these borrowings by a net $17.3 million, ending the year with $21.3 million outstanding under the Senior Secured Credit Facility. In fiscal year 2022, we used cash of $11.8 million for dividends paid to our common stockholders compared to $4.3 million in fiscal year 2021.
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Results of Operations
Years Ended June 30, 2022 and 2021
We reported net income of $32.6 million for the year ended June 30, 2022 compared to a net loss of $16.4 million for the year ended June 30, 2021. The following table summarizes the comparison of financial information for the periods presented:
Years Ended June 30,
Revenues:
Operating costs:
Lease operating costs:
Depletion, depreciation, and amortization:
Depreciation of other property and equipment 4 7 (3) (42.9) %
Amortization of intangibles — 47 (47) (100.0) %
Accretion of asset retirement obligations 531 210 321 152.9 %
Impairment of proved property — 24,792 (24,792) (100.0) %
General and administrative:
Other Income (expenses):
Interest and other income 95 40 55 137.5 %
Production:
Average price per unit(2):
Average cost per unit:
Operating costs:
Lease operating costs:
Ad valorem and production taxes 3.20 1.44 1.76 122.2 %
General and administrative:
General and administrative 3.09 6.20 (3.11) (50.2) %
Stock-based compensation 0.06 1.42 (1.36) (95.8) %
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Revenues
Fiscal year ended June 30, 2022 revenues increased 233.1% to $108.9 million compared to $32.7 million for the fiscal year ended June 30, 2021. The increase in revenue is primarily due to a 145% increase in average daily equivalent production from 2,430 BOEPD to 5,953 BOEPD due the addition of the Jonah Field Acquisition in April 2022, Williston Basin Acquisition in January 2022, and Barnett Shale Acquisition in May 2021, which increased current fiscal year production by approximately 518 BOEPD, 241 BOEPD, and 2,847 BOEPD, respectively. In addition, our average realized commodity prices (excluding the impact of derivative contracts) increased approximately $13.26 per BOE, or 36%, for the fiscal year ended June 30, 2022 compared to June 30, 2021. Oil and natural gas prices are inherently volatile and began to stabilize in 2021 and continuing into 2022. Our average realized oil price was higher primarily due to the recovery of WTI pricing in 2022, as the demand for oil has begun to recover primarily as a result of the roll-out of the COVID -19 vaccines, lessening of pandemic related government restrictions on individuals and businesses, and sanctions affecting Russian oil and natural gas supplies.
Lease Operating Costs
The following table summarizes CO2 costs per Mcf and CO2 volumes for the years ended June 30, 2022 and 2021. CO2 purchase costs are for the Delhi Field. Under our contract with the Delhi Field operator, purchased CO2 is priced at 1% of the realized oil price in the field per Mcf, plus sales taxes and transportation costs as per contract terms.
Years Ended June 30,
CO2 volumes (MMCF per day, gross) 82.6 49.1 33.5 68.2 %
The $4.6 million increase in CO2 costs for the fiscal year ended June 30, 2022 was primarily due to a 68.2% increase in purchased CO2 volumes combined with a 50.7% increase in CO2 costs per MCF, which was driven by a 78.8% increase in our average realized oil price. The increase in purchased CO2 volumes is due to the completion of preventative maintenance on the pipeline that supplies newly purchased CO2 to the Delhi Field which resulted in temporary suspension of CO2 purchases for the three months ended September 30, 2021. Additionally, CO2 purchase nominations increased throughout fiscal year 2022 to compensate for reduced reservoir pressure. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. The pipeline is owned and operated by Denbury and we do not have any ownership in the pipeline. On a per unit basis, CO2 costs were $3.55 per BOE and $3.45 per BOE for the years ended June 30, 2022 and 2021, respectively.
Ad valorem and production taxes were $7.0 million and $1.3 million for the years ended June 30, 2022 and 2021, respectively. On a per unit basis, ad valorem and production taxes were $3.20 per BOE and $1.44 per BOE for the years ended June 30, 2022 and 2021, respectively. The increase in ad valorem and production taxes is primarily due to increases in oil and natural gas prices and increased production volumes described above as production taxes are based on sales at the wellhead.
Compared to fiscal year ended June 30, 2021, other lease operating costs increased 177.6% primarily due to the Jonah Field Acquisition in April 2022, Williston Basin Acquisition in January 2022 and Barnett Shale Acquisition in May 2021. Other lease operating costs per BOE for our Jonah Field, Williston Basin and Barnett Shale properties were approximately $10.69 per BOE, $21.86 per BOE and $14.70 per BOE, respectively, for the years ended June 30, 2022. Other lease operating costs for the Delhi and Hamilton Dome fields increased $0.8 million and $0.9 million, respectively, due to higher labor, electricity and chemical expenses during the year ended June 30, 2022.
Depletion expense increased $2.6 million or 53.3% from $4.9 million for the fiscal year ended June 30, 2021 to $7.5 million for the fiscal year ended June 30, 2022 primarily due to an increase in production. On a per unit basis, depletion expense was $3.46 per BOE and $5.53 per BOE for the fiscal years ended June 30, 2022 and 2021, respectively. The integration of the Jonah Field properties in April 2022, Williston Basin properties in January 2022, and Barnett Shale properties in May 2021 together with the ceiling test impairments recorded during the fiscal year ended June 30, 2021 contributed to the overall lower composite depletion per BOE rate for the year ended June 30, 2022.
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Impairment of Proved Property
We utilize the full cost method of accounting for our oil and natural gas properties under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion, depreciation, and amortization 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 included in the amortization base, plus the cost of unproved properties excluded from amortization, as adjusted for related income tax effects (the valuation “ceiling”). As of June 30, 2022, our net book value of oil and natural gas properties did not exceed the current ceiling. During the fiscal year ended June 30, 2021, we recorded a proved property impairment of $24.8 million primarily as a result of the decline in the price of oil over the historical 12-month period.
Impairment of Well Lift Inc. - Related Expenses
Our royalty rights and investment in Well Lift, Inc. (“WLI”) resulted from the separation of our artificial lift technology operations in December 2015. We conveyed our patents and other intellectual property to WLI and retained a 5% royalty on future gross revenues associated with the technology. We own approximately 18% 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. We evaluate the investment for impairment when we identify any events or changes in circumstances that might have a significant adverse effect on the fair value of the investment. As of March 31, 2021, we reviewed our investment 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 level of activity associated with this technology.
General and Administrative Expenses
General and administrative expenses for the fiscal year ended June 30, 2022 increased $1.2 million, or 22.1%, to $6.7 million compared to $5.5 million for the fiscal year ended June 30, 2021. The increase is primarily due to approximately $0.2 million for salary and employee benefits due to additional personnel, $0.3 million in severance, $0.2 million for professional fees related to increased accounting services as a result of the Jonah Field Acquisition, the Williston Basin Acquisition and the Barnett Shale Acquisition, and $0.3 million for increased business development activity. On a per unit basis, general and administrative expenses decreased $3.11 per BOE to $3.09 per BOE for the year ended June 30, 2022 from $6.20 per BOE for the prior year. The decrease in general and administrative expenses on a per unit basis are due to the increased production volumes described above.
Stock-based Compensation Expenses
Stock-based compensation decreased $1.1 million, or 90%, to $0.1 million for the year ended June 30, 2022 compared to $1.3 million the prior period due to a $1.2 million reduction in current period expense related to the forfeiture of unvested shares in connection with severance.
Net Gain (Loss) on Derivative Contracts
Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural gas prices. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we recorded the net change in the mark-to-market valuation of the derivative contracts in the consolidated statements of operations. The amounts recorded on the consolidated statements of operations related to derivative contracts represent the (i) gains (losses) 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. The table below summarizes our net realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our average realized prices for the periods presented. As a result of the Williston Basin Acquisition in January 2022 and Jonah Field Acquisition in April 2022, we were required by the terms of our Senior Secured Credit Facility to hedge a portion of our production. The increase in commodity prices since entering into the hedges resulted in a realized loss on hedges for the year ended June 30, 2022 and an unrealized loss due to the mark-to-market value of
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remaining hedges. Certain of our hedges begin to expire in October 2022 with our final hedges expiring March 2023. As of June 30, 2022, we had a $0.2 million derivative asset all of which was classified as current, and a $2.2 million derivative liability, all of which was classified as current.
Years Ended June 30,
Average realized crude oil price per Bbl $ 85.11 $ 47.59 $ 37.52 78.8 %
Average realized natural gas price per Mcf $ 5.49 $ 2.73 $ 2.76 101.1 %
Interest Expense
Interest expense increased $0.5 million during the fiscal year ended June 30, 2022 compared to fiscal year 2021 primarily due to the increased borrowings outstanding on our Senior Secured Credit Facility due to our acquisitions throughout the year.
Income tax (expense) provision
For the year ended June 30, 2022, we recognized income tax expense of $8.5 million on net income before income taxes of $41.1 million compared to an income tax benefit of $5.0 million on net loss before income taxes of $21.4 million for the year ended June 30, 2021.
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 1, “Summary of Significant Events and Accounting Policies” 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, 2022, 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.
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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, 2022 would not have resulted in an impairment of our oil and natural gas properties. Holding all other factors constant, a reduction our proved reserve estimates at June 30, 2022 of 10% would affect depletion, depreciation, and amortization expense by approximately $0.4 million.
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 forecasted 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. The deferred tax asset and valuation allowance of $0.1 million related to the portion of the NOLs that are limited by IRC Section 382 were written off during the year ended June 30, 2022.
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 has historically established 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 not 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 7, “Income Taxes”.
Stock-based Compensation. The fair value, and for certain awards the expected vesting period, of our performance-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 our 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 performance-based awards is based on our total common stock return compared to a peer
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group of other companies in our industry with comparable market capitalizations and, for certain awards, our share price attaining a set target.
Recent Accounting Pronouncements. Refer to Note 1, “Summary of Significant Events and Accounting Policies” to our consolidated financial statements in Item 8. Financial Statements and Supplementary Data for discussion of the recent accounting pronouncements issued by the Financial Accounting Standards Board.
Item 7A. Quantitative and Qualitative Disclosures About Market Risks
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 and natural gas prices. We do not enter into derivative contracts for speculative trading purposes.
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 2022 and 2021, we did not post collateral. 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 8, “Derivatives” to our consolidated financial statements for more details.
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.
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Item 8. Consolidated Financial Statements and Supplementary Data
Index to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 659) 43
Consolidated Balance Sheets as of June 30, 2022 and 2021 46
Notes to Consolidated Financial Statements 50
Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) 72
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
Evolution Petroleum Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Evolution Petroleum Corporation and subsidiaries (the “Company”) as of June 30, 2022 and 2021, 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, 2022 and 2021, 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 Depletion, Depreciation and Amortization (“DD&A”) and Full Cost Ceiling Test Impairment Calculation (“Ceiling Test”)
As described in Note 1, 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
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guidelines. For the year ended June 30, 2022, the Company recorded DD&A related to its proved oil and natural gas properties of approximately $7.5 million, and there was no ceiling test impairment.
The Company engages two independent reservoir engineering firms, to serve as a management specialist and 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 specialists 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:
o Testing the data inputs used by specialist for completeness and accuracy;
o Testing the specialist’s findings for mathematical accuracy; and,
◾ prices to historical benchmark prices, adjusted for pricing differentials,
◾ production forecasts to recent historical actual production,
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Testing the accuracy of the Company’s depletion and impairment calculations that included these proved reserves.
/s/ Moss Adams LLP
Houston, Texas
We have served as the Company’s auditor since 2017.
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EVOLUTION PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
Assets
Current assets
Cash and cash equivalents $ 8,280 $ 5,277
Receivables for federal and state income tax refunds — 3,108
Derivative contract assets 170 —
Prepaid expenses and other current assets 3,838 1,036
which none were excluded from amortization 110,508 58,516
Other property and equipment, net — 11
Total property and equipment, net 110,508 58,527
Other assets, net 1,171 71
Liabilities and Stockholders' Equity
Current liabilities
Accrued liabilities and other 11,893 4,943
Derivative contract liabilities 2,164 —
State and federal taxes payable 1,095 38
Total current liabilities 30,285 6,594
Long term liabilities
Senior secured credit facility 21,250 4,000
Deferred income taxes 7,099 5,957
Asset retirement obligations 13,899 5,539
Operating lease liability — 21
Commitments and contingencies (Note 11)
Stockholders' equity
respectively 33 34
Total liabilities and stockholders' equity $ 148,047 $ 76,706
See accompanying notes to consolidated financial statements.
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EVOLUTION PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
Years Ended June 30,
Revenues
Operating costs
Depletion, depreciation, and amortization 8,053 5,167
Impairment of proved property — 24,792
Impairment of Well Lift Inc. - related assets — 146
General and administrative expenses 6,835 6,754
Income (loss) from operations 45,381 (20,744)
Other income and expenses
Net gain (loss) on derivative contracts (3,763) (615)
Interest and other income 95 40
Interest expense (572) (103)
Income (loss) before income taxes 41,141 (21,422)
Income tax (expense) benefit (8,513) 4,984
Earnings (loss) per common share:
Weighted average number of common shares outstanding
See accompanying notes to consolidated financial statements.
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EVOLUTION PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Years Ended June 30,
Cash flows from operating activities:
Depletion, depreciation, and amortization 8,053 5,167
Impairment of proved property — 24,792
Impairment of Well Lift Inc. - related assets — 146
Stock-based compensation 125 1,258
Settlement of asset retirement obligations — (101)
Deferred income taxes 1,142 (5,104)
Unrealized loss on derivative contracts 1,994 615
Accrued settlements on derivative contracts 919 (2,791)
Other (10) 10
Changes in operating assets and liabilities:
Prepaid expenses and other current assets (538) (546)
Accounts payable and accrued expenses 18,516 4,498
State and federal income taxes payable 1,058 (141)
Net cash provided by operating activities 52,460 4,733
Cash flows from investing activities:
Acquisition of oil and natural gas properties (53,342) (18,297)
Capital expenditures for oil and natural gas properties (1,531) (472)
Net cash used in investing activities (54,873) (18,769)
Cash flows from financing activities:
Common stock dividends paid (11,796) (4,342)
Borrowings under credit facility 34,000 7,000
Repayments of credit facility (16,750) (3,000)
Net cash provided by (used in) financing activities 5,416 (349)
Net increase (decrease) in cash and cash equivalents 3,003 (14,385)
Cash and cash equivalents, beginning of year 5,277 19,662
Cash and cash equivalents, end of year $ 8,280 $ 5,277
Supplemental disclosures of cash flow information:
Cash paid for interest on Senior secured credit facility $ 523 $ 86
Cash paid for income taxes 6,294 758
Cash received from income tax refunds 3,223 142
Non-cash investing and financing transactions:
See accompanying notes to consolidated financial statements.
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EVOLUTION PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(In thousands)
Additional Total
Common Stock Paid-in Retained Treasury Stockholders'
Shares Par Value Capital Earnings Stock Equity
Issuance of restricted common stock 561 1 (1) — — —
Retirements of treasury stock (3) — (7) — 7 —
Stock-based compensation — — 1,258 — — 1,258
Net income (loss) — — — (16,438) — (16,438)
Common stock dividends paid — — — (4,342) — (4,342)
Issuance of restricted common stock 336 — — — — —
Forfeitures of restricted stock (373) (1) 1 — — —
Retirements of treasury stock (7) — (38) — 38 —
Stock-based compensation — — 125 — — 125
Net income (loss) — — — 32,628 — 32,628
Common stock dividends paid — — — (11,796) — (11,796)
See accompanying notes to consolidated financial statements.
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Events and Accounting Policies
Nature of Operations. Evolution Petroleum Corporation is an independent energy company focused on maximizing returns to stockholders through the ownership of and investment in onshore oil and natural gas properties in the United States. The Company’s long-term goal is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through acquisitions and through selective development, production enhancement, and other exploitation efforts on its oil and natural gas properties.
The Company’s producing properties consist of non-operated interests in the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO2 enhanced oil recovery (“EOR”) project; non-operated interests in the Hamilton Dome Field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir; non-operated interests in the Barnett Shale located in North Texas, a natural gas producing property; non-operated interests in the Williston Basin in North Dakota, a producing oil and natural gas reservoir; non-operated interests in the Jonah Field in Sublette County, Wyoming; and small overriding royalty interests in four onshore Texas wells.
Principles of Consolidation and Reporting. The 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. To conform with the current year presentation, “Accrued payables” disclosed in Footnote 14, “Additional Financial Information” is included with “Accrued liabilitiesand other” instead of “Accounts Payable” at June 30, 2021 on the consolidated balance sheets and “Net gain (loss) on derivative contracts” is included with “Other income and expenses” instead of “Total operating costs” for the year ended June 30, 2021 on the consolidated statements of operations. These reclassifications have no impact on previously reported net income or stockholders’ equity.
Risk and Uncertainties. None of the Company’s ownership interests are operated by the Company and involve other third-party working interest owners. As a result, the Company has a limited ability to influence or control the operation or future development of such properties. However, the Company is proactive with its third-party operators to review spending and alter plans as appropriate.
Use of Estimates. The preparation of financial statements in conformity with accounting principles generally acceptable in the United States requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective 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) accruals of crude oil, natural gas, and natural gas liquids (“NGL”) revenues and expenses. The Company analyzes estimates and judgements based on historical experience and various other assumptions and information that are believed to be reasonable. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as additional information is obtained, as new events occur, and as the Company’s environment changes. Actual results may differ from the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.
Cash and Cash Equivalents. The Company considers all highly liquid investments, with original maturities of 90 days or less when purchased, to be cash and cash equivalents.
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. The Company establishes 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
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2022 and 2021, no allowance for doubtful accounts was considered necessary.
Oil and Natural Gas Properties. The Company uses the full-cost method of accounting for its 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.
The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of depletion, 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.
The capitalized costs of the Company’s oil and natural gas properties, net of accumulated amortization and related deferred income taxes are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%, net of tax considerations. Any excess over the full cost ceiling limitation is charged to expense as an impairment and is reflected as additional accumulated depletion, depreciation, and amortization or as a credit to oil and natural gas properties.
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, 2022 and 2021, the Company did not have any costs excluded from depletion and amortization.
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. Repair and maintenance costs are expensed in the period incurred.
Asset Retirement Obligations. An asset retirement obligation (“ARO”) 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, the Company’s 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 the Company’s 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. The Company’s 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
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Senior Secured Credit Facility, as defined in Note 6, “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.
Concentrations of Credit Risk. The Company’s primary concentrations of credit risk are the risks of uncollectible accounts receivable, and to a lesser extent, the non-performance by counterparties under the Company’s derivative contracts, and cash and cash equivalent balances in excess of limits federally insured by the Federal Deposit Insurance Corporation.
Substantially all of the Company’s accounts receivable as of June 30, 2022 is from crude oil, natural gas, and NGL sales to third-party purchasers in the oil and natural gas industry. The Company holds working interests in crude oil and natural gas properties for which a third-party serves as operator. As a non-operator, the Company primarily markets its production through its field operators, except at the Jonah Field, where the Company takes its natural gas and NGL production in-kind. As a non-operator, the Company is highly dependent on the success of its third-party operators and the decisions made in connection with their operations. The third-party operator sells the crude oil, natural gas, and NGLs to the purchaser, collects the cash, and distributes the cash to the Company. In the years ended June 30, 2022 and 2021, three operators each distributed over 10% of the Company’s crude oil, natural gas and natural gas liquids revenues making up approximately 83% and 100% of total revenues for the years, respectively. The majority of the Company’s crude oil, natural gas, and NGL production is sold to purchasers under short-term (less than 12 months) contracts at market-based prices.
Derivative Instruments. The Company follows Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging (“ASC 815”). From time to time, in accordance with the Company’s policy and the covenants under the Senior Secured Credit Facility, it may hedge a portion of its forecasted crude oil, natural gas, and NGL 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”); 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 contracts” on the consolidated statements of operations.
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 the Company’s 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 the Company’s financial statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect the Company’s estimated future net cash flows of its proved reserves. These changes could affect the Company’s quarterly ceiling test calculation and could significantly affect its depletion rate.
Income Taxes. The Company recognizes deferred tax assets and liabilities based on the differences between the tax basis of assets and liabilities and its 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
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
assets will not be realizable. The Company recognizes 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. The Company records 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. The Company grants restricted stock awards which entitle the recipient to all of the rights of a shareholder of the Company including non-forfeitable rights to receive all dividends or other distributions paid with respect to such share; therefore, it applies the two-class method of calculating basic and diluted earnings (loss) per share (“EPS”) in accordance with ASC 260, Earnings Per Share (“ASC 260”). Basic EPS is computed by dividing earnings or loss available to common stockholders, after allocating undistributed earnings to participating securities, 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. Unvested performance-based restricted stock awards and unvested contingent restricted share units are only potentially dilutive if the awards meet their respective performance criteria as of the period end. The Company uses the treasury stock method to determine the effect of potentially dilutive common shares on diluted EPS, unless the effect would be anti-dilutive. The unamortized stock-based compensation expense related to unvested awards is assumed to be used to repurchase shares of 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. Awards with performance-based vesting restrictions are 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.
Correction of Immaterial Error
The Company has identified an issue related to its historical process of calculating the Company’s EPS. The Company grants restricted stock awards which entitle the recipient to all of the rights of a shareholder of the Company including non-forfeitable rights to receive all dividends or other distributions paid with respect to such shares. Unvested restricted stock is forfeitable until earned and therefore not considered outstanding for basic EPS. Because restricted stock awards have the non-forfeitable right to share in dividends and earnings with common shareholders prior to vesting, the Company must apply the two-class method of allocating distributed and undistributed earnings to unvested restricted stock and outstanding common shares. Historically, it was identified by management that the Company had not been applying the two-class method of calculating basic and diluted EPS in accordance with ASC 260. Rather, the Company was considering all restricted stock grants as outstanding at the time of issuance in the calculation of EPS.
At March 31, 2022, the Company determined that its unvested restricted stock awards are participating securities which contain non-forfeitable rights to dividends. As a result, the Company is required to adjust “Net income (loss) attributable to common stockholders” to allocate dividends paid to unvested shares as well as undistributed earnings. In addition, the Company determined that its basic and diluted weighted average shares outstanding were also not adjusted correctly to reflect these participating securities.
The Company concluded the adjustments were immaterial to its 2021 annual and interim financial statements and its 2022 interim financial statements in accordance with the guidance in Securities and Exchange Commission (“SEC”) Staff Accounting Bulletin (“SAB”) No. 99, Materiality and SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in the Current Year Financial Statements. The correction resulted in a decrease of $0.01 per basic and diluted share for the year ended June 30, 2021. See Note 13, “Earnings (Loss) per Common Share” for more details.
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company noted the following adjustments to its Earnings (loss) per common share presentation for the year ended June 30, 2021 (in thousands, except per share amounts):
Year Ended June 30,
As reported:
Net income (loss) for earnings per share calculation $ (16,438)
Weighted average number of common shares outstanding — Basic 33,264
Net earnings (loss) per common share — Basic $ (0.49)
Net earnings (loss) per common share — Diluted $ (0.49)
Revised:
Net income (loss) for earnings per share calculation $ (16,503)
Weighted average number of common shares outstanding — Basic 32,744
Net earnings (loss) per common share — Basic $ (0.50)
Net earnings (loss) per common share — Diluted $ (0.50)
Recently Adopted Accounting Pronouncements
Income Taxes. In December 2019, the Financial Accounting Standards Board (“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 intra-period 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. Effective October 1, 2020, the Company adopted this new standard prospectively and it had no impact on the Company’s consolidated financial statements.
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 ASU 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 Company is currently evaluating the impact of ASU 2016-13 but does not expect that it will have a material effect on the Company’s financial position, results of operations, cash flows or disclosures.
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, cash flows or disclosures.
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 2. Leases
Operating leases are reflected as an operating lease right of use (“ROU”) asset included in “Other assets, net”, and as a ROU liability in “Accrued liabilities and other” and “Operating lease liability” on the Company’s 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 and are presented as “General and administrative expenses” in the consolidated statements of operations. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. For all operating leases, lease and non-lease components are accounted for as a single lease component.
As a non-operator and having adequate liquidity, the Company has generally not entered into lease transactions. The Company’s only operating lease is for corporate office space in Houston, Texas, effective May 1, 2019 and which expires November 30, 2022. The Company has no leases that meet the criteria for classification as a finance lease or a short-term lease.
The Company makes certain assumptions and judgments when evaluating a contract that meets the definition of a lease under ACS 842, Leases. At adoption, July 1, 2019, as the Company’s operating lease did not provide an implicit rate, an incremental borrowing rate was calculated using the prime-rate-based borrowing rate under the Company’s Senior Secured Credit Facility as the term facility was based on a similar lease term and is appropriately risk-adjusted. The lease term was determined by considering any option available to extend or to early terminate the lease which the Company believed was reasonably certain to be exercised.
The table below summarized the Company’s leases for the years ended June 30, 2022 and 2021 (in thousands, except years and discount rate):
Years Ended June 30,
Statements of Operations:
Operating lease costs $ 52 $ 52
Statements of Cash Flow:
Operating cash flows from operating leases $ 62 $ 60
Balance Sheets:
Operating lease ROU asset (included in other assets) $ 21 $ 71
Accrued liabilities and other - current 26 64
Operating lease liability - long-term — 21
Other:
Weighted average remaining lease term in years 0.42 1.34
Weighted average discount rate 5.15 % 5.15 %
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of June 30, 2022, the future minimum lease payments associated with the Company’s non-cancellable operating lease for office space are as follows (in thousands):
Total operating lease payments 26
Less: discount to present value —
Total operating lease liabilities 26
Less: current operating lease liabilities 26
Non current operating lease liabilities $ —
The Company applied the following practical expedients as provided in the standards update which provide elections to not reassess:
● Whether an expired or existing pre-adoption date contracts contained leases.
● Lease classification of any expired or existing leases.
● Initial direct costs for any expired or existing leases.
Note 3. Revenue Recognition
The Company’s revenues are primarily generated from its crude oil, natural gas and NGL production from the Delhi Field in Northeast Louisiana, the Hamilton Dome Field in Wyoming, the Barnett Shale properties located in North Texas, the Williston Basin properties in North Dakota, and the Jonah Field in Sublette County, Wyoming. Additionally, an overriding royalty interest retained in a past divestiture of Texas properties historically provided de minimis revenue, with the exception of the three months ended December 31, 2021 in which the Company received $1.1 million for past royalties that accumulated over a period of approximately three years. These past royalties were recorded as operating revenues within the consolidated statements of operations for the year ended June 30, 2022. Going forward, the Company expects de minimis revenue from these royalty interests. The following table disaggregates the Company’s revenues by major product for the years ended June 30, 2022 and 2021 (in thousands):
Years Ended June 30,
Revenues
As of June 30, 2022, as a non-operator, the Company did not take production in-kind and did not negotiate contracts with customers for its production from the Delhi Field, the Hamilton Dome Field, the Barnett Shale properties or the Willison Basin properties. The Company recognizes crude oil, natural gas, and NGL production revenue at the point in time when custody and title (“control”) of the product transfers to the customer. The sales of oil and natural gas are made under contracts which the Company’s third-party operators of its wells have negotiated with customers, which typically include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. The Company receives payment from the sale of oil and natural gas production one to two months after delivery.
In the Jonah Field, the Company has elected to take its natural gas and NGL working interest production in-kind and markets separately to different purchasers for natural gas and to Enterprise Products Partners L.P. (“Enterprise”) for its NGLs.
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Judgments made in applying the guidance in ASC 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 oil and natural gas 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. To estimate accounts receivable from operators’ contracts with customers, the Company uses knowledge of its properties, information from field operators, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Because the contractual performance obligations have been satisfied and an unconditional right to consideration exists as of the balance sheet date, the Company recognized amounts due from contracts with field operators as “Receivables from crude oil, natural gas, and natural gas liquids sales” on the consolidated balance sheets. 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 the Company by field operators.
Note 4. Acquisitions
On April 1, 2022, the Company closed the acquisition of non-operated interests in the Jonah Field in Sublette County, Wyoming from Exaro Energy III, LLC (the “Jonah Field Acquisition”). After taking into account customary closing adjustments and an effective date of February 1, 2022, total cash consideration for the Jonah Field Acquisition was $26.4 million (“Jonah Purchase Agreement”). The Company accounted for this transaction as an asset acquisition and allocated $24.8 million of the purchase price (including $0.2 million of transaction costs) to proved oil and natural gas properties. Approximately, $1.6 million of the consideration transferred related to deposits transferred to the Company at closing, the largest related to a $1.2 million deposit with Enterprise for a gas gathering contract which was recorded to “Other assets, net” on the consolidated balance sheets. In addition, the Company recognized $3.0 million in non-cash asset retirement obligations. The transaction was funded with cash on hand and $17.0 million in borrowings under the Company’s Senior Secured Credit Facility.
On January 14, 2022, the Company completed the acquisition of non-operated working interests in the Williston Basin in North Dakota from Foundation Energy Fund VII-A, LP and Foundation Energy Management, LLC (the “Williston Basin Acquisition”). After taking into account customary closing adjustments and an effective date of June 1, 2021, cash consideration was $25.2 million which included $0.3 million of capitalized transaction costs related to the acquisition. The Company accounted for the transaction as an asset acquisition and allocated all of the purchase price (including capitalized transaction costs) to proved oil and natural gas properties. The Company also recognized $2.4 million in non-cash asset retirement obligations. The transaction was funded with cash on hand and $16.0 million in borrowings under the Company’s Senior Secured Credit Facility.
On May 7, 2021, the Company acquired an approximate 17% average net working interest and a 14% average net revenue interest in non-operated oil and natural gas properties in the Barnett Shale from Tokyo Gas Americas for net cash consideration of $17.4 million, after taking into account customary closing adjustments, and also recognized $2.8 million in non-cash asset retirement obligations (the “Barnett Shale Acquisition”). The Company determined that the properties acquired did not meet the definition of a business; therefore, the transaction was accounted for as an asset acquisition. During the nine months ended March 31, 2022, the Company recorded a downward purchase price
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
adjustment of $0.9 million related to its acquisition of the Barnett Shale properties as a result of the completion of the final settlement statement.
In accordance with the FASB’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 acquisitions 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.
Note 5. Property and Equipment
Property and equipment as of June 30, 2022 and 2021 consisted of the following (in thousands):
Oil and natural gas properties
Property costs subject to amortization $ 188,634 $ 129,123
Oil and natural gas properties, net $ 110,508 $ 58,516
Other property and equipment
Furniture, fixtures and office equipment, at cost $ 148 $ 155
Less: Accumulated depreciation (148) (144)
Other property and equipment, net $ — $ 11
As of June 30, 2022 and 2021, all oil and natural gas property costs were subject to amortization. Depletion on oil and natural gas properties was $7.5 million and $4.9 million for the years ended June 30, 2022 and 2021, respectively. Depreciation on other properties and equipment was less than $0.1 million for both the years ended June 30, 2022 and 2021.
During the years ended June 30, 2022 and 2021, the Company incurred development capital expenditures of $2.6 million and $0.6 million, respectively. In addition, during the year ended June 30, 2022, the Company recorded a downward $0.9 million purchase adjustment related to its acquisition of the Barnett Shale properties. The Company received $0.9 million during the year ended June 30, 2022 primarily related to effective date net revenues received from the previous owner of the properties.
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, 2022, 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, 2022 of the West Texas Intermediate (“WTI”) crude oil spot price of $85.82 per barrel and Henry Hub natural gas spot price of $5.19 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $44.24, which was based on historical differentials to WTI as NGLs do not have any single comparable reference index price. Using these prices, the Company’s net book value of oil and natural gas properties as of June 30, 2022 did not exceed the current ceiling. There was no impairment on oil and natural gas properties for the year ended June 30, 2022.
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 WTI crude 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 was based on historical differentials to WTI as NGLs do not have any single comparable reference
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
index price. 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. 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 crude 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. For the year ended June 30, 2021, the Company recorded total impairment on oil and natural gas properties of $24.8 million recorded as “Impairment of proved property” on the consolidated statements of operations.
Note 6. Senior Secured Credit Facility
On April 11, 2016, the Company entered into a three-year, senior secured reserve-based credit facility, as amended, (the “Senior Secured Credit Facility”) with MidFirst Bank in an amount up to $50.0 million with a current borrowing base of $50.0 million. On November 2, 2020, the Company entered into the Fifth Amendment to the Senior Secured Credit Facility extending the maturity to April 9, 2024. The borrowing base will be redetermined semiannually, with the lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company’s oil and natural gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas lending criteria. The Senior Secured Credit Facility included a placement fee of 0.50% on the initial borrowing base amounting to $50.0 million 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 London Interbank Offered Rate ("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 Company may elect, at its option, to prepay any borrowings outstanding under the Senior Secured Credit Facility without premium or penalty. Amounts outstanding under the Senior Secured Credit Facility are guaranteed by the Company’s direct and indirect subsidiaries and secured by a security interest in substantially all of the properties of the Company and its subsidiaries. Borrowings under the Senior Secured Credit Facility may be used for the acquisition and development of oil and natural gas properties, investments in cash flow generating properties complimentary to the production of oil and natural gas, and for letters of credit or other general corporate purposes.
The Senior Secured Credit Facility contains certain events of default, including non-payment; breaches or representation and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary bankruptcy; judgments and change in control. The Senior Secured Credit Facility also contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (i) a maximum total leverage ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. As of June 30, 2022, the Company had $21.3 million borrowings outstanding under its Senior Secured Credit Facility, resulting in $28.7 million of available borrowing capacity. As of June 30, 2022, the Company was in compliance with the financial covenants under the Senior Secured Credit Facility.
The Company is currently working on its annual redetermination with MidFirst Bank. It expects that the borrowing base will remain at $50.0 million and the Margined Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit Facility, will be set at $125.0 million. The Company is required to enter into hedges on a rolling 12-month basis when the borrowings exceed 25% of the Margined Collateral Value. Based on the current amount outstanding, the utilization percentage under the required hedging covenant is below the minimum utilization threshold of 25% and as a result the Company is not required to enter into additional hedges at this time.
On February 7, 2022, the Company entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will be based on the Margined Collateral Value, as defined in the agreement, to the extent it exceeds the borrowing base then in effect. This amendment also required the Company to enter into hedges for the next 12-month period ending February 2023, covering 25% of expected crude oil and natural gas production over that period.
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On November 9, 2021, the Company entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby the Company must hedge a minimum of 25% to 75% of future production on a rolling 12-month basis when 25% or more of the borrowing base is utilized. The hedging covenant was amended in the Ninth Amendment, as discussed above.
On August 5, 2021 the Company entered into the Seventh Amendment to the Senior Secured Credit Facility which, among other things, added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the consolidated tangible net worth covenant level was reduced to $40.0 million from $50.0 million.
On January 5, 2021, and effective as of December 28, 2020, the Company entered into the Sixth Amendment to the 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.
Note 7. Income Taxes
The Company files a consolidated federal income tax return in the United States and 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, 2022 and 2021. The Company believes that it has 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 its 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 fiscal years ended June 30, 2018 through June 30, 2021 for federal tax purposes and for the fiscal years ended June 30, 2017 through June 30, 2021 for state tax purposes. To the extent the Company utilizes net operating losses (“NOLs”) generated in earlier years, such earlier years may also be subject to audit.
Income tax (expense) benefit for the years ended June 30, 2022 and 2021 is comprised of the following (in thousands):
Current:
Total current income tax (expense) benefit (7,371) (120)
Deferred:
Total deferred income tax (expense) benefit (1,142) 5,104
Total income tax (expense) benefit $ (8,513) $ 4,984
For the year ended June 30, 2022 the Company recognized income tax expense of $8.5 million and had an effective tax rate of 20.7% compared to an income tax benefit of $5.0 million and an effective tax rates of 23.3% for the year ended June 30, 2021.
In certain prior years, the Company undertook a project to seek potential cash tax savings opportunities identifying available Enhanced Oil Recovery credits (“EOR credits”) related to its interests in the Delhi Field. To take advantage of the EOR credits, the Company amended federal and state tax returns for the years ended June 30, 2017 and 2018 and incorporated the associated impacts into its 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, all of which was received during the year ended June 30, 2022. During year ended June 30, 2022, the Company recognized an income tax benefit of $0.4 million attributable to the EOR credit.
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company’s effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the states of Louisiana and Texas, due to percentage depletion in excess of basis, valuation allowance, enhanced oil recovery credit, and other permanent differences. The following table presents the reconciliation of the Company’s income taxes calculated at the statutory federal tax rate to the income tax (expense) benefit (in thousands).
% of Income % of Income
Before Before
Reconciling items:
Return to provision adjustments (2) — % (20) (0.1) %
Depletion in excess of tax basis 190 (0.5) % 176 0.8 %
Federal valuation allowance 623 (1.5) % (570) (2.7) %
EOR credit benefit 377 (0.9) % 336 1.6 %
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. The components of net deferred income tax assets (liabilities) recognized are as follows (in thousands):
Deferred tax assets:
Non-qualified stock-based compensation $ 106 $ 310
Net operating loss carry-forwards and other carry-forwards 8 365
Derivative losses 427 —
Asset retirement obligations 3,128 1,285
Other deferred tax assets 238 161
Gross deferred tax assets 3,907 2,121
Valuation allowance — (862)
Net deferred tax assets 3,907 1,259
Deferred tax liability:
Oil and natural gas properties (11,006) (7,216)
Total deferred tax liability (11,006) (7,216)
Net deferred tax liability $ (7,099) $ (5,957)
As of June 30, 2022, the Company had a federal tax loss carryforward of approximately $0.6 million that it acquired through a reverse merger in May 2004. The majority of the tax loss carryforwards from the reverse merger expired without being utilized. The remaining deferred tax asset and valuation allowance of $0.1 million related to the portion of the NOLs that were limited by IRC Section 382 was written off during the year ended June 30, 2022. The Company has considered all positive and negative evidence to assess the likelihood that it will be able to realize its deferred tax assets. Realization is dependent on generating sufficient taxable income over the period the deferred tax assets are deductible. For the three-year period ending June 30, 2022, the Company is in a cumulative income position. Based on the weight of available evidence, the Company believes that it is more likely than not that the deferred tax assets will be realized. As result, the Company has released the valuation allowance of $0.6 million.
Note 8. Derivatives
The Company is exposed to certain risks relating to its ongoing business operations, including commodity price risk and interest rate risk. In accordance with the Company’s policy and the requirements under the Senior Secured Credit
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Facility (as discussed in Note 6, “Senior Secured Credit Facility”), it may hedge or may be required to hedge a varying portion of anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company’s hedge policies and objectives may change significantly as its operational profile changes. The Company does not enter into derivative contracts for speculative trading purposes.
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, 2022, the Company did not post collateral under any of its derivative contracts as they are secured under the Company’s Senior Secured Credit Facility.
The Company has in the past and may utilize in the future costless put/call collars and fixed-price swaps to hedge a portion of its anticipated future production. 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. 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. 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.
All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820, Fair Value Measurement ("ASC 820") and included in the consolidated balance sheets as assets or liabilities. The “Derivative contract assets” and “Derivative contract liabilities” represent the difference between the market commodity prices and the hedged prices for the remaining volumes of production hedges as of June 30, 2022 (the “mark-to-market valuation”). The following table summarizes the location and fair value amounts of all derivative contracts in the consolidated balance sheets as of June 30, 2022 and 2021 (in thousands):
Derivatives not designated
The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on derivative contracts in the Company’s consolidated statements of operations (in thousands). "Realized gain (loss) on derivative contracts" represents all receipts (payments) on derivative contracts settled during the period. "Unrealized gain (loss) on derivative contracts" represents the net change in the mark-to-market valuation of the derivative contracts.
Derivatives not designated Location of gain (loss)
as hedging contracts recognized in income on Years Ended June 30,
Commodity contracts: