Riley Exploration Permian, Inc. (REPX) FY 2021 MD&A

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the Company’s financial condition and results of operations should be read in conjunction with the Company’s consolidated financial statements and related notes thereto presented in this Annual Report. The following discussion contains “forward-looking statements” that reflect the Company’s future plans, estimates, beliefs and expected performance. The Company’s actual results could differ materially from those discussed in these forward-looking statements. See "Cautionary Statements Regarding Forward-Looking Statements" and "Part I. Item 1A. Risk Factors".

Overview

We operate in the upstream segment of the oil and gas industry and are focused on steadily growing conventional reserves, production and cash flow through the acquisition, exploration, development and production of oil, natural gas and NGLs primarily in the Permian Basin. The Company’s activities are primarily focused on the San Andres Formation, a shelf margin deposit on the Central Basin Platform and Northwest Shelf. We intend to continue to develop our reserves and increase production through development drilling and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives.

Financial and Operating Highlights

Financial and operating results reflect the following:

•Increased total net equivalent production by 22% to 8.6 MBoe/d for the year ended September 30, 2021, as compared to the same period in 2020

•During the year ended September 30, 2021, 20 gross (14 net) horizontal wells brought online to production

•Began initial, planning, permitting and drilling operations on the EOR Project

•Realized average combined price on production sold of $47.12 per Boe, before derivative settlements, during the year ended September 30, 2021, including $58.29 per barrel for oil

•Completed common stock issuance in fiscal fourth quarter 2021 resulting in approximately $46.7 million of proceeds after underwriter costs and other offering costs

•Generated cash flow from continuing operations of $86.1 million for the year ended September 30, 2021

•Total cash capital expenditures before acquisitions of $60.1 million for the year ended September 30, 2021

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•Paid cash dividends on common units/shares of $18.3 million during the year ended September 30, 2021 and announced latest dividend of $0.31 per share with a record date of October 21, 2021, which was paid on November 4, 2021, for a total of $6.0 million

•Exited the fourth quarter with $17.1 million in cash and $60.0 million drawn on our revolving credit facility; subsequently increased our borrowing base from $135 million to $175 million in October 2021

Recent Developments

EOR Project

The Company began initial planning, permitting and drilling operations on its EOR Project, which will utilize a combination of water and CO2 injection through vertical wells, applied to horizontal producing wells at its core asset in Yoakum County, Texas. These wells are directly adjacent to several of the largest EOR projects in the U.S., which have employed EOR techniques for many decades.

Common Stock Offering

In July 2021, the Company issued 1.67 million shares of its common stock for total proceeds net of underwriter fees and other offering costs of approximately $46.7 million.

Market Conditions and Commodity Prices

The COVID-19 pandemic and the measures being taken to address and limit the spread of the virus significantly reduced global economic activity, resulting in a significant decline in the demand for and prices of oil, natural gas and NGLs.

The Company cannot estimate the full length or gravity of the future impacts at this time and if there is another significant decline in oil price, it could have a material adverse effect on the Company’s results of operations, financial position, liquidity and the value of oil and natural gas reserves.

The Company has developed and implemented a number of safety measures, which have successfully kept our workforce healthy and safe. The Company has established an informational campaign to provide employees an understanding of the virus risk factors and safety measures, as well as timely updates from governmental stay-at-home regulations. Expectations have also been set for employees to communicate immediately if they, or someone they have been in contact with, has experienced symptoms or tested positive for COVID-19. Additional measures include distribution of educational material regarding health and safety guidance, limiting access to common areas within the office, ensuring social distancing guidance by relocating personnel, and other guidelines as recommended by the Center for Disease Control and Prevention and local authorities.

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Results of Operations

Comparison for the Years Ended September 30, 2021 and 2020

The following table sets forth selected operating data for the years ended September 30, 2021 and 2020:

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(1)The Company's natural gas and NGL sales are presented net of gathering, processing and transportation fees which at times exceed the price received and result in negative average prices.

(2)The Company's calculation of the effects of derivative settlements includes gains (losses) on the settlement of its commodity derivative contracts. These gains (losses) are included under other income and expense on the Company’s consolidated statement of operations.

(3)During the years ended September 30, 2021 and 2020, the Company did not have any natural gas liquids derivative contracts in place. During the year ended September 30, 2020, the Company did not have any natural gas derivative contracts in place.

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Oil and Natural Gas Revenues

Our revenues are derived from the sale of our oil and natural gas production, including the sale of NGLs that are extracted from our natural gas during processing. Revenues from product sales are a function of the volumes produced, product quality, market prices, and gas Btu content. Our revenues from oil, natural gas and NGL sales do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The Company’s total oil and natural gas revenue, net increased $75.5 million, or 103%, for the year ended September 30, 2021 compared to the same period in 2020. The Company’s realized average combined price on its production for the year ended September 30, 2021 increased by $18.90 or 67%, respectively, compared to the same period of 2020.

Oil revenues

•For the year ended September 30, 2021, oil revenues increased by $61.5 million, or 82%, compared to the same period in 2020. Of the increase, $51.3 million was attributable to an increase in our realized price and $10.2 million was attributable to an increase in volume. Volumes increased by 14% while prices increased by 60% compared to the same period in 2020.

•Oil volumes increased during the year ended September 30, 2021 due to production from new wells and workovers performed on existing wells. During the year ended September 30, 2021, we brought online 20 new gross (14 net) wells.

Natural gas revenues

•For the year ended September 30, 2021, natural gas revenues increased by $8.8 million, compared to the same period in 2020, to $7.5 million from $(1.3) million. Volumes increased by 60% and realized prices increased by $3.66/Mcf from negative effective prices experienced in 2020.

•Natural gas sales volumes increased during the year ended September 30, 2021 due to increased production from new wells brought online and increased gas processing capacity available from the Company's midstream gathering and processing partner.

Natural gas liquids revenues

•For the year ended September 30, 2021, natural gas liquids revenues increased by $5.2 million, compared to the same period in 2020, to $4.7 million from $(0.5) million. Volumes increased by 46% and realized prices increased by $14.31/Bbl from negative effective prices experienced in 2020.

•Natural gas liquids sales volumes increased during the year ended September 30, 2021 due to increased production from new wells brought online and increased gas processing capacity available from the Company's midstream gathering and processing partner.

Contract Services - Related Party Revenue

The following tables present the Company's revenue and costs associated with its related party transactions:

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(1)The Company’s contract services – related parties revenue is derived from master services agreements with related parties to provide certain administrative support services.

(2)The Company's cost of contract services - related parties represents costs specifically attributable to the master service agreements the Company has in place with the respective related parties.

The Company's contract services - related parties decreased for the year ended September 30, 2021 due to the restructuring of the monthly fee in the fourth quarter of fiscal 2020. The monthly fee decreased by $150 thousand per month.

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The following table presents the Company's operating costs and expenses and other (income) expenses:

Lease Operating Expenses

Lease operating expenses ("LOE") are the costs incurred in the operation and maintenance of producing properties. Expenses for compression, direct labor, saltwater disposal and materials and supplies comprise the most significant portion of our lease operating expenses. Certain operating cost components, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities or subsurface maintenance result in increased production expenses in periods during which they are performed. Certain operating cost components, such as compression and salt water disposal associated with completion water, are variable and increase or decrease as hydrocarbon production levels and the volume of completion water disposal increases or decreases.

The Company’s LOE increased by $1.7 million for the year ended September 30, 2021 compared to the same period in 2020. LOE for the year ended September 30, 2020 reflected the reduced activity following the sharp downturn in commodity prices at the time, partially offset by higher workover costs and the addition of new wells in 2021. For the year ended September 30, 2021, LOE reflects additional costs due to higher produced volumes as well as higher costs for certain services due to increased activity in the Permian Basin.

Production and Ad Valorem Tax Expense

Production taxes are paid on produced oil, natural gas and NGLs based on a percentage of revenues at fixed rates established by federal, state or local taxing authorities. In general, the production taxes we pay correlate to changes in our oil, natural gas and NGL revenues. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices and vary across the different counties in which we operate. Production and ad valorem taxes increased by $4.4 million for the year ended September 30, 2021 compared to the same period in 2020, primarily due to increases in our production sold resulting from additional wells brought online, workovers performed on existing wells and significantly higher commodity prices. Also contributing to the increase is higher ad valorem taxes based on the increase in property values during the year ended September 30, 2021.

Exploration Expense

Exploration expense, which consists of expiration of unproved leasehold and geological and geophysical costs that include seismic survey costs, decreased by $0.4 million, or 4%, for the year ended September 30, 2021, as compared to the same period in 2020. For the year ended September 30, 2021, the Company incurred lower seismic expense compared to the same period in 2020.

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The following table presents exploration expense by area for the years ended September 30, 2021 and 2021:

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(1)As of September 30, 2021 exploration expense includes $3,516 and $5,831 related to expiration of unproved leasehold costs in Texas and New Mexico, respectively. As of September 30, 2020 exploration expense includes $1,206 and $6,696 related to expiration of unproved leasehold costs in Texas and New Mexico, respectively.

(2)The Company did not renew any net acreage after expiration in New Mexico for the years ended September 30, 2021 and 2020.

Depletion, Depreciation, and Accretion Expense

Depreciation, depletion and amortization is the systematic expensing of the capitalized costs incurred to acquire, explore and develop oil, natural gas and NGLs. All costs incurred in the acquisition, exploration and development of properties (excluding costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration activities) are capitalized. Capitalized costs are depleted using the units of production method.

Accretion expense relates to ARO. We record the fair value of the legal liability for ARO in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the asset’s inception, with the offsetting increase to property cost. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed.

Depletion, depreciation, amortization and accretion expense increased by $4.5 million for the year ended September 30, 2021, respectively, compared to the same period for 2020. The increase for the year ended September 30, 2021 was due to higher production in addition to a higher depletion rate due to additional capitalized costs.

General and Administrative Expense ("G&A")

G&A expenses include corporate overhead such as payroll and benefits for our corporate staff, equity-based compensation expense, office rent for our headquarters, audit and other fees for professional services and legal compliance. G&A expenses are reported net of recoveries from other owners in properties operated by us and amounts capitalized pursuant to the successful efforts method. During the year ended September 30, 2021, we incurred, and we expect that we will continue to incur, additional general and administrative expenses as a result of being a publicly-traded company.

Total G&A expense increased by $9.0 million, for the year ended September 30, 2021, compared to the same period for 2020. Administrative costs, which includes payroll, benefits and non-payroll costs, increased by $3.1 million, for the year ended September 30, 2021, compared to the same period for 2020. The increase in administrative costs was primarily attributable to increased audit, filing, legal and professional service costs following completion of the Merger. Equity compensation expense increased by $5.8 million for the year ended September 30, 2021, compared to the same periods for 2020. The increase is primarily attributable to restricted shares awarded to certain executives and employees following completion of the Merger.

Transaction Costs

Transaction costs were $3.7 million and $1.4 million for the year ended September 30, 2021 and 2020, which reflects expenses associated with the Merger.

Interest Expense

Interest expense was $4.5 million and $5.3 million for the years ended September 30, 2021 and 2020, respectively. The decrease in interest expense in the 2021 period was primarily attributable to a lower average balance on the Company's revolving credit facility during the year ended September 30, 2021 when compared to the same period for 2020.

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Gain/Loss on Derivatives

The Company recognizes settlements and changes in the fair value of its derivative contracts as a single component within other income (expenses) on its consolidated statement of operations. We have oil and natural gas derivative contracts, including fixed price swaps, basis swaps and collars, that settle against various indices. The following table presents the components of the Company's gain (loss) on derivatives for the years ended September 30, 2021 and 2020:

Our earnings are affected by the changes in value of our derivatives portfolio between periods and the related cash received or paid upon settlement of our derivatives. To the extent the future commodity price outlook declines between periods, we will have mark-to-market gains; while to the extent future commodity price outlook increases between measurement periods, we will have mark-to-market losses.

Income Tax Expense

The Company became a taxable entity as a result of its Merger with Tengasco on February 26, 2021. See further discussion in Note 4 - Acquisitions and Divestitures to the Company's consolidated financial statements included herein. While REP LLC was organized as a limited liability company, taxable income passed through to its unit holders. Accordingly, a provision for federal and state corporate income taxes has been made for the operations of REP LLC only from February 27, 2021 through September 30, 2021 in the accompanying consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon consummation of the Merger, the Company established a $13.6 million provision for deferred income taxes with the conversion to a C-corporation. The majority of this deferred tax liability was established by a change in tax status which primarily was attributable to the oil and natural gas properties. See Note 12 - Income Taxes to the Company's consolidated financial statements included herein for further discussion of income taxes.

Liquidity and Capital Resources

The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, like all upstream operators, we must make capital investments to grow and even sustain production. The Company’s principal liquidity requirements are to finance its operations, fund capital expenditures and acquisitions, make cash distributions and satisfy any indebtedness obligations. Cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop the Company’s oil and natural gas properties. Historically, our primary sources of capital funding and liquidity have been our cash on hand, cash flow from operations and borrowings under our revolving credit facility. At times and as needed, we may also issue debt or equity securities, including through transactions under our shelf registration statement filed with the SEC. In October 2021, the revolving credit facility was further amended to, among other things increase the borrowing base to $175 million. We estimate the combination of the sources of capital discussed above will continue to be adequate to meet our short and long-term liquidity needs.

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Cash on hand and operating cash flow can be subject to fluctuations due to trends and uncertainties that are beyond our control. Likewise, our ability to issue equity and our ability to obtain credit facilities on favorable terms may be impacted by a variety of market factors as well as fluctuations in our results of operations. For more information on conditions impacting our liquidity and capital resources, see "—Recent Developments." For further discussion of risks related to our liquidity and capital resources, see "Item 1A. Risk Factors."

On July 2, 2021 the Company completed the offering of 1,666,667 shares of common stock at a price to the public of $30.00 per common share. The Company received net proceeds of $46.7 million from the sale of the common stock, after deducting underwriting discounts and commissions, and offering expenses paid by the Company. The Company utilized $35.5 million to pay down its revolving credit facility during its fiscal fourth quarter. The Company intends to draw on the revolving credit facility in order to fund drilling and infrastructure for normal operations as well as for the EOR Project. The remaining net proceeds are expected to be used for working capital purposes and other general corporate purposes, which may include financing of capital expenditures, financing acquisitions or investments, repayment or refinancing of outstanding debt, financing other business opportunities, and working capital purposes.

Working Capital

Working capital is the difference in our current assets and our current liabilities. Working capital is an indication of liquidity and potential need for short-term funding. The change in our working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, credit extended to, and the timing of collections from customers, the level and timing of spending for expansion activity, and the timing of debt maturities. As of September 30, 2021, we had a working capital deficit of $46.9 million compared to working capital surplus of $13.9 million as of September 30, 2020. The working capital deficit at September 30, 2021 reflects $42.1 million in current derivative liabilities compared to $18.8 million in current derivative assets at September 30, 2020. Additionally, there was an increase of $18.2 million in accounts payable and accrued liabilities as of September 30, 2021 due to increased drilling and completion activity as well as costs incurred for work on the EOR Project. We utilize our revolving credit facility and cash on hand to manage the timing of cash flows and fund short-term working capital deficits.

Cash Flows

The following table summarizes the Company’s cash flows from continuing operations:

Operating Activities

The Company’s net cash provided by operating activities increased by $23.5 million or 38% to $86.1 million for the year ended September 30, 2021 from $62.6 million for the same periods in 2020. The increase was primarily driven by an increase in revenues of $74.1 million, partially offset by a $43.2 million decrease in net cash received for settlements of commodity derivative contracts and an increase in operating expenses, excluding equity based compensation, of $9.7 million.

Investing Activities

The Company's cash flows used in investing activities increased by $8.1 million or 16% to $59.6 million for the year ended September 30, 2021 from $51.5 million for the same period in 2020. The increase was primarily due to higher capital spending of $11.1 million related to the Company's drilling and completion activity in 2021 and additions to other property and equipment by $1.5 million, partially offset by lower acquisitions of oil and natural gas properties by $3.7 million.

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Financing Activities

Net cash flow used in financing activities was $14.9 million during the year ended September 30, 2021, or an increase of $1.8 million, as compared to the same period in 2020. The most significant cash outflow from financing activities was the net repayment of $41.0 million on the revolving credit facility, as compared to net proceeds of $4.0 million in the same period in 2020. Also contributing to the cash outflow from financing activities was $18.3 million for the payment of dividends on common stock and units during the year ended September 30, 2021. Partially offsetting these cash outflows was the $46.7 million in net proceeds during the year ended September 30, 2021 from the issuance of common stock, after deducting underwriter fees and other offering costs.

Revolving Credit Facility

The Company's borrowing base was $135 million with outstanding borrowings of $60 million on September 30, 2021 representing available borrowing capacity of $75 million. In October 2021, the revolving credit facility was further amended to, among other things, increase the borrowing base to $175 million. See further discussion in Note 9 — Revolving Credit Facility to the Company's consolidated financial statements included herein.

Distributions

For the year ended September 30, 2021, the Company authorized and declared quarterly dividends totaling approximately $18.1 million, with $17.8 million paid in cash and $0.3 million payable to restricted shareholders upon vesting.

Contractual Obligations

In July 2021, as part of a planned expansion of Stakeholder’s primary gas processing plant, the Company committed to annually drill, complete and connect a minimum number of wells or deliver an annual target volume to Stakeholder's gathering system. While the minimum number of wells is below our planned development activity, there are financial penalties if the minimum activity levels are not met. The annual well or volume target is for each of five years beginning January 2022. The additional capacity from the gas processing plant expansion is expected to lead to increased natural gas sales and decreased gas flaring for the Company.

In August 2021, the Company entered into a purchase agreement for supplies for its EOR project. Under the agreement, the Company has committed to purchasing supplies totaling approximately $1.2 million and $3.3 million by January 2022 and April 2022, respectively.

Critical Accounting Estimates

The discussion and analysis of the Company’s financial condition and results of operations are based upon the Company’s consolidated financial statements and accompanying notes included herein, which have been prepared in accordance with U.S. GAAP. The preparation of financial statements requires the Company to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

Changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and assumptions used in preparation of the Company’s consolidated financial statements and it is at least reasonably possible these estimates could be revised in the near term and these revisions could be material.

Method of Accounting for Oil and Natural Gas Properties

We utilize the successful effort method of accounting for our oil and natural gas exploration and development activities which requires management's assessment of the proper designation of wells and associated costs as developmental or exploratory. This classification assessment is dependent on the determination and existence of proved reserves, which is a critical estimate discussed in the section below. The classification of developmental and exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or capitalize, then subject to DD&A calculations and impairment assessments and valuations.

Once a well is drilled, the determination that proved reserves have been discovered may take considerable time and requires both judgment and application of industry experience. Development wells are always capitalized. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have

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been found. At the end of each quarter, the status of all suspended exploratory drilling costs are reviewed to determine whether the costs should continue to remain capitalized or shall be expensed. When making this determination, current activities, near-term plans for additional exploratory or appraisal drilling and the likelihood of reaching a development program is considered. If future development activities and the determination of proved reserves are unlikely to occur, the associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the consolidated statements of operations. Otherwise, the costs of exploratory wells remain capitalized. At September 30, 2021, all suspended well costs have been suspended for greater than one year but less than two years.

Similar to the evaluation of suspended exploratory well costs, costs for undeveloped leasehold, for which reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each quarter, undeveloped leasehold costs are assessed for impairment by considering future drilling plans, drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such projects. At September 30, 2021, the Company had approximately $20.6 million of undeveloped leasehold. Of the remaining undeveloped leasehold costs at September 30, 2021, approximately $0.3 million is scheduled to expire in 2022. The Company will renew or extend the lease if the leasehold expiring in 2022 relates to areas in which the Company is actively drilling. If our drilling is not successful, this leasehold could become partially or entirely impaired.

Oil and Natural Gas Reserves

Our estimates of proved and proved developed reserves are a major component of our depletion calculation. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. A third-party consulting firm prepares our reserve report which the estimates are based off of technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. The data for a given reservoir may also change substantially over time as a result of numerous factors, including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

Derivatives

From time to time, we have used commodity derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of oil and natural gas. We exercise significant judgment in determining the types of instruments to be used, the level of production volumes to include in our commodity derivative contracts, and the prices at which we enter into commodity derivative contracts.

We have not designated our derivative instruments as hedges for accounting purposes and, as a result, mark our derivative instruments to fair value and recognize the cash and non-cash change in fair value on derivative instruments for each period in the consolidated statements of operations. We are also required to recognize our derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation, and is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur.

Income Taxes

The amount of income taxes we record requires interpretations of complex rules and regulations of federal, state, and provincial tax jurisdictions. We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards.

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Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment. These assumptions and judgments are reviewed and adjusted as facts and circumstances change, with our projection of earnings or losses during the current calendar year being the most significant judgement. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.

Goodwill

We test goodwill for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. If the fair value is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available, the fair value is estimated based upon a valuation analyses including comparable companies and transactions and premiums paid. An impairment loss is recognized if the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill.

The Company recognized goodwill of $19.0 million from the result of the Merger, all of which was allocated to the oil and natural gas properties acquired from the Merger. The Company bypassed the qualitative analysis to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying value amount, including goodwill, since the Company entered into a PSA shortly after acquiring the oil and natural gas properties. The Company compared the reporting unit fair value of $3.5 million with its carrying amount, including goodwill, of $19.0 million and recognized a goodwill impairment of $18.5 million. The impairment loss was recognized within loss from discontinued operations for the year ended September 30, 2021 in our consolidated statement of operations.

See Note 3 - Summary of Significant Accounting Policies in the Company's consolidated financial statements in "Item 15. Exhibits and Financial Statement Schedules" for a full discussion of our significant accounting policies.