0001006655-21-000037 | 10-K | XBRL Viewer

Depreciation, depletion, and amortization

$ 32,702,354

$ 29,599,296

Operating costs

5,166,626

5,761,498

Impairment of proved property

24,792,079

Impairment of Well Lift Inc. - related assets

146,051

Net loss on derivative contracts

614,645

1,383,204

General and administrative expenses

^[1]

6,754,532

5,259,659

Total operating costs

54,060,985

25,909,863

Income (loss) from operations

(21,358,631)

3,689,433

Other

Interest and other income

39,401

177,418

Interest expense

(102,965)

(110,775)

Income (loss) before income tax provision

(21,422,195)

3,756,076

Income tax expense (benefit)

(4,984,261)

(2,180,996)

Net income (loss) attributable to common shareholders

$ (16,437,934)

$ 5,937,072

Earnings (loss) per common share

Basic (in dollars per share)

$ (0.49)

$ 0.18

Diluted (in dollars per share)

$ (0.49)

$ 0.18

Weighted average number of common shares outstanding

Basic (in shares)

33,263,701

33,031,149

Diluted (in shares)

33,263,701

33,033,091

Oil

Revenues

$ 26,411,132

$ 28,578,879

Natural gas liquids

Revenues

3,662,478

1,018,349

Natural gas

Revenues

Cash Flows From Operating Activities

2,628,744

2,068

Lease operating costs

Operating costs

Lease operating costs

$ 16,587,052

$ 13,505,502

[1]	General and administrative expenses for the years ended June 30, 2021 and 2020 included non-cash stock-based compensation expense of $1,257,684 and $1,285,663, respectively.

Consolidated Statements of Operations (Parenthetical) - USD ($)	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Non-cash stock-based compensation expense	$ 1,257,684	$ 1,285,663
General and Administrative Expense
Non-cash stock-based compensation expense	$ 1,257,684	$ 1,285,663

Consolidated Statements of Cash Flows - USD ($)

3 Months Ended

12 Months Ended

90 Months Ended

Sep. 30, 2020

Jun. 30, 2021

Jun. 30, 2020

Jun. 30, 2021

Net income (loss) attributable to common shareholders

$ (16,437,934)

$ 5,937,072

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

Depreciation, depletion, and amortization

5,166,626

5,761,498

Impairment of proved property

$ 9,600,000

24,792,079

Impairment of Well Lift Inc. - related assets

146,051

Stock-based compensation

1,257,684

1,285,663

Settlement of asset retirement obligations

(101,311)

(76,832)

Deferred income taxes

(5,103,821)

(261,668)

Net loss on derivative contracts

614,645

1,383,204

Payments received (paid) for derivative settlements

(2,791,176)

793,327

Other

10,316

39,783

Changes in operating assets and liabilities:

Receivables

(6,632,121)

(1,994,368)

Prepaid expenses and other current assets

(545,573)

(33,408)

Accounts payable and accrued expenses

4,498,801

(486,010)

Income taxes payable

(141,441)

48,390

Net cash provided by operating activities

4,732,825

12,396,651

Cash flows from investing activities

Acquisition of oil and gas properties

(18,297,013)

(9,337,716)

Development of oil and natural gas properties

(472,401)

(1,724,829)

Net cash used by investing activities

(18,769,414)

(11,062,545)

Cash flows from financing activities

Common share repurchases, including shares surrendered for tax withholding

(7,347)

(2,483,357)

Common stock dividends paid

(4,342,082)

(10,740,754)

$ (74,500,000)

Borrowings under credit facility

7,000,000

Repayments of credit facility

(3,000,000)

Net cash provided by (used in) financing activities

(349,429)

(13,224,111)

Net decrease in cash, cash equivalents, and restricted cash

(14,386,018)

(11,890,005)

Cash, cash equivalents, and restricted cash, beginning of year

$ 19,662,528

^[1]

19,662,528

^[1]

31,552,533

Cash, cash equivalents, and restricted cash, end of year

^[1]

$ 5,276,510

$ 19,662,528

$ 5,276,510

[1]	Neither annual period had any restricted cash balances.

Consolidated Statements of Changes in Stockholders' Equity - USD ($)	Total	Common Stock	Additional Paid-in Capital	Retained Earnings	Treasury Stock
Balance (shares) at Jun. 30, 2019		33,183,730
Balance at Jun. 30, 2019	$ 80,125,858	$ 33,183	$ 42,488,913	$ 37,603,762	$ 0
Increase (Decrease) in Stockholders' Equity
Issuance of restricted common stock (shares)		271,778
Issuance of restricted common stock		$ 272	(272)
Forfeitures of restricted stock (shares)		(49,118)
Forfeitures of restricted stock		$ (49)	49
Common share repurchases, including shares surrendered for tax withholding	(2,483,357)				(2,483,357)
Retirements of treasury stock (in shares)		(449,921)
Retirements of treasury stock		$ (450)	(2,482,907)		2,483,357
Stock-based compensation	1,285,663		1,285,663
Net income (loss) attributable to common shareholders	5,937,072			5,937,072
Common stock dividends paid	(10,740,754)			(10,740,754)
Balance (shares) at Jun. 30, 2020		32,956,469
Balance at Jun. 30, 2020	74,124,482	$ 32,956	41,291,446	32,800,080	0
Increase (Decrease) in Stockholders' Equity
Issuance of restricted common stock (shares)		561,115
Issuance of restricted common stock		$ 562	(562)
Common share repurchases, including shares surrendered for tax withholding	(7,347)				(7,347)
Retirements of treasury stock (in shares)		(2,632)
Retirements of treasury stock		$ (3)	(7,344)		7,347
Stock-based compensation	1,257,684		1,257,684
Net income (loss) attributable to common shareholders	(16,437,934)			(16,437,934)
Common stock dividends paid	(4,342,082)			(4,342,082)
Balance (shares) at Jun. 30, 2021		33,514,952
Balance at Jun. 30, 2021	$ 54,594,803	$ 33,515	$ 42,541,224	$ 12,020,064	$ 0

Organization and Basis of Preparation	12 Months Ended
Organization and Basis of Preparation	Jun. 30, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Preparation	Organization and Basis of Preparation Nature of Operations. Evolution Petroleum Corporation is an oil and natural gas company focused on delivering a sustainable dividend yield to its stockholders through the ownership, management, and development of producing oil and natural gas properties. The Company's long-term goal is to build a diversified portfolio of oil and natural gas assets primarily through acquisitions while seeking opportunities to maintain and increase production through selective development, production enhancement, and other exploitation efforts on its properties. Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO2 enhanced oil recovery (“EOR”) project, our interests in the Hamilton Dome field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, our interests in the Barnett Shale located in North Texas, a natural gas producing shale reservoir, and overriding royalty interests in two onshore Texas wells. Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of Evolution Petroleum Corporation and its wholly-owned subsidiaries (the “Company”). All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year may include certain reclassifications to conform to the current presentation. Any such reclassifications have no impact on previously reported net income or stockholders' equity. Risk and Uncertainties. The Company is continuously monitoring impacts of the COVID-19 pandemic on its business, including how it has and may continue to impact its financial results, liquidity, employees, and the operations of the Delhi field, Hamilton Dome fields, and its Barnett Shale assets in which it holds non-operated interests. In response to the pandemic, the operator at Hamilton Dome temporarily shut-in some producing wells. In addition to the above, the pandemic slowed the repair schedule of the Delhi CO2 supply pipeline which, together with the foregoing, negatively impacted our production. All of the Company’s property interests are not operated by the Company and involve other third-party working interest owners. As a result, the Company has limited ability to influence or control the operation or future development of such properties. However, the Company has been proactive with its third-party operators to review spend and alter plans as appropriate. The Company is focused on putting long term measures to prevent future disruptions, maintaining its operations and system of controls remotely and has implemented its business continuity plans in order to allow its employees to securely work from home or in the corporate office. The Company was able to transition the operation of its business with minimal disruption and has maintained its system of internal controls and procedures. Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include (a) reserve quantities and estimated future cash flows associated with proved reserves, which may significantly impact depletion expense and potential impairments of oil and natural gas properties, (b) asset retirement obligations, (c) stock-based compensation, (d) fair values of derivative assets and liabilities, (e) income taxes and the valuation of deferred tax assets, (f) commitments and contingencies and (g) oil, natural gas, and NGL revenues. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Jun. 30, 2021
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Cash and Cash Equivalents. We consider all highly liquid investments, with original maturities of 90 days or less when purchased, to be cash and cash equivalents. Restricted Cash. Funds legally designated for a specified purpose are classified as restricted cash. Such a balance is classified on the statement of financial position as either current or non-current depending on its expected use. At June 30, 2021 and 2020, we had no such balances. Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable consist of accrued hydrocarbon revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2021 and 2020, no allowance for doubtful accounts was considered necessary. Oil and Natural Gas Properties. We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs that are directly related to property acquisition, exploration, and development activities but does not include any costs related to production, general corporate overhead, or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from depletion and amortization, which represent investments in unproved and unevaluated properties and include non-producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. These costs are excluded until the project is evaluated and proved reserves are established or impairment is determined. As of June 30, 2021 and 2020, we did not have any costs excluded from depletion and amortization. Limitation on Capitalized Costs. Under the full-cost method of accounting, we are required, at the end of each fiscal quarter, to perform a test to determine the limit on the book value of our oil and natural gas properties (the “Ceiling Test”). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the “Ceiling”, this excess or impairment is charged to expense and reflected as additional accumulated depreciation, depletion, and amortization or as a credit to oil and natural gas properties. The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10 percent and assuming continuation of existing economic conditions, of 1) estimated future gross revenues from proved reserves, which is computed using oil and natural gas prices determined as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period (with consideration of price changes only to the extent provided by contractual arrangements including hedging arrangements pursuant to SAB 103), less 2) estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves; plus (b) the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)); plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; net of (d) the related tax effects related to the difference between the book and tax basis of our oil and natural gas properties. See Note 6 - Property and Equipment for further information about impairment for the year ended June 30, 2021. Other Property and Equipment. Other property and equipment includes building leasehold improvements, data processing and telecommunications equipment, office furniture, and office equipment. These items are recorded at cost and depreciated over expected lives of the individual assets or group of assets, which range from three to seven years. The assets are depreciated using the straight-line method. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. Repairs and maintenance costs are expensed in the period incurred. Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in other assets on the Company's consolidated balance sheet and are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. Asset Retirement Obligations. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred. It is associated with an increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The initial recognition or subsequent revision of asset retirement cost is considered a Level 3 fair value measurement. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivative instruments, and debt. Except for derivatives, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable are short-term instruments and approximate fair value due to their highly liquid nature. The carrying amount of debt approximates fair value as the variable rates on the Senior Secured Credit Facility are market interest rates. The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and natural gas, discount rates, and volatility factors. Stock-based Compensation. We estimate the fair value of stock-based compensation awards on the grant date to provide the basis for future compensation expense. Service-based and performance-based Restricted Stock and Contingent Restricted Stock awards (as defined in Note 11 - Stock-Based Incentive Plan) are valued using the market price of our common stock on the grant date. Market-based awards are valued using a Monte Carlo simulation and geometric Brownian motion techniques applied to the historical volatility of the Company's total stock return compared to the historical volatilities of other companies or indices to which we compare our performance. This Monte Carlo simulation also provides an expected vesting period. For service-based awards, stock-based compensation is recognized ratably over the service period. For performance-based awards, stock-based compensation is recognized ratably over the expected vesting period when it is deemed probable, for accounting purposes, that the performance goal will be achieved. The expected vesting period may be shorter than the remaining term. For market-based awards, stock-based compensation expense is recognized ratably over the expected vesting period, so long as the award holder remains an employee of the Company. Total compensation expense is independent of vesting or expiration of the awards, except for termination of service. Revenue Recognition - Oil and Natural Gas. Our revenues are comprised solely of revenues from customers from the sale of oil, natural gas, and natural gas liquids. The Company believes that the disaggregation of revenue on its consolidated statements of operations into these three major product types appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors based on our geographic locations. Oil, natural gas, and natural gas liquids revenues are recognized at a point in time when production is sold to a purchaser at an index-based, determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue is a function of the contract billing terms which reference index price sources used by the industry. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required within 30 days for oil and 60 days for natural gas and natural gas liquids after the end of the production month. At the end of each month when the performance obligations have been satisfied, the consideration can be reasonably estimated and amounts due from customers (remitted to us by field operators) are accrued in “Receivables from oil and gas sales” in our consolidated balance sheets. As of June 30, 2021 and 2020 receivables from contracts with customers were $8.7 million and $1.9 million, respectively. This increase was related primarily to approximately two months of accrued revenue from the Barnett Shale Acquisition. For additional revenue recognition information see Note 3 - Revenue Recognition. Estimates of Proved Reserves. The estimated quantities of proved oil and natural gas reserves have a significant impact on the underlying financial statements. The estimated quantities of proved reserves are used to calculate depletion expense and the estimated future net cash flows associated with those proved reserves is the basis for determining impairment under the quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex and requires significant decisions in the evaluation of all available geologic, geophysical, engineering, and economic data. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information; this includes reservoir performance, additional development activity, new geologic and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates prepared by our third-party independent engineers represent the most accurate assessments possible, the subjective decisions and variances in available data for the properties make these estimates generally less precise than other estimates included in our financial statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect our estimated future net cash flows of our proved reserves. These changes could affect our quarterly ceiling test calculation and could significantly affect our depletion rate. Derivative Instruments. The Company follows ASC 815, Derivatives and Hedging (“ASC 815”). From time to time, in accordance with the Company’s policy, it may hedge a portion of its forecasted oil, natural gas, and natural gas liquids production. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”) master agreement; the agreement provides for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net (gain) loss on derivative instruments” on the consolidated statements of operations. Depreciation, Depletion, and Amortization (“DD&A”). The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of DD&A, estimated future development costs, and asset retirement costs (net of salvage values) not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves. Other property, consisting of leasehold building improvements and office and computer equipment, is depreciated as described above in Other Property and Equipment. Income Taxes. We recognize deferred tax assets and liabilities based on the differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that may result in taxable or deductible amounts in future years. The measurement of deferred tax assets may be reduced by a valuation allowance based upon management's assessment of available evidence if it is deemed more likely than not that some or all of the deferred tax assets will not be realizable. We recognize a tax benefit from an uncertain position when it is more likely than not that the position will be sustained upon examination which is based on the technical merits of the position. We record the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax expense. Earnings (Loss) Per Share. Basic earnings (loss) per share (“EPS”) is computed by dividing earnings or loss available to common stockholders by the weighted-average number of common shares outstanding during the period. The computation of diluted EPS is similar to the computation of basic EPS, except that the denominator is increased to include the number of additional common shares that would have been outstanding if potentially dilutive common shares had been issued. Potentially dilutive common shares are our contingent restricted common stock. We use the treasury stock method to determine the effect of potentially dilutive common shares on diluted EPS, unless the effect would be anti-dilutive. Under this method, exercise of contingent restricted common stock, under certain condition, is assumed to have occurred at the beginning of the period (or at time of issuance, if later); common shares are assumed to have been issued. The unamortized stock compensation expense related to restricted common stock are assumed to be used to repurchase common stock at the average market price during the period. The incremental shares (the difference between the number of shares assumed issued and the number of shares assumed repurchased) are included in the denominator of the diluted EPS computation. Contingent restricted stock is included in the computation of diluted shares, if dilutive, when the underlying performance conditions either (i) were satisfied as of the end of the reporting period or (ii) would be considered satisfied if the end of the reporting period were the end of the related contingency period. Recently Adopted Accounting Pronouncements Leases. Effective July 1, 2019, the Company adopted the new standard using a modified retrospective approach and elected to use the optional transition methodology whereby reporting periods prior to adoption continue to be presented in accordance with legacy accounting guidance, Accounting Standard Codification 840 - Leases. Upon transition, we recognized a right of use (“ROU”) asset (or operating lease right-of-use asset) and an operating lease liability with no retained earnings impact. We applied the following practical expedients as provided in the standards update which provide elections to not reassess: •Not to apply the recognition requirements in the lease standard to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option that the Company is reasonably certain to exercise). •Whether an expired or existing pre-adoption date contracts contained leases. •Lease classification of any expired or existing leases. •Initial direct costs for any expired or existing leases. •Not to separate lease components from non-lease components in a contract and accounting for the combination as a lease (reflected by asset class). Adoption of the new standard did not impact our consolidated statements of operations, cash flows or stockholders’ equity. Income Taxes. In December 2019, the FASB issued Accounting Standards Update (ASU) 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (ASU 2019-12) as part of its initiative to reduce complexity in the accounting standards. The amendments in ASU 2019-12 remove certain exceptions related to the incremental approach for intraperiod tax allocation and the general methodology for calculating income taxes in an interim period and reducing diversity in practice for the recognition of enacted changes in tax law. ASU 2019-12 also clarifies and simplifies other aspects of accounting for income taxes. ASU 2019-12 is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2020; however, early adoption is permissible for periods for which financial statements have not yet been issued. Effective October 1, 2020, the Company prospectively adopted this new standard. Adoption of this standard had no impact on our consolidated financial statements nor would it have had if we had adopted the standard on July 1, 2020. Recently Issued Accounting Pronouncements In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. Early adoption is permitted and entities must adopt the amendment using a modified retrospective approach to the first reporting period in which the guidance is effective. For smaller reporting companies, as provided by Accounting Standards Update 2019-10, Financial Instruments - Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842), ASU 2016-13 is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2022. The adoption of ASU 2016-13 is currently not expected to have a material effect on our consolidated financial statements. Other accounting pronouncements that have recently been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company's financial position, results of operations, or cash flows.

Revenue Recognition

12 Months Ended

Jun. 30, 2021

Revenue from Contract with Customer [Abstract]

Revenue Recognition

Revenue RecognitionOur revenue is primarily generated from our interests in the Delhi field in Northeast Louisiana, the Barnett Shale assets of North Texas, and the Hamilton Dome field in Wyoming. Additionally, an overriding royalty interest retained in a past divestiture of Texas properties provided de minimis revenue:


	June 30,
	2021		2020
Revenues
Oil	$	26,411,132	$	28,578,879
Natural gas liquids	3,662,478		1,018,349
Natural gas	2,628,744		2,068
Total revenues	$	32,702,354	$	29,599,296

We are a non-operator and presently do not take production in-kind and do not negotiate contracts with customers. We recognize oil, natural gas, and natural gas liquids production revenue at the point in time when custody and title (“control”) of the product transfers to the customer. Transfer of control drives the presentation of post-production expenses such as transportation, gathering, and processing deductions within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within the lease operating costs line item on the accompanying consolidated statements of operations, while fees and other deductions incurred subsequent to control transfer are embedded in the price and effectively recorded as a reduction of oil, natural gas, and natural gas liquids production revenue. Transfer of control related to the Barnett Shale production does not occur until after the marketing, transportation and processing services have been performed, and as such, fees related to these services are recorded within the lease operating costs line item and do not reduce the oil, natural gas, and natural gas liquids production revenue. Transfer of control related to the Hamilton Dome and Delhi production occurs prior to the fees and other deductions, and as such, these fees are recorded as a reduction to the oil and natural gas liquids production revenue.

Judgments made in applying the guidance in Accounting Standards Codification Topic 606, Revenue from Contracts with Customers, relate primarily to determining the point in time when control of product transfers to the customer. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained.

The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied at a point in time upon control transferring to a customer at a specified delivery point. Consideration is allocated to completed performance obligations at the end of an accounting period.

Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received by field operators before distributing the Company’s share one to two months after production has occurred, which is typical in the industry. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for the sale of the product. Estimated revenue due to the Company is recorded within the “Receivables from oil and gas sales” line item on the accompanying consolidated balance sheets until payment is received from field operators. The accounts receivable balances from contracts with customers as of June 30, 2021 and 2020, as presented on our respective consolidated balance sheets, were $8.7 million and $1.9 million, respectively. The increase between fiscal 2020 and fiscal 2021 is primarily due to the Barnett Shale Acquisition. To estimate accounts receivable from operators’ contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser as remitted to us by field operators. Revenue recognized during the fiscal year ended June 30, 2021 and 2020 related to performance obligations satisfied in prior reporting periods, was immaterial.

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI http://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130551-203045

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130556-203045

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
-Section 50
-Paragraph 12
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=123351226&loc=SL49130554-203045

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Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Leases

12 Months Ended

Jun. 30, 2021

Leases [Abstract]

Leases

LeasesOperating leases are reflected as an operating lease ROU asset included in “Other assets, net”, and as a ROU liability in “Accrued liabilities and other” and “Operating lease liability” on our consolidated balance sheets. Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset would also include any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred, if any. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets

and lease liabilities. For all operating leases, lease and non-lease components are accounted for as a single lease component.

As a non-operator in recent years and having adequate liquidity, the Company has generally not entered into lease transactions. Presently, our only operating lease is for corporate office space in Houston, Texas, effective May 1, 2019 and which expires November 30, 2022. Presently we have one operating lease for office space, no finance leases, and no short-term leases.

The Company makes certain assumptions and judgments when evaluating a contract that meets the definition of a lease under Topic 842. At adoption, July 1, 2019, as our lease did not provide an implicit rate, we used our prime-rate-based borrowing rate under our senior secured credit facility as our incremental borrowing as the term facility was based on a similar term and is appropriately risk-adjusted. We determined lease term by considering any option available to extend or to early terminate the lease which we believed was reasonably certain to be exercised.

At June 30, 2021, maturities of our operating lease liability are as follows:


Fiscal Year	Operating Lease Liability
2022	61,843
2023	26,098
Total lease payments	87,941
Less imputed interest	(2,962)
Total lease liability	$	84,979

Supplemental cash flow, balance sheet, and other disclosures information related to our operating leases are as follows:


	As of and For the Year Ended June 30, 2021			As of and For the Year Ended June 30, 2020
Cash Flow:
Cash paid for amounts included in the measurement of lease liabilities	$	59,945		$	4,903
ROU asset added in exchange for lease obligation at adoption	—			161,125

Balance Sheet:
Operating lease ROU asset (included in other assets)	70,789			117,193
Accrued liabilities - current	64,234			54,290
Operating lease liability - long-term	20,745			84,978

Other:
Weighted average remaining lease term in years	1.34			2.66
Weighted average discount rate	5.15		%	5.15		%

Prepaid Expenses and Other Current Assets

12 Months Ended

Jun. 30, 2021

Prepaid Expenses and Other Current Assets


	June 30, 2021		June 30, 2020
Prepaid insurance	$	365,922	$	289,999
Prepaid subscription and licenses	108,048		67,005
Prepaid federal and state income taxes	97,470		86,208
Carryback of EOR tax credit	416,441		—
Prepaid other	49,378		48,474
Total prepaid expenses and other current assets	$	1,037,259	$	491,686

Property and Equipment, Net of Depreciation, Depletion, and Amortization

12 Months Ended

Jun. 30, 2021

Property, Plant and Equipment [Abstract]

Property and Equipment, Net of Depreciation, Depletion, and Amortization


	June 30, 2021		June 30, 2020
Oil and natural gas properties:
Property costs subject to amortization	$	129,123,227	$	107,390,379
Less: Accumulated depreciation, depletion, and amortization and impairment (a)	(70,607,367)		(40,878,098)
Unproved properties not subject to amortization	—		—
Oil and natural gas properties, net	58,515,860		66,512,281
Other property and equipment:
Furniture, fixtures, and office equipment, at cost	154,731		154,731
Less: Accumulated depreciation (b)	(144,092)		(137,092)
Other property and equipment, net	$	10,639	$	17,639

(a) Depletion on oil and natural gas properties was $4,901,969 for fiscal 2021 and $5,592,651 for fiscal 2020. Impairment on oil and natural gas properties was $24,792,079 for fiscal 2021, and there was no impairment in fiscal 2020.

(b) Depreciation was $7,000 for fiscal 2021 and $8,779 for fiscal 2020.

As of June 30, 2021 and 2020, all oil and gas property costs were being amortized.

During the years ended June 30, 2021 and 2020, the Company incurred capital expenditures of $0.6 million and $1.5 million, respectively.

On May 7, 2021, the Company acquired an approximate 17% working interest and a 14% revenue interest in non-operated oil and gas assets in the Barnett Shale from Tokyo Gas Americas for $18.3 million, net of preliminary purchase price adjustments, and also recognized $2.8 million in non-cash asset retirement obligations. The Company accounted for this transaction as an asset acquisition with an effective of January 1, 2021.

On November 1, 2019, the Company acquired a 23.5% non-operated working interest and a 19.7% revenue interest in the Hamilton Dome unitized field located in Hot Springs County, Wyoming, from the Merit Energy Company. As a result of this cash purchase combined with its subsequent purchase adjustments, the Company recorded a purchase cost of $9.3 million, net of purchase price adjustments, and also recognized $0.9 million in non-cash asset retirement obligations. The Company accounted for this transaction as an asset acquisition.

In accordance with the Financial Accounting Standards Board’s authoritative guidance on asset acquisitions, the Company allocated the cost of the acquisition to the assets acquired and liabilities assumed based on a relative fair value basis of the assets acquired and liabilities assumed, with no recognition of goodwill or bargain purchase gain recorded. Incremental legal and professional fees related directly to the Acquisition were capitalized as part of the Acquisition cost. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize market assumptions of market participants.

The Company uses the full cost method of accounting for its investments in oil and natural gas properties. All costs of acquisition, exploration, and development of oil and natural gas reserves are capitalized as the cost of oil and natural gas and properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such excess capitalized costs result in an impairment charge.

At June 30, 2021, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month average for the 12-months ended June 30, 2021 of the West Texas Intermediate (WTI) oil spot price of $49.72 per barrel and Henry Hub natural gas spot price of $2.46 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $19.81, which does not have any single comparable reference index price. The NGL price was based on historical prices received. Using these prices, the Company’s net book value of oil and natural gas properties at June 30, 2021 did not exceed the current ceiling.

At December 31, 2020 and September 30, 2020, the Company recorded ceiling test impairment charges of $15.2 million and $9.6 million, respectively. The ceiling test impairments were driven by decreases in the first-day-of-the-month average for oil used in the ceiling test calculation, from $47.37 per barrel at June 30, 2020 to $43.63 per barrel at September 30, 2020 to $39.54 per barrel at December 31, 2020.

Other Assets, Net

12 Months Ended

Jun. 30, 2021

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Other Assets, Net


	June 30, 2021		June 30, 2020
Royalty rights	—		108,512
Less: Accumulated amortization of royalty rights	—		(61,037)
Investment in Well Lift Inc., at cost	—		108,750
Deferred loan costs	168,972		168,972
Less: Accumulated amortization of deferred loan costs	(168,972)		(157,084)
Right of use asset under operating lease	161,125		161,125
Less: Accumulated amortization of right of use asset	(90,336)		(43,932)
Software license	20,662		20,662
Less: Accumulated amortization of software license	(20,662)		(14,350)
Other assets, net	$	70,789	$	291,618

Our royalty rights and investment in WLI resulted from the separation of our artificial lift technology operations in December 2015. We conveyed our patents and other intellectual property to WLI and retained a 5% royalty on future gross revenues associated with the technology. We own 17.5% of the common stock and 100% of the preferred stock of WLI and account for our investment in this private company at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer, if such were to occur. The Company evaluates the investment for impairment when it identifies any events or changes in circumstances that might have a significant adverse effect on the fair value of the investment. At March 31, 2021, we reviewed our investment and technology rights in WLI for potential impairment and, as a result, recorded an impairment expense of $0.1 million. This impairment charge was recorded based on a variety of factors including the lack of current revenue generated and the outlook for future activity associated with this technology primarily due to a reduction in drilling activities across the industry.

Accrued Liabilities and Other

12 Months Ended

Jun. 30, 2021

Other Liabilities Disclosure [Abstract]

Accrued Liabilities and Other


	June 30, 2021		June 30, 2020
Accrued incentive and other compensation	$	630,744	$	176,636
Accrued retirement costs	52,786		—
Accrued franchise taxes	35,207		100,978
Accrued ad valorem taxes	108,000		108,000
Payable for settled derivatives	—		265,188
Operating lease liability, current	64,234		54,290
Asset retirement obligations due within one year	44,520		—
Accrued - other	11,554		11,556
Total Accrued liabilities and other	$	947,045	$	716,648

Asset Retirement Obligations

12 Months Ended

Jun. 30, 2021

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Our asset retirement obligations represent the estimated present value of the amount we expect to incur to plug, abandon, and remediate our producing properties at the end of their productive lives in accordance with applicable laws and regulations. During the year ended June 30, 2021, the Delhi field operator abandoned two wells. Presently, we expect the Hamilton Dome operator to plug four wells during the next twelve months. The following is a reconciliation of the beginning and ending asset retirement obligations for the years ended June 30, 2021 and 2020:


	Years Ended
	2021			2020
Asset retirement obligations — beginning of period	$	2,588,894		$	1,610,845
Liabilities incurred	—			40,698
Liabilities settled	(99,231)		(a)	(86,592)
Liabilities acquired	2,806,331		(b)	903,580
Accretion of discount	210,182			146,504
Revisions of previous estimates	77,096		(c)	(26,141)
Asset retirement obligations — end of period	5,583,272			2,588,894
Less: current asset retirement obligations	44,520			—
Long-term portion of asset retirement obligations	$	5,538,752		$	2,588,894

(a) Abandonment of two non-scheduled Delhi field wells in fiscal 2021, and abandonment of one Delhi field well and four Hamilton Dome field wells in fiscal 2020.

(b) Liabilities acquired in fiscal 2021 and 2020 were primarily due to our acquisition of the Barnett Shale interest and the Hamilton Dome interest, respectively.

Stockholders' Equity

12 Months Ended

Jun. 30, 2021

Equity [Abstract]

Stockholders' Equity

Common Stock

As of June 30, 2021, we had 33,514,952 shares of common stock outstanding.

The Company began paying quarterly cash dividends on common stock in December 2013. As of June 30, 2021, we have cumulatively paid over $74.5 million in cash dividends. We paid dividends of $4,342,082 and $10,740,754 to our common stockholders during the years ended June 30, 2021 and 2020, respectively. The following table reflects the dividends paid within the respective three-month periods:


	Fiscal Year
	2021	2020
Fourth quarter ended June 30,	$0.050	$0.025
Third quarter ended March 31,	$0.030	$0.100
Second quarter ended December 31,	$0.025	$0.100
First quarter ended September 30,	$0.025	$0.100

In May 2015, the Board of Directors approved a share repurchase program covering up to $5.0 million of the Company's common stock. Since inception of the program through June 30, 2021, the Company has spent $4.0 million to repurchase 706,858 common shares at an average price of $5.72 per share. There were no shares purchased under this program during the year ended June 30, 2021. Under the program's terms, shares are repurchased only on the open market and in accordance with the requirements of the SEC. Such shares are initially recorded as treasury stock, then subsequently canceled. The timing and amount of repurchases depends upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and it may be suspended or discontinued at any time.

During the year ended June 30, 2021 and 2020, the Company also acquired treasury stock from holders of newly vested stock-based awards to fund the recipients' payroll tax withholding obligations. The treasury shares were subsequently canceled. Such

shares were valued at fair market value on the date of vesting. The following table shows all treasury stock purchases in the last two fiscal years:


	Common Shares Acquired	Average Price per Share		Treasury Stock Purchases
Year Ended June 30, 2021:
Shares surrendered for tax withholding upon vesting	2,632	$	2.79	$	7,347
Share repurchase program	—	$	—	—
Total	2,632	$	2.79	$	7,347

Year Ended June 30, 2020:
Shares surrendered for tax withholding upon vesting	9,255	$	5.90	$	54,565
Share repurchase program	440,666	$	5.51	2,428,792
Total	449,921	$	5.52	$	2,483,357

Expected Tax Treatment of Dividends

For the fiscal year ended June 30, 2020, all common stock dividends for that fiscal year were treated for tax purposes as qualified dividend income to the recipients. Based on our current projections for the fiscal year ended June 30, 2021, we expect all common stock dividends for such period to be treated as qualified dividend income to the recipients.

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

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Share-based Payment Arrangement [Abstract]

Stock-Based Incentive Plan

12 Months Ended

Jun. 30, 2021

Stock-Based Incentive Plan

The Evolution Petroleum Corporation 2016 Equity Incentive Plan (“2016 Plan”), approved in the December 2016 annual meeting, authorized the issuance of 1,100,000 shares of common stock prior to its expiration on December 8, 2026. Incentives under the 2016 Plan may be granted to employees, directors, and consultants of the Company in any one or a combination of the following forms: incentive stock options and non-statutory stock options, stock appreciation rights, restricted stock awards and restricted stock unit awards, performance share awards, performance cash awards, and other forms of incentives valued in whole or in part by reference to, or otherwise based on, our common stock, including its appreciation in value. On December 9, 2020, an amendment to the 2016 Plan was approved by our stockholders which increased the number of shares available for issuance by 2,500,000 shares. There were 2,206,294 shares available for grant under the 2016 Plan as of June 30, 2021.

Restricted Stock and Contingent Restricted Stock

The Company has awarded grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after a maximum of four years if unvested, contain service-based, performance-based, and market-based vesting provisions. The common shares underlying the Restricted Stock grants are issued on the date of grant. Contingent Restricted Stock grants vest only upon the attainment of higher performance-based or market-based vesting thresholds and are issued only upon vesting. Shares underlying Contingent Restricted Stock awards are reserved from the Plan they were granted under.

During the year ended June 30, 2021, the Company granted 314,955 service-based restricted stock awards primarily to employees under its long term incentive program together with annual awards to its directors. In addition, under this program, the Company granted 246,160 market-based restricted stock awards and 123,080 Contingent Restricted Stock awards to employees. In addition to the foregoing, in connection with the retirement of the Company's former Chief Financial Officer, vesting was accelerated as to 50,524 aggregate shares of service- and market-based equity awards (with a weighted average fair value of $5.15 per share) which, for accounting purposes, was treated as a cancellation and replacement of the same number of awards which had a fair value of $2.79 per share.

During the year ended June 30, 2020, the Chief Executive Officer upon his July 2019 employment received 48,872 shares of service-based restricted common stock which vests in three equal amounts on June 30, 2020, 2021, and 2022; he was also awarded a total of 200,000 market-based Contingent Restricted Stock units consisting of four equal tranches, each of which may vest only if its respective stock price requirement is met before the award term expires. Each tranche has a separate stated price requirement and respective vesting will occur only if, before July 1, 2023, the ninety-day trailing average Company stock share price equals or exceeds its tranche price requirement. We also granted 52,119 service-based and 104,236 market-based Restricted Stock awards to our employees as well as 56,395 serviced-based awards to the company's directors.

Service-based awards vest with continuous employment by the Company, generally in annual installments over terms of three to four years. Awards to the Company's directors have one-year cliff vesting. Restricted Stock grants, which vest based on service, are valued at the fair market value of the Company’s common stock on the date of grant and amortized over the service period.

Performance-based grants vest upon the attainment of earnings, revenue, and other operational goals and require that the recipient remain an employee or director of the Company through the vesting date. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period based on the grant date fair value of the Company’s common stock and when it is deemed probable, for accounting purposes, that the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the term of the award. As of June 30, 2021, there were no performance-based awards outstanding.

Many of our past market-based awards could vest if their respective two- or three-year trailing total returns on the Company’s common stock exceed the corresponding total returns of various quartiles of indices consisting of peer companies. Additionally, more recent market-based awards vest when the average of the Company's closing stock price over a defined quarterly measurement period meets or exceeds a required stock price. The third-party independent assessment of fair values and expected vesting periods of these awards are determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies in the index. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the holder remains an employee or director of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service.

For market-based awards granted during the years ended June 30, 2021 and 2020, the assumptions used in the Monte Carlo simulation valuations, expected lives and fair values were as follows:


	Year Ended June 30,
	2021			2020

Weighted average fair value of market-based awards granted	$	3.08		$	3.79
Risk-free interest rate	0.23		%	1.65% to 1.87%
Expected life in years	2.56			1.35 to 2.56
Expected volatility	56.9		%	38.6% to 43.7%
Dividend yield	3.2		%	6% to 7.2%

Unvested Restricted Stock awards at June 30, 2021 consisted of the following:


Award Type	Number of Restricted Shares	Weighted Average Grant-Date Fair Value
Service-based awards	348,762	$	3.37

Market-based awards	320,533	3.38
Unvested at June 30, 2021	669,295	$	3.37

The following table sets forth the Restricted Stock transactions for the year ended June 30, 2021:


	Number of Restricted Shares	Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2021		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2020	285,028	$	5.53	$	—
Service-based shares granted	365,479	2.97

Market-based shares granted	246,160	3.07
Vested	(176,848)	5.09
Forfeited	(50,524)	5.15
Unvested at June 30, 2021	669,295	$	3.37	$	1,530,550	1.88

The following is a summary of Restricted Stock that vested during the last two fiscal years:


	Year Ended June 30,
	2021		2020
Vesting-date intrinsic value of Restricted Stock	$	570,711	$	477,647
Grant-date fair value of vested Restricted Stock	$	900,007	$	748,893
Number of awards that vested	176,848		104,159

Unvested Contingent Restricted stock awards table below consists solely of market-based awards for the year ended June 30, 2021:


	Number of Restricted Stock Units	Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2021		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2020	200,000	$	3.50

Market-based awards granted	123,080	1.76

Vested	—	—
Unvested at June 30, 2021	323,080	$	2.84	$	169,257	2.00

All of these outstanding awards at June 30, 2021 are market-based awards.

The following is a summary of Contingent Restricted Stock vestings for the last two fiscal years:


	Year Ended June 30,
	2021		2020
Vest-date intrinsic value of Contingent Restricted Stock	$	—	$	60,225
Grant-date fair value of vested Contingent Restricted Stock	$	—	$	34,734
Number of awards that vested	—		10,156

Stock-based Compensation Expense

For the years ended June 30, 2021, and 2020, we recognized stock-based compensation expense related to Restricted Stock and Contingent Restricted Stock grants of $1,257,684 and $1,285,663, respectively.

Supplemental Disclosure of Cash Flow Information

12 Months Ended

Jun. 30, 2021

Supplemental Cash Flow Elements [Abstract]

Supplemental Disclosure of Cash Flow Information


	June 30,
	2021		2020
Interest paid on the Senior Secured Credit Facility	$	86,347	$	76,390
Income taxes paid	757,963		1,241,538
Income tax refunds	141,848		—
Non-cash transactions:
Decrease in accrued purchases of property and equipment	80,008		(212,456)
Oil and natural gas property costs attributable to the recognition of asset retirement obligations	2,883,426		918,137

Income Taxes

12 Months Ended

Jun. 30, 2021

Income Tax Disclosure [Abstract]

Income Taxes

We file a consolidated federal income tax return in the United States of America in addition to various combined and separate filings in several state and local jurisdictions.

There were no unrecognized tax benefits, nor any accrued interest or penalties associated with unrecognized tax benefits during the years ended June 30, 2021 and 2020. We believe that we have appropriate support for the income tax positions taken and to be taken on the Company's tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations for the years ended June 30, 2017 through June 30, 2020 for federal tax purposes and for the years ended June 30, 2016 through June 30, 2020 for state tax purposes. To the extent we utilize net operating losses generated in earlier years, such earlier years may also be subject to audit.

The components of our income tax provision (benefit) are as follows:


	June 30, 2021		June 30, 2020
Current:
Federal	$	(334,473)	$	(2,264,850)
State	454,033		345,522
Total current income tax provision (benefit)	119,560		(1,919,328)
Deferred:
Federal	(3,987,211)		(266,482)
State	(1,116,610)		4,814
Total deferred income tax provision (benefit)	(5,103,821)		(261,668)
Total income tax provision (benefit)	$	(4,984,261)	$	(2,180,996)

For the years ended June 30, 2021 and 2020, respectively, we recognized an income tax benefit of $5.0 million and an income tax benefit of $2.2 million reflecting corresponding effective tax rates of 23.3% and (58.1)%, respectively. During the fiscal 2020 year we undertook a project to seek potential cash tax savings opportunities identifying available Enhanced Oil Recovery credits (“EOR credits”) related to our interests in the Delhi field. To take advantage of the EOR credits, we amended federal and state tax returns for the years ended June 30, 2017 and 2018 and incorporated the associated impacts into our 2019 tax returns. Principally as a result of the EOR credits, the Company recorded a net tax benefit of $2.8 million during fiscal 2020. Relative to the foregoing, the Company has a $3.1 million receivable for income tax refunds at June 30, 2021, which the Company currently anticipates to receive in the next twelve months based on inquiries and communication with the IRS, although no assurances can be made as to the actual date of receipt. During fiscal 2021, we recognized an income tax benefit of $0.3 million attributable to the EOR credit.

Our effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the State of Louisiana, and differences related to percentage depletion in excess of basis, stock-based compensation, valuation allowance on deferred tax assets, and other permanent differences. The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate to the income tax provision (benefit) in our financial statements.


	June 30, 2021		% of Income Before Income Taxes		June 30, 2020		% of Income Before Income Taxes
Income tax provision (benefit) computed at the statutory federal rate:	$	(4,498,661)	21.0	%	$	788,776	21.0	%
Reconciling items:
Return to provision adjustments	20,036		(0.1)	%	(2,823,527)		(75.2)	%
Depletion in excess of tax basis	(175,840)		0.8	%	(412,215)		(11.0)	%
State income taxes, net of federal tax benefit	(523,436)		2.4	%	272,962		7.3	%
Permanent differences related to stock-based compensation and other	55,278		(0.3)	%	22,408		0.6	%
Federal valuation allowance	570,064		(2.7)	%	—		—	%
EOR credit benefit	(335,717)		1.6	%	—		—	%
Other	(95,985)		0.6	%	(29,400)		(0.8)	%
Income tax provision (benefit)	$	(4,984,261)	23.3	%	$	(2,180,996)	(58.1)	%

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.


	Asset (Liability)
	June 30, 2021		June 30, 2020
Deferred tax assets:
Non-qualified stock-based compensation	$	309,671	$	234,559
Net operating loss carry-forwards and other carry-forwards	365,279		78,197
Derivative losses	—		401,382
Asset retirement obligations (a)	1,284,907		650,042
Other deferred tax assets	160,313		53,159
Gross deferred tax assets	2,120,170		1,417,339
Valuation allowance	(861,838)		(53,218)
Net deferred tax assets	1,258,332		1,364,121
Deferred tax liability:
Oil and natural gas properties (a)	(7,215,534)		(12,425,144)
Total deferred tax liability	(7,215,534)		(12,425,144)

Net deferred tax liability	$	(5,957,202)	$	(11,061,023)

(a) Certain deferred tax assets related to asset retirement obligations have been reclassified from the June 30, 2020 oil and natural gas properties deferred tax liability balance in order to conform to the current year presentation.

As of June 30, 2021, we had a federal tax loss carryforward of approximately $0.6 million that we acquired through a reverse merger in May 2004. The majority of the tax loss carryforwards from the reverse merger expired without being utilized. We will be able to utilize a maximum of $0.2 million of these carryforwards in equal annual amounts of $39,648 through 2023 and the balance is not able to be utilized based on the provisions of Internal Revenue Code (“IRC”) Section 382. We have recorded a valuation allowance for the portion of our net operating loss that is limited by IRC Section 382.

In addition, we must assess the likelihood that we will be able to realize our deferred tax assets. Realization is dependent on generating sufficient taxable income over the period the deferred tax assets are deductible. Given the Company is in a cumulative loss position, Management considered the reversal of deferred tax liabilities and tax planning strategies in making

the assessment of the realization of deferred tax assets. Based upon the weight of available evidence, the Company believes that some of the deferred tax assets are not likely to be realized at the time of this report and have recorded an increase in the valuation allowance during the current year related to the federal and state deferred tax assets of $0.6 million and $0.2 million respectively.

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

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Earnings (Loss) per Common Share

Earnings (Loss) per Common Share

12 Months Ended

Jun. 30, 2021

Earnings Per Share [Abstract]

The following table sets forth the computation of basic and diluted net income per share:


	June 30,
	2021		2020
Numerator
Net income (loss) attributable to common stockholders	$	(16,437,934)	$	5,937,072
Denominator
Weighted average number of common shares – Basic	33,263,701		33,031,149
Effect of dilutive securities:
Contingent restricted stock grants	—		1,942


Weighted average number of common shares and dilutive potential common shares used in diluted earnings (loss) per share	33,263,701		33,033,091
Net earnings (loss) per common share – Basic	$	(0.49)	$	0.18
Net earnings (loss) per common share – Diluted	$	(0.49)	$	0.18


Outstanding Potentially Dilutive Securities	Weighted Average Exercise Price		Outstanding at June 30, 2021
Contingent Restricted Stock grants	$	—	323,080


Outstanding Potential Dilutive Securities	Weighted Average Exercise Price		Outstanding at June 30, 2020
Contingent Restricted Stock grants	$	—	200,000

Senior Secured Credit Agreement	12 Months Ended
Senior Secured Credit Agreement	Jun. 30, 2021
Debt Disclosure [Abstract]
Senior Secured Credit Agreement	Senior Secured Credit Agreement On April 11, 2016, the Company entered into a three-year, senior secured reserve-based credit facility (the “Senior Secured Credit Facility”) in an amount up to $50 million. On May 25, 2018, we entered into the third amendment to our credit agreement governing the Facility to, among other things, extend the maturity date to April 11, 2021. On December 31, 2018, we entered into the fourth amendment to our credit agreement governing the Senior Secured Credit Facility to broaden the definition for the Use of Proceeds. Under the Senior Secured Credit Facility the borrowing base is redetermined semiannually. On November 2, 2020, the Company completed its Fall redetermination of the Senior Secured Credit Facility, resulting in a borrowing base of $23 million, and entered into the fifth amendment to the Senior Secured Credit Facility extending the maturity to April 9, 2024. On January 5, 2021 and effective as of December 28, 2020, we entered into the sixth amendment of our Senior Secured Credit Facility which replaced the Debt Service Coverage Ratio (as defined therein) maintenance covenant with a new covenant requiring Current Ratio (as defined therein) of not less than 1.00 to 1.00. On March 30, 2021, the Company completed its spring redetermination of the Senior Secured Credit Facility, resulting in a borrowing base increase to $30 million. On August 5, 2021, and effective as of June 30, 2021, we entered into the seventh amendment of our Senior Secured Credit Facility which added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the Consolidated Tangible Net Worth was reduced to $40 million from $50 million. We were in compliance with all financial covenants and there was $4 million outstanding under the Senior Secured Credit Facility at June 30, 2021 which is secured by substantially all of the Company's assets. Borrowings from the Senior Secured Credit Facility may be used for the acquisition and development of oil and natural gas properties, investments in cash flow generating assets complimentary to the production of oil and natural gas, and for letters of credit and other general corporate purposes. The Senior Secured Credit Facility included a placement fee of 0.50% on the initial borrowing base amounting to $50,000,000 and carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Senior Secured Credit Facility will bear interest, at the Company’s option, at either LIBOR plus 2.75%, subject to a minimum LIBOR of 0.25%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%. The Senior Secured Credit Facility contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (a) a maximum total leverage ratio of not more than 3.00 to 1.00, (b) a current ratio of not less than 1.00 to 1.00, and (c) a consolidated tangible net worth of not less than $40 million, all as defined under the Senior Secured Credit Facility. In connection with the Senior Secured Credit Facility, the Company has incurred $168,972 of past debt issuance costs. Such costs were capitalized in "Other assets, net" and have been completely amortized to expense as of June 30, 2021.

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

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Concentrations of Credit Risk

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Jun. 30, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and ContingenciesWe are subject to various claims and contingencies in the normal course of business. In addition, from time to time, we receive communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdictions in which we operate. At a minimum, we disclose such matters if we believe it is reasonably possible that a future event or events will confirm a material loss through impairment of an asset or the incurrence of a liability. We accrue a material loss if we believe it is probable that a future event or events will confirm a loss, we can reasonably estimate such loss, and we do not accrue future legal costs related to that loss. Furthermore, we will disclose any matter that is unasserted if we consider it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable and material in amount. We expense legal defense costs as they are incurred.

Concentrations of Credit Risk

12 Months Ended

Jun. 30, 2021

Risks and Uncertainties [Abstract]

Major Customers. As a non-operator, we presently market our production through the field operators. The majority of our natural gas, oil, and condensate production is sold to purchasers under short-term (less than 12 months) contracts at market-based prices. The following table identifies customers from whom we derived 10 percent or more of our net oil and natural gas revenues during the years ended June 30, 2021 and 2020. The loss of either one of our oil purchasers or disruption to their respective pipelines could adversely affect our net realized pricing and potentially our near-term production levels. The loss of our NGL purchaser, who trucks NGLs from the field, would not be expected to have a material adverse effect on our operations.


	Year Ended June 30,
Customer	2021		2020
Plains Marketing L.P. (Delhi field oil)	62	%	87	%
Merit Energy Company (Hamilton Dome field oil)	19	%	10	%
All others	19	%	3	%
Total	100	%	100	%

Accounts Receivable. Substantially all of our accounts receivable from field operators result from oil and natural gas sales to third-parties in the oil and natural gas industry. Our concentration of customers in this industry may impact our overall credit risk.

Cash and Cash Equivalents. We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents in high quality money market funds. At times, cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation (“FDIC”).

Derivatives

12 Months Ended

Jun. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

DerivativesIt is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or commodity hedging institutions deemed by management as competent and competitive market makers. As of June 30, 2021, the Company did not have any remaining open derivative contracts.

The Company has in the past and may utilize in the future fixed-price swaps or costless put/call collars to hedge a portion of its anticipated future production. Fixed-price swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for the volumes under contract. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract, and a purchased put that establishes a minimum price. The Company has elected not to designate its open derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of the derivative contracts and all payments and receipts on settled derivative contracts in “Net (gain) loss on derivative contracts” on the consolidated statements of operations.


	Years Ended June 30,
	2021		2020
Realized (gain) loss	$	2,525,988	$	(528,139)
Unrealized (gain) loss	(1,911,343)		1,911,343
Net (gain) loss on derivative contracts	$	614,645	$	1,383,204

The Company’s derivative contract is recorded at fair market value and is included in the consolidated balance sheets as an asset or a liability. The Company did not have any open positions as of June 30, 2021.

The following sets forth a summary of the Company’s oil derivative positions during the year ended June 30, 2021.

Period

Type of Contract

Volumes in Barrels

Price / Price Range

Weighted Average Floor Price per Bbl.

Weighted Average Ceiling Price per Bbl.

July 2020 to December 2020

Fixed-Price Swap

257,600

$32

$—

The Company nets its derivative instrument fair value amounts executed with the same counterparty. The Company enters into an ISDA with each counterparty prior to a derivative contract with such counterparty. The ISDA is a standard contract that governs all derivative contracts entered into between the Company and the respective counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of both parties, for transactions that occur on the same date and in the same currency.

Fair Value Measurement	12 Months Ended
Fair Value Measurement	Jun. 30, 2021
Fair Value Disclosures [Abstract]
Fair Value Measurement	Fair Value Measurement Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities. Level 2—Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Level 3—Unobservable inputs for which there are little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities. Fair Value of Derivative Instruments. The Company’s determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC 820 – Fair Value Measurement (“ASC 820”) establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs are generally market corroborated (Level 2), and the Company classifies fair value balances as such. There were no open positions as of June 30, 2021, and there were $1.9 million of open positions as of June 30, 2020 which were all settled during the current fiscal year. As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment; this may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period presented in this report. The Company did not have any open positions as of June 30, 2021. Other Fair Value Measurements. The initial measurement and any subsequent revision of asset retirement obligations at fair value are calculated using discounted future cash flows of internally estimated costs. Significant Level 3 inputs used in the calculation of asset retirement obligations include the costs of plugging and abandoning wells, surface restoration, and reserve lives. Subsequent to initial recognition, revisions to estimated asset retirement obligations are made when changes occur for input values.

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited)

12 Months Ended

Jun. 30, 2021

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited)

Costs incurred for oil and natural gas property acquisition, exploration, and development activities

The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration, and development activities. Property acquisition costs are those costs incurred to lease property, including both undeveloped leasehold, and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination, examining specific areas that are considered to have prospects containing oil and natural gas reserves, costs of drilling exploratory wells, geologic and geophysical assessment costs, and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling. Development costs also include amounts incurred due to the recognition of asset retirement obligations of $2,883,426 and $918,137 during the years ended June 30, 2021 and 2020, respectively.


	For the Years Ended June 30,
	2021		2020
Oil and Natural Gas Activities
Property acquisition costs:
Proved property	$	18,297,013	$	9,337,716
Unproved property	—		—
Exploration costs	—		—
Development costs	3,435,836		2,430,510
Total costs incurred for oil and natural gas activities	$	21,732,849	$	11,768,226

Estimated Net Quantities of Proved Oil and Natural Gas Reserves

The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the United States of America are based on evaluations prepared by third-party reservoir engineers, D&M. Reserve volumes and values were determined under the method prescribed by the SEC for our fiscal years ended June 30, 2021 and 2020. SEC methodology requires the application of the previous 12 months unweighted arithmetic average first-day-of-the-month price, and current costs held constant throughout the projected reserve life, when estimating whether reserve quantities are economical to produce.

Proved oil and natural gas reserves are estimated quantities of oil, natural gas, and natural gas liquids that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in estimating quantities of proved oil and natural gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

Estimated quantities of proved oil, natural gas, and natural gas liquids reserves and changes in quantities of proved developed and undeveloped reserves for each of the periods indicated are as follows:


	Oil (Bbls)	NGLs (Bbls)	Natural Gas (Mcf)	BOE
Proved developed and undeveloped reserves:
June 30, 2019	7,615,731	1,364,761	—	8,980,492
Revisions of previous estimates (a)	(2,177,787)	734,169	—	(1,443,618)
Improved recovery, extensions and discoveries	—	—	—	—
Sales of minerals in place	—	—	—	—
Purchase of reserves in place (c)	3,426,756	—		3,426,756
Production (sales volumes)	(638,464)	(106,340)	—	(744,804)
June 30, 2020	8,226,236	1,992,590	—	10,218,826
Revisions of previous estimates (b)	661,711	93,139	330	754,905
Improved recovery, extensions and discoveries	—	—	—	—
Purchase of reserves in place (c)	86,608	4,957,226	49,533,801	13,299,468
Sales of minerals in place	—	—	—	—
Production (sales volumes)	(554,888)	(171,451)	(963,496)	(886,922)
June 30, 2021	8,419,667	6,871,504	48,570,635	23,386,277
Proved developed reserves:
June 30, 2019	6,273,907	1,124,302	—	7,398,209
June 30, 2020	6,577,731	1,777,236	—	8,354,967
June 30, 2021	6,815,126	6,662,952	48,570,634	21,573,184
Proved undeveloped reserves:
June 30, 2019	1,341,824	240,459	—	1,582,283
June 30, 2020	1,648,505	215,354	—	1,863,859
June 30, 2021	1,604,541	208,551	—	1,813,092

(a) Revisions in fiscal year 2020 were primarily due to negative revisions at Hamilton Dome field reflecting the impact of pricing on future economic production. In March 2020 when the oil price decreased, the operator began to shut-in wells that were not economic at those lower prices to try and keep the field cash flow positive. The use of an SEC price deck for our reserves at June 30, 2020, precludes volumes that are uneconomic at such prices. Positive NGL revisions at Delhi field reflect adjusted methodology of forecasting NGLs independently from the oil production as forecasted by our independent reservoir engineering firm.

(b) Revisions in fiscal year 2021 were primarily due to positive revisions at Hamilton Dome reflecting the impact of increased oil pricing in the field on future production and extension of reserves economic limit. Positive NGL revisions at Delhi field reflect the impact of increased pricing on future production and the extension of reserves economic limit. Positive natural gas revisions in the Barnett Shale reflect the impact of increased natural gas prices from the date of the Barnett Shale Acquisition on May 7, 2021 to the end of the fiscal year on June 30, 2021.

(c) On May 7, 2021, the Company acquired the Barnett Shale assets from Tokyo Gas Americas for $18.3 million, net of preliminary purchase price adjustments. On November 1, 2019, the Company acquired certain mineral interests in the Hamilton Dome field from Merit, who owns the vast majority of the remaining working interest in the field.

Standardized Measure of Discounted Future Net Cash Flows

Future oil and natural gas sales, production, and development costs have been estimated using prices and costs in effect at the end of the years indicated, as required by ASC 932, Extractive Activities - Oil and Gas (“ASC 932”). ASC 932 requires that net cash flow amounts be discounted at 10%. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing our proved oil and natural gas reserves and for asset retirement obligations, assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to our proved oil and natural gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the

impact of general and administrative costs of ongoing operations relating to the Company's proved oil and natural gas reserves. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. The table below should not be construed to be an estimate of the current market value of our proved reserves.

The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2021 and 2020 are as follows:


	As of June 30,
	2021		2020
Future cash inflows	$	632,620,246	$	399,358,481
Future production costs and severance taxes	(398,021,728)		(240,399,715)
Future development costs	(29,339,399)		(24,623,426)
Future income tax expenses	(42,368,085)		(21,982,469)
Future net cash flows	162,891,034		112,352,871
10% annual discount for estimated timing of cash flows	(75,308,483)		(49,862,035)
Standardized measure of discounted future net cash flows	$	87,582,551	$	62,490,836

Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the previous 12 months unweighted arithmetic average first-day-of-the-month commodity prices for each year and reflect adjustments for lease quality, transportation fees, energy content, and regional price differentials.


	For the Years Ended June 30,
	2021				2020
	Oil (Bbl)		Gas (MMBtu)		Oil (Bbl)		Gas (MMBtu)
NYMEX prices used in determining future cash flows	$	49.72	$	2.46	$	47.37	n/a

There were no natural gas reserves in 2020. The NGL prices utilized for future cash inflows were based on historical prices received, where available. For the Delhi NGL plant, we utilized historical prices for the expected mix and net pricing of natural gas liquid products projected to be produced by the plant.

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil, natural gas, and natural gas liquids reserves is as follows:


	For the Years Ended June 30,
	2021		2020
Balance, beginning of the fiscal year	$	62,490,836	$	126,732,042
Net changes in sales prices and production costs related to future production	11,538,209		(83,857,342)
Changes in estimated future development costs	403,109		(4,099,792)
Sales of oil and gas produced during the period, net of production costs	(16,115,302)		(16,093,794)
Net change due to extensions, discoveries, and improved recovery	—		—
Net change due to revisions in quantity estimates	6,840,767		(6,746,316)
Net change due to purchase of minerals in place	31,461,405		10,364,875
Development costs incurred during the period	—		1,431,444
Accretion of discount	7,529,289		16,266,663
Net change in discounted income taxes	(10,678,450)		17,078,591
Net changes in timing of production and other	(5,887,312)		1,414,465
Balance, end of the fiscal year	$	87,582,551	$	62,490,836

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Jun. 30, 2021

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data (Unaudited)


2021	First (a)		Second (b)		Third		Fourth (c)
Revenues	$	5,595,376	$	5,768,152	$	7,635,748	$	13,703,078
Income (loss) from operations	$	(9,429,720)	$	(15,910,266)	$	980,605	$	3,000,750
Net income (loss) attributable to common shareholders	$	(7,135,148)	$	(12,710,007)	$	1,191,001	$	2,216,220
Basic earnings (loss) per common share	$	(0.22)	$	(0.38)	$	0.04	$	0.07
Diluted earnings (loss) per common share	$	(0.22)	$	(0.38)	$	0.04	$	0.07


2020	First		Second		Third (d)		Fourth
Revenues	$	9,152,215	$	9,381,615	$	7,712,619	$	3,352,847
Income (loss) from operations	$	3,274,019	$	2,249,764	$	951,814	$	(2,786,164)
Net income (loss) attributable to common shareholders	$	2,792,820	$	1,764,918	$	3,710,159	$	(2,330,825)
Basic earnings per common share	$	0.08	$	0.05	$	0.11	$	(0.07)
Diluted earnings per common share	$	0.08	$	0.05	$	0.11	$	(0.07)

(a) The first quarter of fiscal 2021 included a ceiling test impairment charge of $9.6 million.

(b) The second quarter of fiscal 2021 included a ceiling test impairment charge of $15.2 million.

(c) The fourth quarter of fiscal 2021 includes approximately two months of production and related revenues and expenses from the Barnett Shale assets.

(d) The third quarter of fiscal 2020 was impacted by a $2.8 million tax benefit attributable to the EOR tax credits.

Subsequent Events	12 Months Ended
Subsequent Events	Jun. 30, 2021
Subsequent Events [Abstract]
Subsequent Events	Subsequent EventsOn August 5, 2021, and effective as of June 30, 2021, we entered into the seventh amendment of our Senior Secured Credit Facility which added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests EBITDA Adjustment.” Additionally, the Consolidated Tangible Net Worth was reduced to $40 million from $50 million. On September 9, 2021, the Company declared a quarterly cash dividend of $0.075 per share of common stock to shareholders of record on September 20, 2021 and payable on September 30, 2021.

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Jun. 30, 2021
Accounting Policies [Abstract]
Principles of Consolidation and Reporting	Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of Evolution Petroleum Corporation and its wholly-owned subsidiaries (the “Company”). All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year may include certain reclassifications to conform to the current presentation. Any such reclassifications have no impact on previously reported net income or stockholders' equity.
Risk and Uncertainties	Risk and Uncertainties. The Company is continuously monitoring impacts of the COVID-19 pandemic on its business, including how it has and may continue to impact its financial results, liquidity, employees, and the operations of the Delhi field, Hamilton Dome fields, and its Barnett Shale assets in which it holds non-operated interests. In response to the pandemic, the operator at Hamilton Dome temporarily shut-in some producing wells. In addition to the above, the pandemic slowed the repair schedule of the Delhi CO2 supply pipeline which, together with the foregoing, negatively impacted our production. All of the Company’s property interests are not operated by the Company and involve other third-party working interest owners. As a result, the Company has limited ability to influence or control the operation or future development of such properties. However, the Company has been proactive with its third-party operators to review spend and alter plans as appropriate. The Company is focused on putting long term measures to prevent future disruptions, maintaining its operations and system of controls remotely and has implemented its business continuity plans in order to allow its employees to securely work from home or in the corporate office. The Company was able to transition the operation of its business with minimal disruption and has maintained its system of internal controls and procedures.
Use of Estimates	Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include (a) reserve quantities and estimated future cash flows associated with proved reserves, which may significantly impact depletion expense and potential impairments of oil and natural gas properties, (b) asset retirement obligations, (c) stock-based compensation, (d) fair values of derivative assets and liabilities, (e) income taxes and the valuation of deferred tax assets, (f) commitments and contingencies and (g) oil, natural gas, and NGL revenues. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents. We consider all highly liquid investments, with original maturities of 90 days or less when purchased, to be cash and cash equivalents.
Restricted Cash	Restricted Cash. Funds legally designated for a specified purpose are classified as restricted cash. Such a balance is classified on the statement of financial position as either current or non-current depending on its expected use.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable consist of accrued hydrocarbon revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2021 and 2020, no allowance for doubtful accounts was considered necessary.
Oil and Natural Gas Properties	Oil and Natural Gas Properties. We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs that are directly related to property acquisition, exploration, and development activities but does not include any costs related to production, general corporate overhead, or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.Oil and natural gas properties include costs that are excluded from depletion and amortization, which represent investments in unproved and unevaluated properties and include non-producing leasehold, geologic and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. These costs are excluded until the project is evaluated and proved reserves are established or impairment is determined. As of June 30, 2021 and 2020, we did not have any costs excluded from depletion and amortization.
Limitation on Capitalized Costs	Limitation on Capitalized Costs. Under the full-cost method of accounting, we are required, at the end of each fiscal quarter, to perform a test to determine the limit on the book value of our oil and natural gas properties (the “Ceiling Test”). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the “Ceiling”, this excess or impairment is charged to expense and reflected as additional accumulated depreciation, depletion, and amortization or as a credit to oil and natural gas properties. The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10 percent and assuming continuation of existing economic conditions, of 1) estimated future gross revenues from proved reserves, which is computed using oil and natural gas prices determined as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period (with consideration of price changes only to the extent provided by contractual arrangements including hedging arrangements pursuant to SAB 103), less 2) estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves; plus (b) the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)); plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; net of (d) the related tax effects related to the difference between the book and tax basis of our oil and natural gas properties.
Other Property and Equipment	Other Property and Equipment. Other property and equipment includes building leasehold improvements, data processing and telecommunications equipment, office furniture, and office equipment. These items are recorded at cost and depreciated over expected lives of the individual assets or group of assets, which range from three to seven years. The assets are depreciated using the straight-line method. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. Repairs and maintenance costs are expensed in the period incurred.
Deferred Financing Costs	Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in other assets on the Company's consolidated balance sheet and are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method.
Asset Retirement Obligations	Asset Retirement Obligations. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred. It is associated with an increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The initial recognition or subsequent revision of asset retirement cost is considered a Level 3 fair value measurement. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment.
Fair Value of Financial Instruments	Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivative instruments, and debt. Except for derivatives, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable are short-term instruments and approximate fair value due to their highly liquid nature. The carrying amount of debt approximates fair value as the variable rates on the Senior Secured Credit Facility are market interest rates. The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and natural gas, discount rates, and volatility factors.
Stock-based Compensation	Stock-based Compensation. We estimate the fair value of stock-based compensation awards on the grant date to provide the basis for future compensation expense. Service-based and performance-based Restricted Stock and Contingent Restricted Stock awards (as defined in Note 11 - Stock-Based Incentive Plan) are valued using the market price of our common stock on the grant date. Market-based awards are valued using a Monte Carlo simulation and geometric Brownian motion techniques applied to the historical volatility of the Company's total stock return compared to the historical volatilities of other companies or indices to which we compare our performance. This Monte Carlo simulation also provides an expected vesting period. For service-based awards, stock-based compensation is recognized ratably over the service period. For performance-based awards, stock-based compensation is recognized ratably over the expected vesting period when it is deemed probable, for accounting purposes, that the performance goal will be achieved. The expected vesting period may be shorter than the remaining term. For market-based awards, stock-based compensation expense is recognized ratably over the expected vesting period, so long as the award holder remains an employee of the Company. Total compensation expense is independent of vesting or expiration of the awards, except for termination of service.
Revenue Recognition - Oil and Natural Gas	Revenue Recognition - Oil and Natural Gas. Our revenues are comprised solely of revenues from customers from the sale of oil, natural gas, and natural gas liquids. The Company believes that the disaggregation of revenue on its consolidated statements of operations into these three major product types appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors based on our geographic locations. Oil, natural gas, and natural gas liquids revenues are recognized at a point in time when production is sold to a purchaser at an index-based, determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue is a function of the contract billing terms which reference index price sources used by the industry. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required within 30 days for oil and 60 days for natural gas and natural gas liquids after the end of the production month. At the end of each month when the performance obligations have been satisfied, the consideration can be reasonably estimated and amounts due from customers (remitted to us by field operators) are accrued in “Receivables from oil and gas sales” in our consolidated balance sheets.
Derivative Instruments	Derivative Instruments. The Company follows ASC 815, Derivatives and Hedging (“ASC 815”). From time to time, in accordance with the Company’s policy, it may hedge a portion of its forecasted oil, natural gas, and natural gas liquids production. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to an International Swap Dealers Association Master Agreement (“ISDA”) master agreement; the agreement provides for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. Accordingly, the Company records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled contracts, in “Net (gain) loss on derivative instruments” on the consolidated statements of operations.
Estimates of Proved Reserves	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.
Depreciation, Depletion and Amortization (“DD&A”)	Depreciation, Depletion, and Amortization (“DD&A”). The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of DD&A, estimated future development costs, and asset retirement costs (net of salvage values) not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves. Other property, consisting of leasehold building improvements and office and computer equipment, is depreciated as described above in Other Property and Equipment.
Income Taxes	Income Taxes. We recognize deferred tax assets and liabilities based on the differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that may result in taxable or deductible amounts in future years. The measurement of deferred tax assets may be reduced by a valuation allowance based upon management's assessment of available evidence if it is deemed more likely than not that some or all of the deferred tax assets will not be realizable. We recognize a tax benefit from an uncertain position when it is more likely than not that the position will be sustained upon examination which is based on the technical merits of the position. We record the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax expense.
Earnings (Loss) Per Share	Earnings (Loss) Per Share. Basic earnings (loss) per share (“EPS”) is computed by dividing earnings or loss available to common stockholders by the weighted-average number of common shares outstanding during the period. The computation of diluted EPS is similar to the computation of basic EPS, except that the denominator is increased to include the number of additional common shares that would have been outstanding if potentially dilutive common shares had been issued. Potentially dilutive common shares are our contingent restricted common stock. We use the treasury stock method to determine the effect of potentially dilutive common shares on diluted EPS, unless the effect would be anti-dilutive. Under this method, exercise of contingent restricted common stock, under certain condition, is assumed to have occurred at the beginning of the period (or at time of issuance, if later); common shares are assumed to have been issued. The unamortized stock compensation expense related to restricted common stock are assumed to be used to repurchase common stock at the average market price during the period. The incremental shares (the difference between the number of shares assumed issued and the number of shares assumed repurchased) are included in the denominator of the diluted EPS computation. Contingent restricted stock is included in the computation of diluted shares, if dilutive, when the underlying performance conditions either (i) were satisfied as of the end of the reporting period or (ii) would be considered satisfied if the end of the reporting period were the end of the related contingency period.
Recently Adopted and Issued Accounting Pronouncements	Recently Adopted Accounting Pronouncements Leases. Effective July 1, 2019, the Company adopted the new standard using a modified retrospective approach and elected to use the optional transition methodology whereby reporting periods prior to adoption continue to be presented in accordance with legacy accounting guidance, Accounting Standard Codification 840 - Leases. Upon transition, we recognized a right of use (“ROU”) asset (or operating lease right-of-use asset) and an operating lease liability with no retained earnings impact. We applied the following practical expedients as provided in the standards update which provide elections to not reassess: •Not to apply the recognition requirements in the lease standard to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option that the Company is reasonably certain to exercise). •Whether an expired or existing pre-adoption date contracts contained leases. •Lease classification of any expired or existing leases. •Initial direct costs for any expired or existing leases. •Not to separate lease components from non-lease components in a contract and accounting for the combination as a lease (reflected by asset class). Adoption of the new standard did not impact our consolidated statements of operations, cash flows or stockholders’ equity. Income Taxes. In December 2019, the FASB issued Accounting Standards Update (ASU) 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (ASU 2019-12) as part of its initiative to reduce complexity in the accounting standards. The amendments in ASU 2019-12 remove certain exceptions related to the incremental approach for intraperiod tax allocation and the general methodology for calculating income taxes in an interim period and reducing diversity in practice for the recognition of enacted changes in tax law. ASU 2019-12 also clarifies and simplifies other aspects of accounting for income taxes. ASU 2019-12 is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2020; however, early adoption is permissible for periods for which financial statements have not yet been issued. Effective October 1, 2020, the Company prospectively adopted this new standard. Adoption of this standard had no impact on our consolidated financial statements nor would it have had if we had adopted the standard on July 1, 2020. Recently Issued Accounting Pronouncements In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. Early adoption is permitted and entities must adopt the amendment using a modified retrospective approach to the first reporting period in which the guidance is effective. For smaller reporting companies, as provided by Accounting Standards Update 2019-10, Financial Instruments - Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842), ASU 2016-13 is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2022. The adoption of ASU 2016-13 is currently not expected to have a material effect on our consolidated financial statements. Other accounting pronouncements that have recently been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company's financial position, results of operations, or cash flows.

Revenue Recognition (Tables)

12 Months Ended

Jun. 30, 2021

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

Additionally, an overriding royalty interest retained in a past divestiture of Texas properties provided de minimis revenue:


	June 30,
	2021		2020
Revenues
Oil	$	26,411,132	$	28,578,879
Natural gas liquids	3,662,478		1,018,349
Natural gas	2,628,744		2,068
Total revenues	$	32,702,354	$	29,599,296

Leases (Tables)

12 Months Ended

Jun. 30, 2021

Leases [Abstract]

Schedule of future minimum lease commitments under the operating lease

At June 30, 2021, maturities of our operating lease liability are as follows:


Fiscal Year	Operating Lease Liability
2022	61,843
2023	26,098
Total lease payments	87,941
Less imputed interest	(2,962)
Total lease liability	$	84,979

Supplemental cash flow, balance sheet and other information

Supplemental cash flow, balance sheet, and other disclosures information related to our operating leases are as follows:


	As of and For the Year Ended June 30, 2021			As of and For the Year Ended June 30, 2020
Cash Flow:
Cash paid for amounts included in the measurement of lease liabilities	$	59,945		$	4,903
ROU asset added in exchange for lease obligation at adoption	—			161,125

Balance Sheet:
Operating lease ROU asset (included in other assets)	70,789			117,193
Accrued liabilities - current	64,234			54,290
Operating lease liability - long-term	20,745			84,978

Other:
Weighted average remaining lease term in years	1.34			2.66
Weighted average discount rate	5.15		%	5.15		%

Prepaid Expenses and Other Current Assets (Tables)

12 Months Ended

Jun. 30, 2021

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Schedule of prepaid expenses and other current assets


	June 30, 2021		June 30, 2020
Prepaid insurance	$	365,922	$	289,999
Prepaid subscription and licenses	108,048		67,005
Prepaid federal and state income taxes	97,470		86,208
Carryback of EOR tax credit	416,441		—
Prepaid other	49,378		48,474
Total prepaid expenses and other current assets	$	1,037,259	$	491,686

Property and Equipment, Net of Depreciation, Depletion, and Amortization (Tables)

12 Months Ended

Jun. 30, 2021

Property, Plant and Equipment [Abstract]

Schedule of oil and natural gas properties and other property and equipment


	June 30, 2021		June 30, 2020
Oil and natural gas properties:
Property costs subject to amortization	$	129,123,227	$	107,390,379
Less: Accumulated depreciation, depletion, and amortization and impairment (a)	(70,607,367)		(40,878,098)
Unproved properties not subject to amortization	—		—
Oil and natural gas properties, net	58,515,860		66,512,281
Other property and equipment:
Furniture, fixtures, and office equipment, at cost	154,731		154,731
Less: Accumulated depreciation (b)	(144,092)		(137,092)
Other property and equipment, net	$	10,639	$	17,639

(b) Depreciation was $7,000 for fiscal 2021 and $8,779 for fiscal 2020.

Other Assets, Net (Tables)

12 Months Ended

Jun. 30, 2021

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Schedule of other assets


	June 30, 2021		June 30, 2020
Royalty rights	—		108,512
Less: Accumulated amortization of royalty rights	—		(61,037)
Investment in Well Lift Inc., at cost	—		108,750
Deferred loan costs	168,972		168,972
Less: Accumulated amortization of deferred loan costs	(168,972)		(157,084)
Right of use asset under operating lease	161,125		161,125
Less: Accumulated amortization of right of use asset	(90,336)		(43,932)
Software license	20,662		20,662
Less: Accumulated amortization of software license	(20,662)		(14,350)
Other assets, net	$	70,789	$	291,618

Accrued Liabilities and Other (Tables)

12 Months Ended

Jun. 30, 2021

Other Liabilities Disclosure [Abstract]

Other Current Liabilities


	June 30, 2021		June 30, 2020
Accrued incentive and other compensation	$	630,744	$	176,636
Accrued retirement costs	52,786		—
Accrued franchise taxes	35,207		100,978
Accrued ad valorem taxes	108,000		108,000
Payable for settled derivatives	—		265,188
Operating lease liability, current	64,234		54,290
Asset retirement obligations due within one year	44,520		—
Accrued - other	11,554		11,556
Total Accrued liabilities and other	$	947,045	$	716,648

Asset Retirement Obligations (Tables)

12 Months Ended

Jun. 30, 2021

Asset Retirement Obligation Disclosure [Abstract]

Schedule of reconciliation of the beginning and ending asset retirement obligation

The following is a reconciliation of the beginning and ending asset retirement obligations for the years ended June 30, 2021 and 2020:


	Years Ended
	2021			2020
Asset retirement obligations — beginning of period	$	2,588,894		$	1,610,845
Liabilities incurred	—			40,698
Liabilities settled	(99,231)		(a)	(86,592)
Liabilities acquired	2,806,331		(b)	903,580
Accretion of discount	210,182			146,504
Revisions of previous estimates	77,096		(c)	(26,141)
Asset retirement obligations — end of period	5,583,272			2,588,894
Less: current asset retirement obligations	44,520			—
Long-term portion of asset retirement obligations	$	5,538,752		$	2,588,894

(a) Abandonment of two non-scheduled Delhi field wells in fiscal 2021, and abandonment of one Delhi field well and four Hamilton Dome field wells in fiscal 2020.

(b) Liabilities acquired in fiscal 2021 and 2020 were primarily due to our acquisition of the Barnett Shale interest and the Hamilton Dome interest, respectively.

Stockholders' Equity (Tables)

12 Months Ended

Jun. 30, 2021

Equity [Abstract]

Dividends declared and paid

The following table reflects the dividends paid within the respective three-month periods:


	Fiscal Year
	2021	2020
Fourth quarter ended June 30,	$0.050	$0.025
Third quarter ended March 31,	$0.030	$0.100
Second quarter ended December 31,	$0.025	$0.100
First quarter ended September 30,	$0.025	$0.100

Schedule of share repurchases

The following table shows all treasury stock purchases in the last two fiscal years:


	Common Shares Acquired	Average Price per Share		Treasury Stock Purchases
Year Ended June 30, 2021:
Shares surrendered for tax withholding upon vesting	2,632	$	2.79	$	7,347
Share repurchase program	—	$	—	—
Total	2,632	$	2.79	$	7,347

Year Ended June 30, 2020:
Shares surrendered for tax withholding upon vesting	9,255	$	5.90	$	54,565
Share repurchase program	440,666	$	5.51	2,428,792
Total	449,921	$	5.52	$	2,483,357

Stock-Based Incentive Plan (Tables)

12 Months Ended

Jun. 30, 2021

Share-based Payment Arrangement [Abstract]

Schedule of Valuation Assumptions

June 30, 2021 and 2020, the assumptions used in the Monte Carlo simulation valuations, expected lives and fair values were as follows:


	Year Ended June 30,
	2021			2020

Weighted average fair value of market-based awards granted	$	3.08		$	3.79
Risk-free interest rate	0.23		%	1.65% to 1.87%
Expected life in years	2.56			1.35 to 2.56
Expected volatility	56.9		%	38.6% to 43.7%
Dividend yield	3.2		%	6% to 7.2%

Schedule of Restricted Stock transactions

Unvested Restricted Stock awards at June 30, 2021 consisted of the following:


Award Type	Number of Restricted Shares	Weighted Average Grant-Date Fair Value
Service-based awards	348,762	$	3.37

Market-based awards	320,533	3.38
Unvested at June 30, 2021	669,295	$	3.37

The following table sets forth the Restricted Stock transactions for the year ended June 30, 2021:


	Number of Restricted Shares	Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2021		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2020	285,028	$	5.53	$	—
Service-based shares granted	365,479	2.97

Market-based shares granted	246,160	3.07
Vested	(176,848)	5.09
Forfeited	(50,524)	5.15
Unvested at June 30, 2021	669,295	$	3.37	$	1,530,550	1.88

for the year ended June 30, 2021:


	Number of Restricted Stock Units	Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2021		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2020	200,000	$	3.50

Market-based awards granted	123,080	1.76

Vested	—	—
Unvested at June 30, 2021	323,080	$	2.84	$	169,257	2.00

Schedule of Restricted Stock Activity

The following is a summary of Restricted Stock that vested during the last two fiscal years:


	Year Ended June 30,
	2021		2020
Vesting-date intrinsic value of Restricted Stock	$	570,711	$	477,647
Grant-date fair value of vested Restricted Stock	$	900,007	$	748,893
Number of awards that vested	176,848		104,159

The following is a summary of Contingent Restricted Stock vestings for the last two fiscal years:


	Year Ended June 30,
	2021		2020
Vest-date intrinsic value of Contingent Restricted Stock	$	—	$	60,225
Grant-date fair value of vested Contingent Restricted Stock	$	—	$	34,734
Number of awards that vested	—		10,156

Supplemental Disclosure of Cash Flow Information (Tables)

12 Months Ended

Jun. 30, 2021

Supplemental Cash Flow Elements [Abstract]

Schedule of supplemental disclosures of cash flow information


	June 30,
	2021		2020
Interest paid on the Senior Secured Credit Facility	$	86,347	$	76,390
Income taxes paid	757,963		1,241,538
Income tax refunds	141,848		—
Non-cash transactions:
Decrease in accrued purchases of property and equipment	80,008		(212,456)
Oil and natural gas property costs attributable to the recognition of asset retirement obligations	2,883,426		918,137

Income Taxes (Tables)

12 Months Ended

Jun. 30, 2021

Income Tax Disclosure [Abstract]

Schedule of components of income tax provision (benefit)

The components of our income tax provision (benefit) are as follows:


	June 30, 2021		June 30, 2020
Current:
Federal	$	(334,473)	$	(2,264,850)
State	454,033		345,522
Total current income tax provision (benefit)	119,560		(1,919,328)
Deferred:
Federal	(3,987,211)		(266,482)
State	(1,116,610)		4,814
Total deferred income tax provision (benefit)	(5,103,821)		(261,668)
Total income tax provision (benefit)	$	(4,984,261)	$	(2,180,996)

Schedule of reconciliation of statutory income tax expense to income tax provision

The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate to the income tax provision (benefit) in our financial statements.


	June 30, 2021		% of Income Before Income Taxes		June 30, 2020		% of Income Before Income Taxes
Income tax provision (benefit) computed at the statutory federal rate:	$	(4,498,661)	21.0	%	$	788,776	21.0	%
Reconciling items:
Return to provision adjustments	20,036		(0.1)	%	(2,823,527)		(75.2)	%
Depletion in excess of tax basis	(175,840)		0.8	%	(412,215)		(11.0)	%
State income taxes, net of federal tax benefit	(523,436)		2.4	%	272,962		7.3	%
Permanent differences related to stock-based compensation and other	55,278		(0.3)	%	22,408		0.6	%
Federal valuation allowance	570,064		(2.7)	%	—		—	%
EOR credit benefit	(335,717)		1.6	%	—		—	%
Other	(95,985)		0.6	%	(29,400)		(0.8)	%
Income tax provision (benefit)	$	(4,984,261)	23.3	%	$	(2,180,996)	(58.1)	%

Schedule of components of deferred taxes


	Asset (Liability)
	June 30, 2021		June 30, 2020
Deferred tax assets:
Non-qualified stock-based compensation	$	309,671	$	234,559
Net operating loss carry-forwards and other carry-forwards	365,279		78,197
Derivative losses	—		401,382
Asset retirement obligations (a)	1,284,907		650,042
Other deferred tax assets	160,313		53,159
Gross deferred tax assets	2,120,170		1,417,339
Valuation allowance	(861,838)		(53,218)
Net deferred tax assets	1,258,332		1,364,121
Deferred tax liability:
Oil and natural gas properties (a)	(7,215,534)		(12,425,144)
Total deferred tax liability	(7,215,534)		(12,425,144)

Net deferred tax liability	$	(5,957,202)	$	(11,061,023)

Earnings (Loss) per Common Share (Tables)

12 Months Ended

Jun. 30, 2021

Earnings Per Share [Abstract]

Schedule of computation of basic and diluted income (loss) per share

The following table sets forth the computation of basic and diluted net income per share:


	June 30,
	2021		2020
Numerator
Net income (loss) attributable to common stockholders	$	(16,437,934)	$	5,937,072
Denominator
Weighted average number of common shares – Basic	33,263,701		33,031,149
Effect of dilutive securities:
Contingent restricted stock grants	—		1,942


Weighted average number of common shares and dilutive potential common shares used in diluted earnings (loss) per share	33,263,701		33,033,091
Net earnings (loss) per common share – Basic	$	(0.49)	$	0.18
Net earnings (loss) per common share – Diluted	$	(0.49)	$	0.18

Schedule of outstanding potentially dilutive securities


Outstanding Potentially Dilutive Securities	Weighted Average Exercise Price		Outstanding at June 30, 2021
Contingent Restricted Stock grants	$	—	323,080


Outstanding Potential Dilutive Securities	Weighted Average Exercise Price		Outstanding at June 30, 2020
Contingent Restricted Stock grants	$	—	200,000

Concentrations of Credit Risk (Tables)

12 Months Ended

Jun. 30, 2021

Risks and Uncertainties [Abstract]

Schedule of customers from whom the entity derived 10 percent or more of net oil and natural gas revenues

The following table identifies customers from whom we derived 10 percent or more of our net oil and natural gas revenues during the years ended June 30, 2021 and 2020. The loss of either one of our oil purchasers or disruption to their respective pipelines could adversely affect our net realized pricing and potentially our near-term production levels. The loss of our NGL purchaser, who trucks NGLs from the field, would not be expected to have a material adverse effect on our operations.


	Year Ended June 30,
Customer	2021		2020
Plains Marketing L.P. (Delhi field oil)	62	%	87	%
Merit Energy Company (Hamilton Dome field oil)	19	%	10	%
All others	19	%	3	%
Total	100	%	100	%

Derivatives (Tables)

12 Months Ended

Jun. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments, Gain (Loss)


	Years Ended June 30,
	2021		2020
Realized (gain) loss	$	2,525,988	$	(528,139)
Unrealized (gain) loss	(1,911,343)		1,911,343
Net (gain) loss on derivative contracts	$	614,645	$	1,383,204

Schedule of Outstanding Derivative Positions

The following sets forth a summary of the Company’s oil derivative positions during the year ended June 30, 2021.

Period

Type of Contract

Volumes in Barrels

Price / Price Range

Weighted Average Floor Price per Bbl.

Weighted Average Ceiling Price per Bbl.

July 2020 to December 2020

Fixed-Price Swap

257,600

$32

$—

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

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Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) (Tables)

12 Months Ended

Jun. 30, 2021

Schedule of costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities


	For the Years Ended June 30,
	2021		2020
Oil and Natural Gas Activities
Property acquisition costs:
Proved property	$	18,297,013	$	9,337,716
Unproved property	—		—
Exploration costs	—		—
Development costs	3,435,836		2,430,510
Total costs incurred for oil and natural gas activities	$	21,732,849	$	11,768,226

Schedule of estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves


	Oil (Bbls)	NGLs (Bbls)	Natural Gas (Mcf)	BOE
Proved developed and undeveloped reserves:
June 30, 2019	7,615,731	1,364,761	—	8,980,492
Revisions of previous estimates (a)	(2,177,787)	734,169	—	(1,443,618)
Improved recovery, extensions and discoveries	—	—	—	—
Sales of minerals in place	—	—	—	—
Purchase of reserves in place (c)	3,426,756	—		3,426,756
Production (sales volumes)	(638,464)	(106,340)	—	(744,804)
June 30, 2020	8,226,236	1,992,590	—	10,218,826
Revisions of previous estimates (b)	661,711	93,139	330	754,905
Improved recovery, extensions and discoveries	—	—	—	—
Purchase of reserves in place (c)	86,608	4,957,226	49,533,801	13,299,468
Sales of minerals in place	—	—	—	—
Production (sales volumes)	(554,888)	(171,451)	(963,496)	(886,922)
June 30, 2021	8,419,667	6,871,504	48,570,635	23,386,277
Proved developed reserves:
June 30, 2019	6,273,907	1,124,302	—	7,398,209
June 30, 2020	6,577,731	1,777,236	—	8,354,967
June 30, 2021	6,815,126	6,662,952	48,570,634	21,573,184
Proved undeveloped reserves:
June 30, 2019	1,341,824	240,459	—	1,582,283
June 30, 2020	1,648,505	215,354	—	1,863,859
June 30, 2021	1,604,541	208,551	—	1,813,092

Schedule of standardized measure of discounted future net cash flows related to proved oil and natural gas reserves

The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2021 and 2020 are as follows:


	As of June 30,
	2021		2020
Future cash inflows	$	632,620,246	$	399,358,481
Future production costs and severance taxes	(398,021,728)		(240,399,715)
Future development costs	(29,339,399)		(24,623,426)
Future income tax expenses	(42,368,085)		(21,982,469)
Future net cash flows	162,891,034		112,352,871
10% annual discount for estimated timing of cash flows	(75,308,483)		(49,862,035)
Standardized measure of discounted future net cash flows	$	87,582,551	$	62,490,836

Schedule of NYMEX prices used in determining future cash flows


	For the Years Ended June 30,
	2021				2020
	Oil (Bbl)		Gas (MMBtu)		Oil (Bbl)		Gas (MMBtu)
NYMEX prices used in determining future cash flows	$	49.72	$	2.46	$	47.37	n/a

Schedule of changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil, natural gas, and natural gas liquids reserves is as follows:


	For the Years Ended June 30,
	2021		2020
Balance, beginning of the fiscal year	$	62,490,836	$	126,732,042
Net changes in sales prices and production costs related to future production	11,538,209		(83,857,342)
Changes in estimated future development costs	403,109		(4,099,792)
Sales of oil and gas produced during the period, net of production costs	(16,115,302)		(16,093,794)
Net change due to extensions, discoveries, and improved recovery	—		—
Net change due to revisions in quantity estimates	6,840,767		(6,746,316)
Net change due to purchase of minerals in place	31,461,405		10,364,875
Development costs incurred during the period	—		1,431,444
Accretion of discount	7,529,289		16,266,663
Net change in discounted income taxes	(10,678,450)		17,078,591
Net changes in timing of production and other	(5,887,312)		1,414,465
Balance, end of the fiscal year	$	87,582,551	$	62,490,836

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Jun. 30, 2021

Summary of quarterly financial information


2021	First (a)		Second (b)		Third		Fourth (c)
Revenues	$	5,595,376	$	5,768,152	$	7,635,748	$	13,703,078
Income (loss) from operations	$	(9,429,720)	$	(15,910,266)	$	980,605	$	3,000,750
Net income (loss) attributable to common shareholders	$	(7,135,148)	$	(12,710,007)	$	1,191,001	$	2,216,220
Basic earnings (loss) per common share	$	(0.22)	$	(0.38)	$	0.04	$	0.07
Diluted earnings (loss) per common share	$	(0.22)	$	(0.38)	$	0.04	$	0.07


2020	First		Second		Third (d)		Fourth
Revenues	$	9,152,215	$	9,381,615	$	7,712,619	$	3,352,847
Income (loss) from operations	$	3,274,019	$	2,249,764	$	951,814	$	(2,786,164)
Net income (loss) attributable to common shareholders	$	2,792,820	$	1,764,918	$	3,710,159	$	(2,330,825)
Basic earnings per common share	$	0.08	$	0.05	$	0.11	$	(0.07)
Diluted earnings per common share	$	0.08	$	0.05	$	0.11	$	(0.07)

(a) The first quarter of fiscal 2021 included a ceiling test impairment charge of $9.6 million.

(b) The second quarter of fiscal 2021 included a ceiling test impairment charge of $15.2 million.

(c) The fourth quarter of fiscal 2021 includes approximately two months of production and related revenues and expenses from the Barnett Shale assets.

(d) The third quarter of fiscal 2020 was impacted by a $2.8 million tax benefit attributable to the EOR tax credits.

Organization and Basis of Preparation (Details)	Jun. 30, 2021 well
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of wells with overriding royalty interest	2

Summary of Significant Accounting Policies - Narrative (Details)	12 Months Ended
	Jun. 30, 2021 USD ($) type	Jun. 30, 2020 USD ($)
Limitation on Capitalized Costs
Allowance for doubtful accounts	$ 0	$ 0
Revenue Recognition - Oil and Gas
Receivables from oil and gas sales	$ 8,686,967	$ 1,919,213
Number of product types \| type	3
Oil and natural gas properties
Limitation on Capitalized Costs
Period considered for computing unweighted arithmetic average of oil and natural gas prices (in months)	12 months
Other Property and Equipment \| Minimum
Other Property and Equipment
Expected lives of the individual assets or group of assets	3 years
Other Property and Equipment \| Maximum
Other Property and Equipment
Expected lives of the individual assets or group of assets	7 years
Discount rate \| Oil and natural gas properties
Limitation on Capitalized Costs
Discount rate for present value (as a percent)	0.10

Revenue Recognition - Schedule of Revenues (Details) - USD ($)	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Disaggregation of Revenue [Line Items]
Total revenues	$ 32,702,354	$ 29,599,296
Oil
Disaggregation of Revenue [Line Items]
Total revenues	26,411,132	28,578,879
Natural gas liquids
Disaggregation of Revenue [Line Items]
Total revenues	3,662,478	1,018,349
Natural gas
Disaggregation of Revenue [Line Items]
Total revenues	$ 2,628,744	$ 2,068

Amount, excluding tax collected from customer, of revenue from satisfaction of performance obligation by transferring promised good or service to customer. Tax collected from customer is tax assessed by governmental authority that is both imposed on and concurrent with specific revenue-producing transaction, including, but not limited to, sales, use, value added and excise.

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Revenue Recognition - Additional Information (Details) - USD ($)	Jun. 30, 2021	Jun. 30, 2020
Revenue from Contract with Customer [Abstract]
Receivables from oil and gas sales	$ 8,686,967	$ 1,919,213

Leases - Additional Information (Details)	12 Months Ended
Leases - Additional Information (Details)	Jun. 30, 2021 contract
Leases [Abstract]
Number of operating lease contracts	1
Number of finance lease contracts	0
Number of short-term lease contracts	0

Leases - Future Minimum Lease Maturities (Details)	Jun. 30, 2021 USD ($)
Operating Lease Liability Maturity
2022	$ 61,843
2023	26,098
Total lease payments	87,941
Less imputed interest	(2,962)
Total lease liability	$ 84,979

Leases - Supplemental Information (Details) - USD ($)	12 Months Ended
Leases - Supplemental Information (Details) - USD ($)	Jun. 30, 2021	Jun. 30, 2020
Leases [Abstract]
Cash paid for amounts included in the measurement of lease liabilities	$ 59,945	$ 4,903
ROU asset added in exchange for lease obligation at adoption	0	161,125
Operating lease ROU asset (included in other assets)	70,789	117,193
Operating lease liability, current	64,234	54,290
Operating lease liability - long-term	$ 20,745	$ 84,978
Weighted average remaining lease term in years	1 year 4 months 2 days	2 years 7 months 28 days
Weighted average discount rate	5.15%	5.15%
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:OtherAssets	us-gaap:OtherAssets
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Accrued liabilities and other	Accrued liabilities and other

Prepaid Expenses and Other Current Assets (Details) - USD ($)	Jun. 30, 2021	Jun. 30, 2020
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid insurance	$ 365,922	$ 289,999
Prepaid subscription and licenses	108,048	67,005
Prepaid federal and state income taxes	97,470	86,208
Carryback of EOR tax credit	416,441	0
Prepaid other	49,378	48,474
Total prepaid expenses and other current assets	$ 1,037,259	$ 491,686

Property and Equipment, Net of Depreciation, Depletion, and Amortization - Summary of Property and Equipment (Details) - USD ($)			3 Months Ended		12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Oil and natural gas properties:
Property costs subject to amortization					$ 129,123,227	$ 107,390,379
Less: Accumulated depreciation, depletion, and amortization and impairment					(70,607,367)	(40,878,098)
Unproved properties not subject to amortization					0	0
Oil and natural gas properties, net					58,515,860	66,512,281
Other property and equipment:
Furniture, fixtures, and office equipment, at cost					154,731	154,731
Less: Accumulated depreciation					(144,092)	(137,092)
Other property and equipment, net					10,639	17,639
Depletion					4,901,969	5,592,651
Impairment of proved property	$ 15,200,000	$ 9,600,000	$ 15,200,000	$ 9,600,000	24,792,079	0
Depreciation					$ 7,000	$ 8,779

Property and Equipment, Net of Depreciation, Depletion, and Amortization - Narrative (Details)					3 Months Ended		12 Months Ended
	May 07, 2021 USD ($)	Dec. 31, 2020 USD ($)	Sep. 30, 2020 USD ($)	Nov. 01, 2019 USD ($)	Dec. 31, 2020 USD ($)	Sep. 30, 2020 USD ($)	Jun. 30, 2021 USD ($) $ / bbl	Jun. 30, 2020 USD ($)
Property, Plant and Equipment [Line Items]
Capital expenditures							$ 600,000	$ 1,500,000
Asset retirement obligation liabilities incurred							0	40,698
Impairment of proved property		$ 15,200,000	$ 9,600,000		$ 15,200,000	$ 9,600,000	$ 24,792,079	$ 0
Natural Gas and Natural Gas Liquids
Property, Plant and Equipment [Line Items]
Net price per barrel (in dollars per barrel) \| $ / bbl							19.81
Barnett Shale
Property, Plant and Equipment [Line Items]
Non-operating working interest, percent	17.00%
Revenue interest, percent	14.00%
Purchase price of oil and gas assets	$ 18,300,000
Asset retirement obligation liabilities incurred	$ 2,800,000
Hamilton Dome Field
Property, Plant and Equipment [Line Items]
Non-operating working interest, percent				23.50%
Revenue interest, percent				19.70%
Purchase price of oil and gas assets				$ 9,300,000
Asset retirement obligation liabilities incurred				$ 900,000

Other Assets, Net (Details) - USD ($)	Jun. 30, 2021	Jun. 30, 2020
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Royalty rights	$ 0	$ 108,512
Less: Accumulated amortization of royalty rights	0	(61,037)
Investment in Well Lift Inc., at cost	0	108,750
Deferred loan costs	168,972	168,972
Less: Accumulated amortization of deferred loan costs	(168,972)	(157,084)
Right of use asset under operating lease	161,125	161,125
Less: Accumulated amortization of right of use asset	(90,336)	(43,932)
Software license	20,662	20,662
Less: Accumulated amortization of software license	(20,662)	(14,350)
Other assets, net	$ 70,789	$ 291,618

Other Assets, Net - Additional Information (Details) - Well Lift Inc. - USD ($) $ in Millions		12 Months Ended
	Mar. 31, 2021	Jun. 30, 2021
Line of Credit Facility [Line Items]
Perpetual royalty percentage		5.00%
Impairment expense	$ 0.1
Common Stock
Line of Credit Facility [Line Items]
Ownership percentage		17.50%
Preferred Stock
Line of Credit Facility [Line Items]
Ownership percentage		100.00%

Accrued Liabilities and Other - Schedule of Other Current Liabilities (Details) - USD ($)	Jun. 30, 2021	Jun. 30, 2020
Other Liabilities Disclosure [Abstract]
Accrued incentive and other compensation	$ 630,744	$ 176,636
Accrued retirement costs	52,786	0
Accrued franchise taxes	35,207	100,978
Accrued ad valorem taxes	108,000	108,000
Payable for settled derivatives	0	265,188
Operating lease liability, current	64,234	54,290
Asset retirement obligations due within one year	44,520	0
Accrued - other	11,554	11,556
Total Accrued liabilities and other	$ 947,045	$ 716,648

Asset Retirement Obligations - Summary of Asset Retirement Obligations (Details)		12 Months Ended
	Nov. 01, 2019 USD ($)	Jun. 30, 2021 USD ($) well	Jun. 30, 2020 USD ($) well
Reconciliation of the beginning and ending asset retirement obligation
Asset retirement obligations—beginning of period		$ 2,588,894	$ 1,610,845
Liabilities incurred		0	40,698
Liabilities settled		(99,231)	(86,592)
Liabilities acquired		2,806,331	903,580
Accretion of discount		210,182	146,504
Revisions of previous estimates		77,096	(26,141)
Asset retirement obligations—ending of period		5,583,272	2,588,894
Asset retirement obligations due within one year		44,520	0
Long-term portion of asset retirement obligations		$ 5,538,752	$ 2,588,894
Hamilton Dome Field
Property, Plant and Equipment [Line Items]
Number of abandoned wells \| well			4
Abandoned wells in next twelve months \| well		4
Reconciliation of the beginning and ending asset retirement obligation
Liabilities incurred	$ 900,000
Delhi Field Property
Property, Plant and Equipment [Line Items]
Number of abandoned wells \| well		2	1

Stockholders' Equity - Narrative (Details) - USD ($)	12 Months Ended		74 Months Ended	90 Months Ended
Stockholders' Equity - Narrative (Details) - USD ($)	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2021	May 31, 2015
Class of Stock [Line Items]
Common stock, outstanding shares (in shares)	33,514,952	32,956,469	33,514,952	33,514,952
Common stock dividends paid	$ 4,342,082	$ 10,740,754		$ 74,500,000
Purchases of treasury stock (in shares)	2,632	449,921
Treasury stock acquired, average cost (in USD per share)	$ 2.79	$ 5.52
2015 Share Repurchase Program
Class of Stock [Line Items]
Repurchase amount	$ 4,000,000		$ 4,000,000	$ 4,000,000
Purchases of treasury stock (in shares)	0	440,666
Treasury stock acquired, average cost (in USD per share)	$ 0	$ 5.51
2015 Share Repurchase Program \| Common Stock
Class of Stock [Line Items]
Amount authorized to be repurchased					$ 5,000,000.0
Purchases of treasury stock (in shares)	0		706,858
Treasury stock acquired, average cost (in USD per share)			$ 5.72

Stockholders' Equity - Dividends (Details) - $ / shares	3 Months Ended
Stockholders' Equity - Dividends (Details) - $ / shares	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019
Equity [Abstract]
Cash dividends paid (in USD per share)	$ 0.050	$ 0.030	$ 0.025	$ 0.025	$ 0.025	$ 0.100	$ 0.100	$ 0.100

Stockholders' Equity - Treasury Shares (Details) - USD ($)	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Equity, Class of Treasury Stock [Line Items]
Number of treasury shares acquired (in shares)	2,632	449,921
Average Price per Share (in USD per share)	$ 2.79	$ 5.52
Treasury Stock Purchases	$ 7,347	$ 2,483,357
Shares surrendered for tax withholding upon vesting
Equity, Class of Treasury Stock [Line Items]
Number of treasury shares acquired (in shares)	2,632	9,255
Average Price per Share (in USD per share)	$ 2.79	$ 5.90
Treasury Stock Purchases	$ 7,347	$ 54,565
2015 Share Repurchase Program
Equity, Class of Treasury Stock [Line Items]
Number of treasury shares acquired (in shares)	0	440,666
Average Price per Share (in USD per share)	$ 0	$ 5.51
Treasury Stock Purchases	$ 0	$ 2,428,792

Stock-Based Incentive Plan - Narrative (Details)		12 Months Ended
Stock-Based Incentive Plan - Narrative (Details)	Dec. 09, 2020 shares	Jun. 30, 2021 USD ($) $ / shares shares	Jun. 30, 2020 USD ($) tranche shares	Dec. 08, 2016 shares
Restricted Stock and Contingent Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period (in years)		4 years
Stock-based compensation expense \| $		$ 1,257,684	$ 1,285,663
Restricted Stock, Service Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		365,479
Forfeited (in USD per share) \| $ / shares		$ 2.79
Restricted Stock, Service Based \| Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		314,955
Restricted Stock, Service Based \| Chief Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)			48,872
Number of vesting tranches \| tranche			3
Restricted Stock, Market Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		246,160
Restricted Stock, Market Based \| Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		246,160
Restricted Stock, Market Based \| Chief Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)			200,000
Number of vesting tranches \| tranche			4
Other Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		1 year
Restricted Stock, Performance Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding (in shares)		0
Contingent restricted stock grants
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		123,080
Contingent restricted stock grants \| Employee
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		123,080
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forfeited (in shares)		50,524
Forfeited (in USD per share) \| $ / shares		$ 5.15
2016 Equity Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for granting (in shares)				1,100,000
Number of additional shares authorized (in shares)	2,500,000
Shares available for grant (shares)		2,206,294
Minimum \| Restricted Stock, Service Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		3 years
Minimum \| Restricted Stock, Market Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		2 years
Maximum \| Restricted Stock, Service Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		4 years
Maximum \| Restricted Stock, Market Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		3 years
Employee \| Restricted Stock, Service Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)			52,119
Employee \| Restricted Stock, Market Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)			104,236
Directors \| Restricted Stock, Service Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)			56,395

Stock-Based Incentive Plan - Fair Value Assumptions (Details) - Restricted Stock And Contingent Restricted Stock, Market-Based - $ / shares	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average fair value of market-based awards granted (in USD per share)	$ 3.08	$ 3.79
Risk-free interest rate	0.23%
Risk-free interest rate, minimum		1.65%
Risk-free interest rate, maximum		1.87%
Expected life in years	2 years 6 months 21 days
Expected volatility	56.90%
Expected volatility, minimum		38.60%
Expected volatility, maximum		43.70%
Dividend yield	3.20%
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life in years		1 year 4 months 6 days
Dividend yield		6.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected life in years		2 years 6 months 21 days
Dividend yield		7.20%

Stock-Based Incentive Plan - Schedule of Restricted Stock and Contingent restricted Stock (Details) - USD ($)	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Restricted Stock
Number of Restricted Shares
Unvested, beginning of period (in shares)	285,028
Vested (in shares)	(176,848)
Forfeited (in shares)	(50,524)
Unvested, end of period (in shares)	669,295	285,028
Weighted Average Grant-Date Fair Value
Unvested, beginning of period (in USD per share)	$ 5.53
Vested (in USD per share)	5.09
Forfeited (in USD per share)	5.15
Unvested, end of period (in USD per share)	$ 3.37	$ 5.53
Unamortized compensation expense	$ 1,530,550	$ 0
Weighted Average Remaining Amortization Period (Years)	1 year 10 months 17 days
Restricted Stock, Service Based
Number of Restricted Shares
Granted (in shares)	365,479
Unvested, end of period (in shares)	348,762
Weighted Average Grant-Date Fair Value
Granted (in USD per share)	$ 2.97
Forfeited (in USD per share)	2.79
Unvested, end of period (in USD per share)	$ 3.37
Restricted Stock, Market Based
Number of Restricted Shares
Granted (in shares)	246,160
Unvested, end of period (in shares)	320,533
Weighted Average Grant-Date Fair Value
Granted (in USD per share)	$ 3.07
Unvested, end of period (in USD per share)	$ 3.38
Contingent Restricted Stock Grants
Number of Restricted Shares
Unvested, beginning of period (in shares)	200,000
Granted (in shares)	123,080
Vested (in shares)	0
Unvested, end of period (in shares)	323,080	200,000
Weighted Average Grant-Date Fair Value
Unvested, beginning of period (in USD per share)	$ 3.50
Granted (in USD per share)	1.76
Vested (in USD per share)	0
Unvested, end of period (in USD per share)	$ 2.84	$ 3.50
Unamortized compensation expense	$ 169,257
Weighted Average Remaining Amortization Period (Years)	2 years

Stock-Based Incentive Plan - Vesting Date Restricted Stock (Details) - USD ($)	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting-date intrinsic value of Restricted Stock	$ 570,711	$ 477,647
Grant-date fair value of vested Restricted Stock	$ 900,007	$ 748,893
Number of awards vesting (in shares)	176,848	104,159
Contingent Restricted Stock Grants
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting-date intrinsic value of Restricted Stock	$ 0	$ 60,225
Grant-date fair value of vested Restricted Stock	$ 0	$ 34,734
Number of awards vesting (in shares)	0	10,156

Supplemental Disclosure of Cash Flow Information - Schedule of Supplement Cash Flow (Details) - USD ($)	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Supplemental Cash Flow Elements [Abstract]
Interest paid on the Senior Secured Credit Facility	$ 86,347	$ 76,390
Income taxes paid	757,963	1,241,538
Income tax refunds	141,848	0
Non-cash transactions:
Decrease in accrued purchases of property and equipment	80,008	(212,456)
Oil and natural gas property costs attributable to the recognition of asset retirement obligations	$ 2,883,426	$ 918,137

Income Taxes - Narrative (Details) - USD ($)	3 Months Ended	12 Months Ended
Income Taxes - Narrative (Details) - USD ($)	Mar. 31, 2020	Jun. 30, 2021	Jun. 30, 2020
Operating Loss Carryforwards [Line Items]
Unrecognized tax benefits		$ 0	$ 0
Accrued interest and penalties		0	0
Income tax expense (benefit)		$ (4,984,261)	$ (2,180,996)
Income tax rate percentage		23.30%	(58.10%)
EOR credit benefit	$ 2,800,000	$ 300,000	$ 2,800,000
Receivable for income tax refunds		3,107,638	$ 3,243,271
Federal
Operating Loss Carryforwards [Line Items]
Tax loss carryforward from reverse merger		600,000
Carryforward from reverse merger		200,000
Annual amount of carryforward from reverse merger through 2023		39,648
Valuation allowance, deferred tax asset, increase		600,000
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Valuation allowance, deferred tax asset, increase		$ 200,000

Income Taxes - Components of Income Tax Provision (Benefit) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Current:
Federal	$ (334,473)	$ (2,264,850)
State	454,033	345,522
Total current income tax provision (benefit)	119,560	(1,919,328)
Deferred:
Federal	(3,987,211)	(266,482)
State	(1,116,610)	4,814
Total deferred income tax provision (benefit)	(5,103,821)	(261,668)
Income tax provision (benefit)	$ (4,984,261)	$ (2,180,996)

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

Income Taxes - Reconciliation of Statutory and Income Tax Expense (Details) - USD ($)	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income tax provision (benefit) computed at the statutory federal rate:	$ (4,498,661)	$ 788,776
Return to provision adjustments	20,036	(2,823,527)
Depletion in excess of tax basis	(175,840)	(412,215)
State income taxes, net of federal tax benefit	(523,436)	272,962
Permanent differences related to stock-based compensation and other	55,278	22,408
Federal valuation allowance	570,064	0
EOR credit benefit	(335,717)	0
Other	(95,985)	(29,400)
Income tax provision (benefit)	$ (4,984,261)	$ (2,180,996)
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Income tax provision (benefit) computed at the statutory federal rate:	21.00%	21.00%
Return to provision adjustments	(0.10%)	(75.20%)
Depletion in excess of tax basis	0.80%	(11.00%)
State income taxes, net of federal tax benefit	2.40%	7.30%
Permanent differences related to stock-based compensation and other	(0.30%)	0.60%
Federal valuation allowance	(2.70%)	0.00%
EOR credit benefit	1.60%	0.00%
Other	0.60%	(0.80%)
Income tax provision (benefit)	23.30%	(58.10%)

Income Taxes - Schedule of Deferred Income Taxes (Details) - USD ($)	Jun. 30, 2021	Jun. 30, 2020
Deferred tax assets:
Non-qualified stock-based compensation	$ 309,671	$ 234,559
Net operating loss carry-forwards and other carry-forwards	365,279	78,197
Derivative losses	0	401,382
Asset retirement obligations (a)	1,284,907	650,042
Other deferred tax assets	160,313	53,159
Gross deferred tax assets	2,120,170	1,417,339
Valuation allowance	(861,838)	(53,218)
Net deferred tax assets	1,258,332	1,364,121
Deferred tax liability:
Oil and natural gas properties (a)	(7,215,534)	(12,425,144)
Total deferred tax liability	(7,215,534)	(12,425,144)
Net deferred tax liability	$ (5,957,202)	$ (11,061,023)

Earnings (Loss) per Common Share - Schedule of Basic and Diluted Earnings (Loss) Per Share (Details) - USD ($)	3 Months Ended								12 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2021	Jun. 30, 2020
Numerator
Net income (loss) attributable to common stockholders	$ 2,216,220	$ 1,191,001	$ (12,710,007)	$ (7,135,148)	$ (2,330,825)	$ 3,710,159	$ 1,764,918	$ 2,792,820	$ (16,437,934)	$ 5,937,072
Denominator
Weighted average number of common shares—Basic (in shares)									33,263,701	33,031,149
Effect of dilutive securities:
Weighted average number of common shares and dilutive potential common shares used in diluted EPS (in shares)									33,263,701	33,033,091
Net income per common share - Basic (in dollars per share)	$ 0.07	$ 0.04	$ (0.38)	$ (0.22)	$ (0.07)	$ 0.11	$ 0.05	$ 0.08	$ (0.49)	$ 0.18
Net income per common share - Diluted (in dollars per share)	$ 0.07	$ 0.04	$ (0.38)	$ (0.22)	$ (0.07)	$ 0.11	$ 0.05	$ 0.08	$ (0.49)	$ 0.18
Contingent restricted stock grants
Effect of dilutive securities:
Contingent restricted stock grants (in shares)									0	1,942

Earnings (Loss) per Common Share - Schedule of Outstanding Potentially Dilutive Securities (Details) - Contingent Restricted Stock grants - $ / shares	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted Average Exercise Price (in dollars per share)	$ 0	$ 0
Outstanding (in shares)		200,000

Senior Secured Credit Agreement (Details) - Line of Credit - Senior Secured Reserve-Based Credit Facility - Revolving Credit Facility	Apr. 11, 2016 USD ($)	Aug. 05, 2021 USD ($)	Jun. 30, 2021 USD ($)	Mar. 30, 2021 USD ($)	Jan. 05, 2021	Nov. 02, 2020 USD ($)
Debt Instrument [Line Items]
Term of debt instrument	3 years
Maximum borrowing capacity	$ 50,000,000
Initial borrowing base				$ 30,000,000		$ 23,000,000
Minimum current ratio					1.00
Minimum consolidated tangible net worth			$ 50,000,000
Long-term line of credit			$ 4,000,000
Placement fee percentage	0.50%
Commitment fee percentage	0.25%
Maximum total leverage ratio (not more than)	3.00
Debt service coverage ratio (not less than)	1.00
Debt issuance costs	$ 168,972
Subsequent Event
Debt Instrument [Line Items]
Minimum consolidated tangible net worth		$ 40,000,000
LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate	2.75%
Prime Rate
Debt Instrument [Line Items]
Basis spread on variable rate	1.00%

Concentrations of Credit Risk - Schedule of Credit Risk (Details) - Net revenue - Major Customers	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Concentrations of Credit Risk
Percent of Total Revenue	100.00%	100.00%
Plains Marketing L.P. (Delhi field oil)
Concentrations of Credit Risk
Percent of Total Revenue	62.00%	87.00%
Merit Energy Company (Hamilton Dome field oil)
Concentrations of Credit Risk
Percent of Total Revenue	19.00%	10.00%
All others
Concentrations of Credit Risk
Percent of Total Revenue	19.00%	3.00%

Derivatives - Gain and Loss on Derivatives (Details) - USD ($)	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Realized (gain) loss	$ 2,525,988	$ (528,139)
Unrealized (gain) loss	(1,911,343)	1,911,343
Net (gain) loss on derivative contracts	$ 614,645	$ 1,383,204

Derivatives - Crude Oil Derivative Positions (Details) - Oil Swap July To December 2020	12 Months Ended
	Jun. 30, 2021 $ / bbl bbl
Derivative [Line Items]
Volumes in Barrels \| bbl	257,600
Price / Price Range (in USD per barrel)	32
Weighted Average Floor Price per Bbl. (in USD per barrel)	32
Weighted Average Ceiling Price per Bbl. (in USD per barrel)	0

Fair Value Measurement (Details) - USD ($)	Jun. 30, 2021	Jun. 30, 2020
Fair Value Disclosures [Abstract]
Open positions	$ 0	$ 1,900,000

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Narrative (Details) - USD ($)	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Asset retirement obligations	$ 2,883,426	$ 918,137
Period considered for unweighted arithmetic average	12 months
Period considered for determining unweighted arithmetic average of first day of month, commodity Prices	12 months

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Schedule of Costs Incurred and Capitalized in Oil and Natural Gas Property Acquisition, Exploration, and Development (Details) - USD ($)	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Property acquisition costs:
Proved property	$ 18,297,013	$ 9,337,716
Unproved property	0	0
Exploration costs	0	0
Development costs	3,435,836	2,430,510
Total costs incurred for oil and natural gas activities	$ 21,732,849	$ 11,768,226

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Estimated Quantities of Proved Oil and Natural Gas Reserves (Details) $ in Millions		12 Months Ended
	May 07, 2021 USD ($)	Jun. 30, 2021 Boe bbl Mcf	Jun. 30, 2020 Boe bbl Mcf	Jun. 30, 2019 Boe bbl Mcf
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Balance at the beginning of the period (in BOE) \| Boe		10,218,826	8,980,492
Revisions of previous estimates (in BOE) \| Boe		754,905	(1,443,618)
Improved recovery, extensions and discoveries (in BOE) \| Boe		0	0
Purchase of reserves in place (in BOE) \| Boe		13,299,468	3,426,756
Sales of minerals in place (in BOE) \| Boe		0	0
Production (sales volumes) (in BOE) \| Boe		(886,922)	(744,804)
Balance at the end of the period (in BOE) \| Boe		23,386,277	10,218,826
Proved developed reserves (in BOE) \| Boe		21,573,184	8,354,967	7,398,209
Proved undeveloped reserves (in BOE) \| Boe		1,813,092	1,863,859	1,582,283
Barnett Shale
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Purchase price of oil and gas assets \| $	$ 18.3
Crude Oil
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Balance at the beginning of the period (in Bbls/Mcf)		8,226,236	7,615,731
Revisions of previous estimates (in Bbls/Mcf)		661,711	(2,177,787)
Improved recovery, extensions and discoveries (in Bbls/Mcf)		0	0
Purchase of reserves in place (in Bbls/Mcf)		86,608	3,426,756
Sales of minerals in place (in Bbls/Mcf)		0	0
Production (sales volumes) (in Bbls/Mcf)		(554,888)	(638,464)
Balance at the end of the period (in Bbls/Mcf)		8,419,667	8,226,236
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Proved developed reserves (in Bbls/Mcf)		6,815,126	6,577,731	6,273,907
Proved undeveloped reserves (in Bbls/Mcf)		1,604,541	1,648,505	1,341,824
Natural gas liquids
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Balance at the beginning of the period (in Bbls/Mcf)		1,992,590	1,364,761
Revisions of previous estimates (in Bbls/Mcf)		93,139	734,169
Improved recovery, extensions and discoveries (in Bbls/Mcf)		0	0
Purchase of reserves in place (in Bbls/Mcf)		4,957,226	0
Sales of minerals in place (in Bbls/Mcf)		0	0
Production (sales volumes) (in Bbls/Mcf)		(171,451)	(106,340)
Balance at the end of the period (in Bbls/Mcf)		6,871,504	1,992,590
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Proved developed reserves (in Bbls/Mcf)		6,662,952	1,777,236	1,124,302
Proved undeveloped reserves (in Bbls/Mcf)		208,551	215,354	240,459
Natural gas
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Balance at the beginning of the period (in Bbls/Mcf) \| Mcf		0	0
Revisions of previous estimates (in Bbls/Mcf) \| Mcf		330	0
Improved recovery, extensions and discoveries (in Bbls/Mcf) \| Mcf		0	0
Purchase of reserves in place (in Bbls/Mcf) \| Mcf		49,533,801
Sales of minerals in place (in Bbls/Mcf) \| Mcf		0	0
Production (sales volumes) (in Bbls/Mcf) \| Mcf		(963,496)	0
Balance at the end of the period (in Bbls/Mcf) \| Mcf		48,570,635	0
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Proved developed reserves (in Bbls/Mcf) \| Mcf		48,570,634	0	0
Proved undeveloped reserves (in Bbls/Mcf) \| Mcf		0	0	0

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserves (Details) - USD ($)	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2019
Standardized measure of discounted future net cash flows
Future cash inflows	$ 632,620,246	$ 399,358,481
Future production costs and severance taxes	(398,021,728)	(240,399,715)
Future development costs	(29,339,399)	(24,623,426)
Future income tax expenses	(42,368,085)	(21,982,469)
Future net cash flows	162,891,034	112,352,871
10% annual discount for estimated timing of cash flows	(75,308,483)	(49,862,035)
Standardized measure of discounted future net cash flows	$ 87,582,551	$ 62,490,836	$ 126,732,042

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Schedule of NYMEX Prices Used in Determining Future Cash Flows (Details)	3 Months Ended	6 Months Ended	12 Months Ended
	Sep. 30, 2020 $ / bbl	Dec. 31, 2020 $ / bbl	Jun. 30, 2021 $ / bbl	Jun. 30, 2020 $ / bbl $ / MMBtu
Oil (per barrel)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices Used in Determining Future Cash Flows (in USD per barrel)	43.63	39.54	49.72	47.37
Gas (per million BTU)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices Used in Determining Future Cash Flows (in USD per barrel)			2.46	0

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Roll Forward of Changes in Standardized Measure of Discount Future Cash Flows on Proved Crude Oil, Natural Gas Liquids, and Natural Gas Reserves (Details) - USD ($)	12 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves
Balance, beginning of the fiscal year	$ 62,490,836	$ 126,732,042
Net changes in sales prices and production costs related to future production	11,538,209	(83,857,342)
Changes in estimated future development costs	403,109	(4,099,792)
Sales of oil and gas produced during the period, net of production costs	(16,115,302)	(16,093,794)
Net change due to extensions, discoveries, and improved recovery	0	0
Net change due to revisions in quantity estimates	6,840,767	(6,746,316)
Net change due to purchase of minerals in place	31,461,405	10,364,875
Development costs incurred during the period	0	1,431,444
Accretion of discount	7,529,289	16,266,663
Net change in discounted income taxes	(10,678,450)	17,078,591
Net changes in timing of production and other	(5,887,312)	1,414,465
Balance, end of the fiscal year	$ 87,582,551	$ 62,490,836

Selected Quarterly Financial Data (Unaudited) - Summary of Quarterly Financial Information (Details) - USD ($)			3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2021	Jun. 30, 2020
Quarterly Financial Information Disclosure [Abstract]
Revenues			$ 13,703,078	$ 7,635,748	$ 5,768,152	$ 5,595,376	$ 3,352,847	$ 7,712,619	$ 9,381,615	$ 9,152,215
Income (loss) from operations			3,000,750	980,605	(15,910,266)	(9,429,720)	(2,786,164)	951,814	2,249,764	3,274,019	$ (21,358,631)	$ 3,689,433
Net income (loss) attributable to common shareholders			$ 2,216,220	$ 1,191,001	$ (12,710,007)	$ (7,135,148)	$ (2,330,825)	$ 3,710,159	$ 1,764,918	$ 2,792,820	$ (16,437,934)	$ 5,937,072
Basic earnings (loss) per common share (in dollars per share)			$ 0.07	$ 0.04	$ (0.38)	$ (0.22)	$ (0.07)	$ 0.11	$ 0.05	$ 0.08	$ (0.49)	$ 0.18
Diluted earnings (loss) per common share (in dollars per share)			$ 0.07	$ 0.04	$ (0.38)	$ (0.22)	$ (0.07)	$ 0.11	$ 0.05	$ 0.08	$ (0.49)	$ 0.18
Impairment of proved property	$ 15,200,000	$ 9,600,000			$ 15,200,000	$ 9,600,000					$ 24,792,079	$ 0
EOR credit benefit								$ 2,800,000			$ 300,000	$ 2,800,000

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

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Amount of revenue recognized from goods sold, services rendered, insurance premiums, or other activities that constitute an earning process. Includes, but is not limited to, investment and interest income before deduction of interest expense when recognized as a component of revenue, and sales and trading gain (loss).

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