Riley Exploration Permian (REPX) 8-K/A Financial Statements and Exhibits

Exhibit 99.2

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Report of Independent Registered Public Accounting Firm

Members and Board of Directors

Riley Exploration – Permian, LLC

Oklahoma City, Oklahoma

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Riley Exploration – Permian, LLC (the “Company”) as of September 30, 2020 and 2019, the related consolidated statements of operations, changes in members’ equity, and cash flows for each of the three years in the period ended September 30, 2020, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at September 30, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2020, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ BDO USA, LLP

We have served as the Company's auditor since 2016.

Houston, Texas

December 23, 2020

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Riley Exploration – Permian, LLC

Consolidated Balance Sheets

($ in thousands)

	September 30, 2020	September 30, 2019
Assets
Current Assets:
Cash and cash equivalents	$1,660	$3,726
Accounts receivable	10,128	11,643
Accounts receivable – related parties	55	504
Prepaid expenses and other current assets	1,752	1,410
Current derivative assets	18,819	7,503
Total Current Assets	32,414	24,786
Non-Current Assets:
Oil and natural gas properties, net (successful efforts)	310,726	289,301
Other property and equipment, net	1,801	2,000
Right of use assets	700	—
Non-current derivative assets	3,102	7,936
Other non-current assets	2,249	2,724
Total Non-Current Assets	318,578	301,961
Total Assets	$350,992	$326,747
Liabilities, Series A Preferred Units, and Members' Equity
Current Liabilities:
Accounts payable	$4,739	$2,422
Accrued liabilities	8,746	13,177
Current lease liability	392	—
Revenue payable	4,432	4,516
Advances from joint interest owners	254	362
Current derivative liabilities	—	328
Total Current Liabilities	18,563	20,805
Non-Current Liabilities:
Non-current derivative liabilities	—	152
Asset retirement obligations	2,268	1,203
Revolving credit facility	101,000	97,000
Deferred tax liabilities	1,834	1,333
Non-current lease liability	314	—
Other non-current liabilities	104	61
Total Non-Current Liabilities	105,520	99,749
Total Liabilities	124,083	120,554
Series A Preferred Units	60,292	56,810
Members' Equity	166,617	149,383
Total Liabilities, Series A Preferred Units, and Members' Equity	$350,992	$326,747

The accompanying notes are an integral part of these consolidated financial statements

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Riley Exploration – Permian, LLC

Consolidated Statements of Operations

($ and units in thousands, except per unit amounts)

	Years Ended September 30,
	2020	2019	2018
Revenues:
Oil and natural gas sales, net	$73,133	$101,096	$69,872
Contract services – related parties	3,800	1,900	—
Total Revenues	76,933	102,996	69,872
Costs and Expenses:
Lease operating expenses	20,997	23,808	11,044
Gathering, processing & transportation	—	—	735
Production taxes	3,526	4,804	3,207
Exploration costs	9,923	5,074	5,992
Depletion, depreciation, amortization and accretion	21,479	20,182	15,714
General and administrative:
Administrative costs	10,826	12,168	14,175
Unit-based compensation expense	963	898	—
Cost of contract services – related parties	503	21	—
Transaction costs	1,431	4,553	878
Total Costs and Expenses	69,648	71,508	51,745
Income From Operations	7,285	31,488	18,127
Other Income (Expense):
Interest expense	(5,299)	(4,924)	(1,707)
Gain (loss) on derivatives	33,876	26,712	(17,143)
Total Other Income (Expense)	28,577	21,788	(18,850)
Net Income (Loss) Before Income Taxes	35,862	53,276	(723)
Income tax expense	(718)	(1,410)	—
Net Income (Loss)	35,144	51,866	(723)
Dividends on preferred units	(3,535)	(3,330)	(3,129)
Net Income (Loss) Attributable to Common Unitholders	$31,609	$48,536	$(3,852)
Net Income (Loss) per Unit:
Basic	$20.67	$31.87	$(2.57)
Diluted	$17.24	$26.03	$(2.57)
Weighted Average Common Units Outstanding:
Basic	1,529	1,523	1,500
Diluted	2,038	1,992	1,500

The accompanying notes are an integral part of these consolidated financial statements

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Riley Exploration – Permian, LLC

Consolidated Statements of Changes in Members' Equity

($ and units in thousands)

	Units Outstanding	Amount
Balance, September 30, 2017	1,500	$111,526
Distributions to Riley Exploration Group, Inc.	—	(275)
Dividends on preferred units	—	(3,129)
Net loss	—	(723)
Balance, September 30, 2018	1,500	$107,399
Issuance of common units under long-term incentive plan	40	4,000
Purchase of common units under long-term incentive plan	(13)	(1,456)
Dividends on preferred units	—	(3,330)
Dividends on common units	—	(9,994)
Unit-based compensation expense	—	898
Net income	—	51,866
Balance, September 30, 2019	1,527	$149,383
Issuance of common units under long-term incentive plan	31	—
Purchase of common units under long-term incentive plan	(3)	(322)
Dividends on preferred units	—	(3,535)
Dividends on common units	—	(15,016)
Unit-based compensation expense	—	963
Net income	—	35,144
Balance, September 30, 2020	1,555	$166,617

The accompanying notes are an integral part of these consolidated financial statements

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Riley Exploration – Permian, LLC

Consolidated Statements of Cash Flows

($ in thousands)

 

	Years Ended September 30,
	2020	2019	2018
Cash Flows from Operating Activities:
Net income (loss)	$35,144	$51,866	$(723)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Oil and gas lease abandonments	7,902	4,839	5,837
Depletion, depreciation, amortization and accretion	21,341	20,182	15,714
Loss on plugging liabilities	138	—	—
(Gain) loss on derivatives	(33,876)	(26,712)	17,143
Settlements on derivative contracts	26,914	514	(7,527)
Amortization of debt issuance costs	648	502	306
Write-off of previously deferred IPO costs	—	2,658	—
Unit-based compensation expense	963	898	—
Deferred income tax expense	665	1,333	—
Changes in operating assets and liabilities:
Accounts receivable	1,515	(2,713)	(3,967)
Accounts receivable – related parties	449	(504)	—
Prepaid expenses and other current assets	839	(1,088)	(138)
Other non-current assets	84	(107)	(6)
Accounts payable and accrued liabilities	16	1,435	8,392
Revenue payable	(84)	(858)	3,036
Advances from joint interest owners	(108)	(238)	552
Net Cash Provided By Operating Activities	62,550	52,007	38,619
Cash Flows From Investing Activities:
Additions to oil and natural gas properties	(47,183)	(77,557)	(68,581)
Acquisitions of oil and natural gas properties	(4,110)	(5,356)	(19,507)
Additions to other property and equipment	(228)	(485)	(301)
Net Cash Used In Investing Activities	(51,521)	(83,398)	(88,389)
Cash Flows From Financing Activities:
Additional issuance costs of Series A Preferred Units	—	—	(30)
Debt issuance costs	(1,476)	—	—
Equity offering costs	—	—	(2,658)
Distribution to Riley Exploration Group, Inc.	—	—	(275)
Net proceeds from revolving credit facility	4,000	43,228	52,607
Payments of notes payable	—	—	(218)
Payment of common unit dividends	(15,297)	(9,994)	—
Purchase of common units under long-term incentive plan	(322)	(1,456)	—
Net Cash Provided By (Used In) Financing Activities	(13,095)	31,778	49,426
Net Increase (Decrease) in Cash and Cash Equivalents	(2,066)	387	(344)
Cash and Cash Equivalents, Beginning of Period	3,726	3,339	3,683
Cash and Cash Equivalents, End of Period	$1,660	$3,726	$3,339

The accompanying notes are an integral part of these consolidated financial statements

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Riley Exploration – Permian, LLC

Consolidated Statements of Cash Flows

($ in thousands)

	Years Ended September 30,
	2020	2019	2018
Supplemental Disclosure of Cash Flow Information Cash Paid For:
Interest	$4,206	$4,212	$1,229
Non-Cash Investing and Financing Activities:
Changes in capital expenditures in accounts payable and accrued liabilities	$(2,301)	$(7,825)	$5,877
Common unit dividends incurred but not paid	$173	$—	$—
Asset retirement obligations	$1,184	$318	$754
Issuance of common units under long-term incentive plan	$—	$4,000	$—
Preferred unit dividends paid in kind	$3,482	$3,281	$3,736
Preferred unit dividends	$3,535	$3,330	$3,129

The accompanying notes are an integral part of these consolidated financial statements

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Riley Exploration – Permian LLC

Notes to the Consolidated Financial Statements

1.
Nature of Business

Riley Exploration – Permian, LLC (“Riley Permian” or the “Company”) is a growth-oriented, independent oil and natural gas company focused on steadily growing our conventional reserves, production and cash flow through the acquisition, exploration, development and production of oil, natural gas and natural gas liquids (“NGLs”) in the Permian Basin. Our activities are primarily focused on the San Andres Formation, a shelf margin deposit on the Central Basin Platform and Northwest Shelf. The Company was formed to focus on opportunities (i) with favorable reservoir and geological characteristics primarily for oil development, (ii) that offer large contiguous acreage positions with significant untapped potential in terms of ultimate recoverable reserves and (iii) with a high degree of operational control. Our acreage is primarily located on large, contiguous blocks in Yoakum County, Texas and Lea, Roosevelt, and Chaves Counties, New Mexico.

Current Commodity Environment

During 2020, a novel strain of coronavirus, SARS-CoV-2, causing a disease referred to as COVID-19, spread quickly across the globe. Federal, state and local governments mobilized to implement containment mechanisms and minimize impacts to their populations and economies. Various containment measures, which included the quarantining of cities, regions and countries, while aiding in the prevention of further outbreak, have resulted in a severe drop in general economic activity and a resulting decrease in energy demand.

Currently, oil and natural gas operations are considered essential in the State of Texas and New Mexico, and the Company has not had any significant disruptions in operations.

This outbreak and the related responses of governmental authorities and others to limit the spread of the virus have significantly reduced global economic activity, resulting in an unprecedented decline in the demand for oil and other commodities. This supply-and-demand imbalance has been exacerbated by uncertainty regarding the future global supply of oil due to disputes between Russia and the members of the Organization of the Petroleum Exporting Countries (“OPEC”), particularly Saudi Arabia, in March 2020. These factors caused a swift and material deterioration in commodity prices in early 2020. With the commodity prices declining throughout the first half of 2020, the Company's reserve value decreased which also resulted in a decreased borrowing base under the Company's revolving credit facility. While the decline in commodity prices and reduced demand negatively impacted the oil and natural gas industry as a whole, the Company had certain commodity hedges in place in order to mitigate and partially offset the negative effects of such price declines. However, the Company cannot estimate the full length or gravity of the impacts of these events at this time and if the pandemic and/or decreased oil prices continue, it could continue to have a material adverse effect on the Company’s results of operations, financial position, liquidity and the value of oil and natural gas reserves.

CARES Act

On March 27, 2020, President Trump signed into law the Coronavirus Aid, and Economic Security Act (“CARES Act”). The Company evaluated the outlook of its future operations, current financial position and liquidity and determined not to take the relief provided by the CARES Act.

2.
Basis of Presentation

These consolidated financial statements include the accounts of Riley Permian and its wholly-owned subsidiaries Riley Permian Operating Company, LLC (“RPOC”) and Riley Employee Member, LLC (“REM”), and have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). All intercompany balances and transactions have been eliminated upon consolidation.

3.
Summary of Significant Accounting Policies

Significant Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management 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 as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

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Riley Exploration – Permian LLC

Notes to the Consolidated Financial Statements— (Continued)

Making accurate estimates and assumptions is particularly difficult as the oil and natural gas industry experiences depressed commodity pricing and reduced global demand from the effects of COVID-19 and actions by OPEC. These circumstances generally increase the estimation uncertainty in the Company's accounting estimates, particularly the Company's reserve estimates.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include, but are not limited to, estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, accounts receivable and accrued operating expenses, the fair value determination of acquired assets and liabilities, certain tax accruals and the fair value of derivatives.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The Company maintains cash at financial institutions which may at times exceed federally insured amounts. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on cash and cash equivalents.

Accounts Receivable

Our receivables arise primarily from the sale of oil, natural gas and NGLs and joint interest owner receivables for properties in which we serve as the operator. Accounts receivable are stated at amounts due, net of an allowance for doubtful accounts, if necessary.

Accounts receivable from oil, natural gas and NGL sales are generally due within 30 to 60 days after the last day of each production month. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items.

To the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. Crude oil is priced based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gas pricing provisions are tied to a market index, with certain adjustments based on, among other factors, quality and heat content of natural gas, and prevailing supply and demand conditions. NGLs are priced based upon a market index with certain adjustments for transportation and fractionation. These market indices are determined on a monthly basis.

Accounts receivable are reviewed periodically and the carrying amount is reduced by a valuation allowance that reflects the best estimate of the amount that may not be collectible. No allowance for uncollectible amounts was required as of September 30, 2020 and 2019.

Accounts receivable as of September 30, 2020 and 2019 is summarized below:

	September 30,
	2020	2019
	($ in thousands)
Oil, natural gas and NGL sales	$6,919	$10,366
Joint interest accounts receivable	1,022	788
Realized derivative receivable	2,187	288
Other accounts receivable	—	201
Total accounts receivable	$10,128	$11,643

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Riley Exploration – Permian LLC

Notes to the Consolidated Financial Statements— (Continued)

Proved Oil and Natural Gas Properties

The Company uses the successful efforts method of accounting for oil and natural gas producing activities. Under this method, all property acquisition costs, and costs of development wells are capitalized as incurred. The costs of development wells are capitalized whether producing or non-producing. Costs to drill exploratory wells are capitalized pending the determination of whether proved reserves are found. If an exploratory well is determined to be unsuccessful, the costs of drilling the unsuccessful exploratory well are charged to exploration costs.

Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved oil and natural gas properties, are charged to exploration costs as incurred. Expenditures incurred to operate and for maintenance, repairs and minor renewals necessary to maintain our oil and natural gas properties in operating condition are charged to lease operating expenses as incurred.

Capitalized costs of proved oil and natural gas properties are amortized using the units-of-production method based on production and estimates of proved reserve quantities. Acquisition costs of proved properties are depleted over total estimated proved reserves, and capitalized development costs of wells and related equipment and facilities are depleted over-estimated proved developed reserves.

On the sale or retirement of a complete unit of a proved property or field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the oil and natural gas property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the unamortized cost of the property is apportioned to the interest sold and the interest retained is accounted for on the basis of the fair value of the retained interests and a gain or loss is recognized.

Unproved Oil and Natural Gas Properties

Unproved oil and natural gas properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we charge the associated unproved lease acquisition costs to exploration costs. Lease acquisition costs related to successful drilling are reclassified to proved oil and natural gas properties.

Upon the sale of an entire interest in an unproved property for cash or cash equivalents, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from the sale of partial interests in unproved oil and natural gas properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

Impairment of Oil and Natural Gas Properties

The cost of proved oil and natural gas properties are assessed for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The expected undiscounted future cash flows of the contributed oil and natural gas properties are compared to the carrying amount of the oil, natural gas and NGL properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the carrying amount of the oil and natural gas properties is adjusted to estimated fair value. Assumptions associated with discounted cash flow models or valuations used in the impairment evaluation include estimates of future crude oil, natural gas and NGL prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. An evaluation is performed on a field-by-field basis at least annually or whenever changes in facts and circumstances indicate that our oil and natural gas properties may be impaired. See further discussion in Note 7 – Fair Value Measurements. The unproved oil and natural gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and record impairment expense for any decline in value.

Business Combinations

The Company accounts for its acquisitions that qualify as a business using the acquisition method under ASC 805 – Business Combinations (“ASC 805”). Under the acquisition method, assets acquired, and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of

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Riley Exploration – Permian LLC

Notes to the Consolidated Financial Statements— (Continued)

significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized as a bargain purchase gain.

Acquisitions of oil and natural gas properties that do not qualify as businesses are accounted for as an asset acquisition in accordance with ASU 2017-01.

Other Property and Equipment, Net

Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 3 to 39 years. Depreciation expense for other property and equipment amounted to $428 thousand, $370 thousand and $286 thousand for the years ended September 30, 2020, 2019 and 2018, respectively. Capitalized costs related to leasehold improvements are depreciated over the life of the lease.

Debt Issuance Costs

Debt issuance costs include origination, arrangement, legal and other fees to issue or amend the terms of credit facility agreements. These debt issuance costs are reported as other non-current assets and recognized on the statement of operations as interest expense by amortizing the costs over the related financing using the straight-line method, which approximates the effective interest method.

Equity Issuance Costs

Equity issuance costs include underwriter, legal, accounting, printing and other fees to issue common equity securities. These issuance costs are netted against offering proceeds at the time of issuance and are reported as other non-current assets when related to the issuance of common equity securities such as an initial public offering (“IPO”). The issuance costs are expensed to the consolidated statement of operations if the issuance is unsuccessful.

Accrued Liabilities

Accrued liabilities as of September 30, 2020 and 2019 consisted of the following:

	September 30,
	2020	2019
	($ in thousands)
Accrued capital expenditures	$2,964	$4,786
Accrued lease operating expenses	1,617	3,503
Accrued ad valorem tax	680	793
Accrued general and administrative costs	2,125	2,570
Accrued interest expense	63	177
Accrued dividends on preferred units	903	851
Accrued dividends on common units	95	419
Other accrued expenditures	299	78
Total accrued liabilities	$8,746	$13,177

Asset Retirement Obligations

Asset retirement obligations (“ARO”) consist of future plugging and abandonment expenses on oil and natural gas properties. The fair value of the ARO is recorded as a liability in the period in which wells are drilled with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted for

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Riley Exploration – Permian LLC

Notes to the Consolidated Financial Statements— (Continued)

the change in its present value each period and the capitalized cost is depreciated using the units-of-production method. The asset and liability is adjusted for changes resulting from revisions to the timing or the amount of the original estimate when deemed necessary. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

Components of the changes in ARO as of September 30, 2020 and 2019 are shown below:

	September 30,
	2020	2019
	($ in thousands)
ARO, beginning balance	$1,203	$843
Liabilities incurred	68	140
Liabilities acquired	1,161	215
Revision of estimated obligations	(45)	57
Liability settlements and disposals	(131)	(94)
Accretion	70	42
ARO, ending balance	2,326	1,203
Less current ARO	(58)	—
ARO, long-term	$2,268	$1,203

Revenue Recognition

Revenue from Contracts with Customers

On October 1, 2018, the Company adopted ASC 606 – Revenue from Contracts with Customers (“ASC 606”) using the modified retrospective approach and has applied the standard to all existing contracts subsequent to adoption as restatement of prior periods is not required. ASC 606 supersedes previous revenue recognition guidance in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services.

Oil Sales

Under the Company’s oil sales contracts, oil that is produced by the Company is delivered to the purchaser at a contractually agreed-upon delivery point at which point the purchaser takes custody, title and risk of loss of the product. Once control has been transferred, the purchaser transports the product to a third party and receives market-based prices from the third party. The Company receives a percentage of proceeds received by the purchaser less transportation costs. As transportation costs are incurred after the transfer of control, the costs are included in oil and natural gas sales and represent part of the transaction price of the contract. The Company recognizes revenue at the net price received when control transfers to the purchaser.

Natural Gas and NGL Sales

Under the Company’s natural gas gathering and processing contracts, natural gas is delivered to the purchaser at the inlet of the purchasers gathering system, at which point title and risk of loss is transferred to the purchaser. The purchaser gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas and NGLs. As the gathering, processing and transportation activities occur after the transfer of control, these costs are netted against our oil and natural gas sales and represent part of the transaction price of the contract, and may exceed the sales price. The Company recognizes revenue on a net basis for amounts expected to be received from third party customers through the marketing process.

Transaction Price Allocated to Remaining Performance Obligations

For the contracts that are short term in nature with a contract term of one year or less, the Company applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration

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Riley Exploration – Permian LLC

Notes to the Consolidated Financial Statements— (Continued)

of one year or less. Based on the Company’s current product sales contracts, with contract terms ranging from one to ten years, each unit of production is considered a separate performance obligation and therefore future production volumes are wholly unsatisfied and do not require allocation or disclosure of the transaction price to remaining performance obligations.

Contract Balances

Under the Company’s product sales contracts, the Company has the right to invoice customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606.

Prior-Period Performance Obligations

Revenue is recorded in the month in which production is delivered to the purchaser. However, certain settlement statements for oil, natural gas and NGLs may not be received for thirty to ninety days after the date production is delivered and, as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences identified between the Company’s revenue estimates and actual revenue received historically have not been significant. For the years ended September 30, 2020, 2019 and 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Disaggregation of Revenue

The following table presents revenues disaggregated by product for the years ended September 30, 2020, 2019 and 2018:

	Years Ended September 30,
	2020	2019	2018
	($ in thousands)
Operating revenues:
Oil	$74,895	$101,619	$68,336
Natural gas	(1,267)	(288)	402
Natural gas liquids	(495)	(235)	1,134
Total operating revenues	$73,133	$101,096	$69,872

Contract Services with Related Parties

The Company has contracts with related parties to provide certain contract operating, accounting and back-office support services. Revenue related to these contract services is recognized over time as the services are rendered, and the fee is stated within the contract at a fixed monthly rate. Costs directly attributable to performing these services are also recognized as the services are rendered. Refer to Note 8 – Transactions with Related Parties for a more detailed discussion regarding these contracts.

Revenue Payable

For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue and royalties payable in the consolidated balance sheets.

Production Costs

Production costs, including payroll for field personnel, saltwater disposal, electricity, generator rentals, diesel fuel and other operating expenses, are expensed as incurred and included in lease operating expenses in our consolidated statements of operations.

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Riley Exploration – Permian LLC

Notes to the Consolidated Financial Statements— (Continued)

Transaction Costs

Transaction costs consist of those costs associated with investment banking, accounting, legal and other diligence costs related to unsuccessful acquisitions, successful acquisitions accounted for as business combinations in accordance with ASC 805 and the write-off of previously capitalized costs related to our abandoned IPO.

	Years Ended September 30,
	2020	2019	2018
	($ in thousands)
Business combination acquisition costs	$1,431	$—	$—
Deferred IPO costs	—	4,553	—
Other	—	—	878
Total transaction costs	$1,431	$4,553	$878

The Company incurred and expensed $1.4 million of transaction costs during the year ended September 30, 2020 related to the subsequent execution of a merger agreement between the Company and Tengasco, Inc (“TGC”) on October 21, 2020. Refer to Note 16 – Subsequent Events for a more detailed discussion regarding the merger agreement.

The Company had deferred $2.7 million of IPO costs on the consolidated balance sheet as of September 30, 2018 that were written off in 2019 and also expensed $1.9 million of additional IPO costs incurred during the year ended September 30, 2019 in conjunction with the abandonment of the Company's IPO.

Income Taxes

The Company and its subsidiaries, with the exception of REM, are not taxpaying entities for federal income tax purposes. Accordingly, a provision for federal income taxes has not been recorded in the Company’s consolidated financial statements. The Company’s income or losses are reflected in the members’ income tax returns in accordance with their ownership percentages. The provision for federal income taxes for REM was de minimus.

The Company is subject to the State of Texas enacted margin-based franchise tax law which is commonly referred to as the Texas margin tax and is assessed at a 0.75% rate. The tax is considered an entity-level tax which makes it applicable to the Company even though we are a partnership for federal tax purposes. The amount is determined by applying the tax rate to the positive difference or margin between the Company’s oil, natural gas and NGL revenue less certain operating expenses pertaining to those assets that we own in the State of Texas. For the years ended September 30, 2020 and 2019, the Company recorded a current tax liability of $241 thousand and $78 thousand and a long-term deferred tax liability of $1.8 million and $1.3 million, respectively. The Company also recognized income tax expense of $0.7 million and $1.4 million, respectively, attributable to the tax liabilities for the years ended September 30, 2020 and 2019. No Texas margin tax was recorded in 2018.

Deferred tax assets and liabilities associated with the Texas margin tax result from temporary differences between the capitalization of the Company’s intangible drilling costs for financial statement purposes and the expensing of these amounts for Texas margin tax purposes. Should a change in the Texas margin tax rates occur, the impact of such change on deferred tax assets and liabilities is recognized as an increase or decrease in income tax expense in the year of the enacted tax rate change. We periodically review deferred tax assets and liabilities and will record a valuation allowance to reduce the carrying values of such assets and liabilities to amounts that are more-likely-than-not to be recognized.

Interest Expense

We have financed a portion of our working capital requirements, capital expenditures and certain acquisitions with borrowings under our revolving credit facility. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. This amount reflects interest, unused commitment fees

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paid to our lender, interest rate swap settlements plus the amortization of deferred financing costs (including origination and amendment fees). Interest expense was $5.3 million, $4.9 million and $1.7 million for the years ended September 30, 2020, 2019 and 2018.

Concentrations of Credit Risk

Our customer concentration may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry.

We sell our production to purchasers at market prices. For the years ended September 30, 2020, 2019 and 2018, Stakeholder Crude Oil Marketing, LLC and Stakeholder Midstream, LLC (collectively “Stakeholder”) accounted for 86%, 85% and 92%, respectively, of our revenues. During 2020, 2019 and 2018, no other purchaser accounted for 10% or more of our revenues. The loss of either of these purchasers could materially and adversely affect our revenues in the short-term. However, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any of our purchasers would not have a long-term material adverse effect on our financial condition and results of operations because oil, natural gas and NGLs are marketable products with well-established markets.

We manage credit risk related to accounts receivable through credit approvals, escrow accounts and monitoring procedures. Accounts receivable are generally not collateralized. However, we routinely assess the financial strength of our customers and, based upon factors surrounding the credit risk, establish an allowance for uncollectible accounts, if required. As a result, we believe that our accounts receivable credit risk exposure beyond such allowance is limited.

Environmental and Other Issues

We are engaged in oil and natural gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental cleanup or restoration, we would be responsible for curing such a violation.

We account for environmental contingencies in accordance with the accounting guidance related to accounting for contingencies. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated.

Fair Value Measurements

Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e. an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

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The carrying values of financial instruments comprising cash and cash equivalents, accounts payable, accounts receivable and related party accounts receivable approximate fair values due to the short-term maturities of these instruments. The carrying value reported for the revolving line of credit approximates fair value because the underlying instruments are at interest rates which approximate current market rates.

Derivative Contracts

We report the fair value of derivatives on the consolidated balance sheets in derivative assets and derivative liabilities as either current or noncurrent based on the timing of the settlement of individual trades. Trades that are scheduled to settle in the next twelve months are reported as current. The Company nets derivative assets and liabilities, in the accompanying consolidated balance sheet, whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract.

For the years ended September 30, 2020, 2019 and 2018, we have not designated our derivative contracts as hedges for accounting purposes, and therefore changes in the fair value of derivatives are recognized in earnings. Cash settlements of contracts are included in cash flows from operating activities in the consolidated statement of cash flows. Derivative contracts are settled on a monthly basis.

The fair value of the derivatives is established using index prices, volatility curves and discount factors. The value we report in our consolidated financial statements is as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors.

The use of derivatives involves the risk that the counterparties to such contracts will be unable to meet their obligations under the terms of the agreement. To minimize the credit risk with derivative instruments, it is our policy to enter into derivative contracts primarily with counterparties that are financial institutions that are also lenders within our credit facility. Under the terms of the current counterparties' contracts, only those that are lenders under our revolving credit facility are secured by the same collateral as outlined in our revolving credit facility. The counterparties are not required to provide credit support to the Company. See further discussion in Note 6 – Derivative Instruments.

Leases

On October 1, 2019, the Company adopted ASC 842 – Leases (“ASC 842”) using the modified retrospective approach and has applied the standard to all existing leases for fiscal year 2020 as restatement of prior periods is not required. ASC 842 supersedes the previous lease accounting requirements in ASC 840 and requires lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance.

The Company reviews all contracts to determine if a lease exists at contract inception. A lease exists when the Company has the right to obtain substantially all of the economic benefit of a specific asset and to control the use of that asset over the term of the agreement. Identified leases are classified as an operating or finance lease, which determines the recognition, measurement and presentation of expenses. As of September 30, 2020, the Company does not have any finance leases. Operating leases are capitalized on the consolidated balance sheet at commencement date through a lease right-of-use (“ROU”) asset and lease liability representing the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease ROU asset includes any lease payments made to the lessor prior to lease commencement less any lease incentives and initial direct costs incurred. Options to extend or terminate leases are included in the lease term when it is reasonably certain the Company will exercise the option. For operating leases, lease costs are recognized on a straight-line basis over the term of the lease.

The Company elected certain practical expedients and made certain accounting policy elections that impacted the effect of adoption on the consolidated balance sheet and statement of operations, including: (i) a package of practical expedients which allowed the Company to not reassess contracts that commenced prior to adoption in regards to lease terms, lease classification and indirect costs incurred prior to adoption, (ii) excluding land easements that existed or expired prior to adoption, (iii) policy election that eliminates the need for adjusting prior period comparable financial statements prepared under prior lease accounting guidance and (iv) to not apply the recognition requirements under the standard to short-term leases.

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The present value of operating lease payments and amortization of the lease liability is calculated using a discount rate. When available, the Company uses the rate implicit in the lease as the discount rate; however, most of the Company’s leases do not provide a readily determinable implicit rate. In such cases, the Company is required to use its incremental borrowing rate (“IBR”). The Company’s IBR reflects the estimated rate of interest that the Company would pay to borrow on a collateralized basis over a similar term and amount equal to the lease payments in a similar economic environment. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date.

Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

The Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842) (“ASU 2016-02”) in February 2016 and subsequent ASU's, which together amend the accounting standards for leases. ASU 2016-02 retains a distinction between finance leases and operating leases. The Company adopted this ASU using the modified retrospective approach and did not have a cumulative-effect adjustment in retained earnings as a result of the adoption. The adoption of this standard did not have a material impact on the Company's consolidated financial statements. See further discussion in Note 9 – Leases.

Issued Accounting Standards Not Yet Adopted

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses and amendments to ASU 2016-13 through subsequent ASU's, which together amend the accounting standards for credit losses. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. Receivables arising from operating leases are not in scope of this subtopic, but rather Topic 842. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2020, and interim periods within fiscal years beginning after December 15, 2021. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on its consolidated financial statements.

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement. The purpose of this amendment is to improve the effectiveness of disclosures in the notes of the financial statements. The amendments will be effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2019. The adoption of this guidance will not have a material impact on the Company's financial statements.

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 840): Facilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., London Interbank Offered Rate (“LIBOR”)) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted as a continuation of the existing contract. This ASU was effective upon the issuance and its optional relief can be applied through December 31, 2022. Due to the Sixth Amendment to the Credit Agreement (“Sixth Amendment”) which included provisions in consideration of the phase out, the Company applied the optional expedient pursuant to ASC 848-20-35-14, which allows reporting entities to not have to reassess the embedded derivatives under ASC 815-15.

The Company is adopting the optional expedient to reduce the costs and complexity of accounting for contract modifications as a result of changes due to reference rate reform.

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4.
Oil and Natural Gas Properties

Oil and natural gas properties are summarized below:

	September 30,
	2020	2019
	($ in thousands)
Proved	$326,420	$291,226
Unproved	32,084	36,658
Work-in-progress	15,398	3,750
	373,902	331,634
Accumulated depletion and amortization	(63,176)	(42,333)
Total oil and natural gas properties, net	$310,726	$289,301

Depletion and amortization expenses for proved oil and natural gas properties was $20.8 million, $19.8 million and $15.4 million, respectively, for the years ended September 30, 2020, 2019 and 2018.

The Company incurred $9.9 million, $5.1 million and $6.0 million of exploration costs for the years ended September 30, 2020, 2019 and 2018, respectively, $7.9 million, $4.8 million and $5.8 million of which relates to the abandonment of oil and natural gas leases. The Company also incurred $2.0 million, $0.3 million and $0.2 million of geological and geophysical costs during the years ended September 30, 2020, 2019 and 2018, respectively.

Acquisitions of Oil and Natural Gas Properties

On December 20, 2019, the Company acquired 38 net acres (unaudited) in Yoakum County, Texas. The acquisition included 17 total wells, with 11 producing and 6 salt water disposals, for a total purchase price of $3.3 million, as adjusted in accordance with the terms of the purchase and sale agreement with J. Cleo Thompson and James Cleo Thompson, Jr., L.P. The effective date of the transaction was August 1, 2019. The transaction was accounted for as an asset acquisition in accordance with ASU 2017-01 and was therefore recorded based on the total consideration paid, with value assigned to unproved oil and natural gas properties and ARO.

During the years ended for September 30, 2020 and 2019 the Company made several additional acquisitions in the ordinary course of business totaling $0.8 million and $1.3 million, respectively, for oil and natural gas properties, none of which individually were considered significant.

On January 8, 2019, the Company acquired 448 net acres (unaudited) in Yoakum County, Texas. The acquisition included 10 total wells, with 2 producing and 3 salt water disposals, for a total purchase price of $4.0 million, as adjusted in accordance with the terms of the purchase and sale agreement with Breitburn Operating, LP. The effective date of the transaction was December 1, 2018. The transaction was accounted for as an asset acquisition in accordance with ASU 2017-01 and was therefore recorded based on the total consideration paid, with value assigned to unproved and proved oil and natural gas properties.

On May 15, 2018, the Company acquired 44,133 net acres (unaudited) in Chaves, Lea, and Roosevelt Counties, New Mexico. The acquisition included 12 total wells, only 1 of which was producing, 1 salt water disposal well and associated gathering lines for a total purchase price of $19.7 million, as adjusted in accordance with terms of the purchase and sale agreement with Rockcliff Operating New Mexico, LLC. The effective date of the transaction is April 1, 2018. The transaction was accounted for as an asset acquisition in accordance with ASU 2017-01 and was therefore recorded based on the total consideration paid, with value assigned to unproved and proved oil and natural gas properties.

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5.
Other Non-Current Assets

Other non-current assets consisted of the following:

	September 30,
	2020	2019
	($ in thousands)
Debt issuance costs, net	$1,867	$1,039
Prepayments to outside operators	284	1,560
Other deposits	98	125
Total other non-current assets	$2,249	$2,724

6.
Derivative Instruments

Crude Oil Contracts

The Company uses derivative contracts to reduce exposure to fluctuations in crude oil prices. While the use of these contracts attempt to limit the downside risk for adverse price changes, their use may also limit future revenues from favorable price changes.

As of September 30, 2020, the Company's oil derivative instruments consisted of the following types:

• Fixed Price Swaps – the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

• Costless collars – the combination of a put option (fixed floor) and call option (fixed ceiling), with the options structured so that the premium paid to purchase the put option is offset by the premium received from the sale of the call option. If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike price, no payments are due from either party.

• Basis Protection Swaps – Basis swaps are settled based on differences between a fixed price differential and the differential between the settlement prices of two referenced indexes. We receive the fixed price differential and pay the differential between the referenced indexes.

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The following table summarizes the open financial derivative positions as of September 30, 2020, related to crude oil production.

		Weighted Average Price
Calendar Quarter	Notional Volume	Fixed	Put	Call
	(Bbl)	($ per Bbl)
Crude Oil Swaps
Q4 2020	339,000	$57.15	$—	$—
Q1 2021	405,000	$53.01	$—	$—
Q2 2021	405,000	$53.01	$—	$—
Q3 2021	405,000	$53.01	$—	$—
Q4 2021	405,000	$53.01	$—	$—
2022	360,000	$45.25	$—	$—
Crude Oil Collars
Q4 2020	45,000	$—	$50.00	$56.48
2022	360,000	$—	$35.00	$42.63
Crude Oil Basis
Q4 2020	384,000	$0.39	$—	$—
Q1 2021	435,000	$0.40	$—	$—
Q2 2021	435,000	$0.40	$—	$—
Q3 2021	435,000	$0.40	$—	$—
Q4 2021	435,000	$0.40	$—	$—

Interest Rate Contracts

The Company has entered into floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage interest rate exposure related to the revolving credit facility.

The notional amount of the interest rate swaps, as of September 30, 2020 and 2019, was $55 million and $40 million, respectively, and expires on September 28, 2021.

Balance Sheet Presentation of Derivatives

The following table presents the location and fair value of the Company’s derivative contracts included in the accompanying consolidated balance sheets as of September 30, 2020 and 2019.

	September 30, 2020
Balance Sheet Classification	Gross Fair Value	Amounts Netted	Net Fair Value
	($ in thousands)
Current derivative assets	$19,690	$(871)	$18,819
Non-current derivative assets	4,651	(1,549)	3,102
Current derivative liabilities	(871)	871	—
Non-current derivative liabilities	(1,549)	1,549	—
Total	$21,921	$—	$21,921

	September 30, 2019
Balance Sheet Classification	Gross Fair Value	Amounts Netted	Net Fair Value
	($ in thousands)
Current derivative assets	$7,982	$(479)	$7,503
Non-current derivative assets	8,135	(199)	7,936
Current derivative liabilities	(807)	479	(328)
Non-current derivative liabilities	(351)	199	(152)
Total	$14,959	$—	$14,959

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The following table presents the Company's derivative activities for the years ended September 30, 2020, 2019 and 2018.

	Years Ended September 30,
	2020	2019	2018
	($ in thousands)
Fair value of net asset (liability), beginning of period	$14,959	$(11,239)	$(1,623)
Gain (loss) on derivatives	33,876	26,712	(17,143)
Settlements on derivatives	(26,914)	(514)	7,527
Fair value of net asset (liability), end of period	$21,921	$14,959	$(11,239)

7.
Fair Value Measurements

Assets and Liabilities Measured on a Recurring Basis

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2020 and 2019, by level within the fair value hierarchy:

	September 30, 2020
	Level 1	Level 2	Level 3	Total
	($ in thousands)
Financial assets:
Commodity derivative assets	$ —	$ 24,341	$ —	$ 24,341
Financial liabilities:
Commodity derivative liabilities	$ —	$(1,672)	$ —	$(1,672)
Interest rate liabilities	$ —	$(748)	$ —	$(748)

	September 30, 2019
	Level 1	Level 2	Level 3	Total
	($ in thousands)
Financial assets:
Commodity derivative assets	$ —	$ 16,117	$ —	$ 16,117
Financial liabilities:
Commodity derivative liabilities	$ —	$(922)	$ —	$(922)
Interest rate liabilities	$ —	$(236	$ —	$(236)

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Assets and liabilities accounted for at fair value on a non-recurring basis in accordance with the fair value hierarchy include the initial recognition of asset retirement obligations and the fair value of oil and natural gas properties when acquired in a business combination or assessed for impairment.

The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs used to determine the fair value include estimates of: (i) reserves; (ii) future commodity prices; (iii) operating and development costs; and (iv) a market-based weighted average cost of capital rate. The underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with New York Mercantile Exchange (NYMEX) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that the Company’s management believes will impact realizable prices. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation.

The fair value of asset retirement obligations incurred and acquired during the years ended September 30, 2020 and 2019, totaled approximately $1.2 million and $0.4 million, respectively. The fair value of additions to the asset retirement obligation liabilities is measured using valuation techniques consistent with the income

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approach, which converts future cash flows to a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well; (ii) estimated remaining life per well; (iii) future inflation factors; and (iv) our average credit-adjusted risk- free rate. These assumptions represent Level 3 inputs.

If the carrying amount of our oil and natural gas properties exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The fair value of our oil and natural gas properties is determined using valuation techniques consistent with the income and market approach. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with the expected cash flow projected. These assumptions represent Level 3 inputs.

8.
Transactions with Related Parties

Contract Services

In May 2019, Combo Resources, LLC (“Combo”) entered into a contract services agreement with RPOC, whereby RPOC became the contract operator on behalf of Combo and provides certain administrative services to Combo in exchange for payment of a fee equal to $250 thousand per month and reimbursement of all third party expenses. This fee was subsequently decreased to $150 thousand per month effective July 1, 2020 and further decreased to $100 thousand per month effective August 1, 2020. Combo is owned by Oakspring Energy Holdings, LLC (“Oakspring”) and by a wholly- owned subsidiary of Riley Exploration Group, Inc. (“REG”).

The Company recognized $2.6 million and $1.5 million in the years ended September 30, 2020 and 2019, respectively, in revenue under the contract services agreement and had an accounts receivable of $55 thousand $343 thousand as of September 30, 2020 and 2019, respectively.

In May 2019, REG entered into a contract services agreement with RPOC with an effective date of May 1, 2019, whereby RPOC will provide certain operational services to REG in exchange for payment of a fee equal to $75 thousand per month. This fee was subsequently increased to $100 thousand per month effective September 1, 2019.

The Company recognized $1.2 million and $0.4 million in the years ended September 30, 2020 and 2019, respectively, in revenue under the contract services agreement and had an accounts receivable of $0 thousand and $161 thousand as of September 30, 2020 and 2019, respectively.

The Company identified costs directly relating to the performance of its obligations under these contract service agreements and recognized $503 thousand and $21 thousand of costs during the years ended September 30, 2020 and 2019.

Oakspring and REG are portfolio companies of Yorktown Energy Partners XI, L.P. (“Yorktown XI”), certain managed funds of which have investments in the Company (all deemed to be related parties).

One of our executives held positions with REG and Combo at September 30, 2020. Our Executive Vice President, Business Intelligence is the President of both REG and Combo, as well as a board member of Combo. Our former Executive Vice President, Geoscience, who is no longer with the Company as of February 18, 2020, is the President of Oakspring.

9.
Leases

The Company’s current leases include office space and information technology equipment, comprised of printers and copiers. All current leases are structured with non-cancelable terms of one to three years. The Company leased office space for its corporate headquarters in Oklahoma City, Oklahoma and has renewal options that are not reasonably certain to be exercised. The corporate headquarters is under a five-year operating lease agreement terminating in July 2022 and is subject to a two percent (2%) escalation with each subsequent year. However, the Company’s leased office space for its field offices in La Grange, Texas have renewal options that the

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Company reasonably expects to exercise to align termination dates with its corporate office lease and therefore has included these renewal periods in the total ROU asset and lease liability calculations at inception. The Company’s leases for printers and copiers do not have renewal options.

At adoption, the Company recorded a total of $1.0 million in operating lease ROU assets and corresponding current and non-current lease liabilities on the accompanying consolidated balance sheet.

Lease expense for the year ended September 30, 2020 totaled $417 thousand and is included as general and administrative costs on the accompanying consolidated statements of operations.

Supplemental cash flow information related to the Company’s operating leases is included in the following table:

	September 30, 2020
	($ in thousands)
Cash paid for amounts included in the measurement of lease liabilities	$410
ROU assets added in exchange for lease obligations (since adoption)	40

The following table summarizes the Company’s weighted average remaining lease term and weighted average discount rate for operating leases in effect as of September 30, 2020:

	September 30, 2020
Weighted Average Remaining Lease Term	1.8 Years
Weighted Average Discount Rate	5.17%

The following table summarizes the undiscounted cash flows owed by the Company to lessors pursuant to contractual agreements in effect as of September 30, 2020:

	Operating Leases
	($ in thousands)
2021	$419
2022	320
2023	1
Thereafter	—
Total future minimum lease payments	740
Less imputed interest	(34)
Present value of future minimum lease payments	$706

As of September 30, 2019 future lease payment obligations under ASC Topic 840 were as follows:

	Operating Leases
	($ in thousands)
Fiscal Year 2020	$389
Fiscal Year 2021	378
Fiscal Year 2022	288
Thereafter	—
Total future minimum lease payments	$1,055

10.
Revolving Credit Facility

On September 28, 2017, the Company and SunTrust Robinson Humphrey, Inc., now Truist Bank as successor by merger, as lead arranger and administrative agent, entered into a credit agreement to establish a senior secured revolving credit facility. The credit facility had an initial borrowing base of $25 million with a maximum facility amount of $500 million. The credit facility maturity date is set on September 28, 2023 in accordance with the Sixth Amendment effective August 31, 2020. Substantially all of the Company’s assets are secured under the credit facility.

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Notes to the Consolidated Financial Statements— (Continued)

Effective February 27, 2018, the Company amended its credit facility to increase the borrowing base from $25 million to $60 million. Effective May 25, 2018, the Company amended its credit facility to increase the borrowing base from $60 million to $100 million. Effective November 9, 2018, the Company amended its credit facility to increase the borrowing base from $100 million to $135 million. Effective April 3, 2019, the Company amended its credit facility to allow for a future increase in the borrowing base from $135 million to $175 million. Effective October 15, 2019, the Company amended its credit facility to increase the borrowing base from $135 million to $180 million and has the ability to request an increase in its lender commitments up to the approved $200 million borrowing base amount. Effective May 7, 2020 the Company amended its credit facility to decrease the borrowing base from $180 million to $150 million. Effective August 31, 2020 the Company amended its credit facility to decrease the borrowing base from $150 million to $132.5 million.

The borrowing base is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The facility currently requires semi-annual redeterminations on February 1 and August 1. During these redetermination periods, the Company’s borrowing base may be increased and may also be reduced in certain circumstances. The credit facility allows for Eurodollar Loans and Base Rate Loans (each as defined in the credit agreement). The interest rate on each Eurodollar Loan will be the adjusted LIBOR for the applicable interest period plus a margin between 2.50% and 3.50% (depending on the borrowing base utilization percentage). The annual interest rate on each Base Rate Loan is (i) the greatest of (a) the administrative agent’s prime lending rate, (b) the federal funds rate plus 0.5% per annum or (c) the adjusted LIBOR determined on a daily basis for an interest period of one-month, plus 1.00% per annum, plus (ii) a margin between 1.50% and 2.50% (depending on the borrowing base utilization percentage). The Company is also subject to an unused commitment fee of between 0.375% and 0.500% (depending on the borrowing base utilization percentage). Interest expense and unused commitment fees related to the credit facility for the years ended September 30, 2020, 2019 and 2018, totaled $4.7 million, $4.4 million and $1.4 million, respectively. The amortization of debt issuance costs for the years ended September 30, 2020, 2019 and 2018 was $648 thousand, $502 thousand and $306 thousand, respectively. The weighted average interest rate as of September 30, 2020, 2019 and 2018 was 4.09%, 5.63% and 5.14%, respectively.

In July 2017, the United Kingdom's Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR as a benchmark by the end of 2021. The Company’s revolving credit facility includes provisions which account for this potential phase out and provides consideration for use of a commercially viable substitute if necessary.

The credit agreement contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio of not more than 3.5 to 1.0 and (ii) a minimum current ratio of 1.0 to 1.0 as of the last day of any fiscal quarter. The credit agreement also contains a total leverage ratio for Restricted Payments after giving pro forma effect to such Restricted Payments, which includes payments to any holder of the Company's capital units, would not exceed 2.75 to 1.0. The Company is also required to prepay the credit facility if at any time the consolidated cash balance is in excess of the greater of $15 million or 10% of the borrowing base for five consecutive business days and the Company has not identified an approved intended use for the excess cash. The credit agreement also contains other customary affirmative and negative covenants and events of default. The Company’s minimum hedging requirement was 50% as of September 30, 2020.

As of September 30, 2020, the Company was in compliance with all covenants contained in the credit agreement and had $101 million of outstanding borrowings and an additional $31.5 million available under the credit facility.

11.
Members’ Equity

On December 27, 2017 the Company's Board of Managers approved an amendment to the Second Amended and Restated Limited Liability Company Agreement which authorized 2,265,200 common units and 512,667 of Series A Preferred Units.

On December 31, 2018, the Company’s Board of Managers approved the Third Amended and Restated Limited Liability Company Agreement (the “Third LLC Agreement”), which removed references to the previously designated 2,265,200 total number of units authorized for issuance as common units and 512,667 as Series A Preferred and replaced the references to a fixed number of authorized units with a provision that defines the total

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Notes to the Consolidated Financial Statements— (Continued)

number of units as any units that are authorized and approved for issuance by the Board of Managers under the provisions of the Third LLC Agreement. As of September 30, 2020, the common units authorized and approved by the Board of Managers totaled 1,555,049 and the total number of Preferred Series A Units were 504,168.

The Third LLC Agreement reserved and authorized 200,128 common units for issuance pursuant to the Company’s 2018 Long-Term Incentive Plan (the “2018 LTIP”). The Company also granted 40,000 unrestricted common units and simultaneously repurchased 12,540 of these common units. This grant was issued to settle the Company's liability associated with a 2018 incentive compensation award earned by certain executives. During the year ended September 30, 2020, the Company repurchased an additional 1,669 of these common units related to the 2018 LTIP, leaving 174,337 remaining for future issuances. See further discussion in Note 13 – Unit-Based Compensation.

On April 29, 2019, the Company granted 14,766 restricted units to certain executives which vest over a defined period. On January 23, 2020, the Company modified the vesting date related to these restricted units to February 1 for each subsequent vesting date beginning February 1, 2020, which 5,374 restricted units vested. Simultaneously, the Company granted an additional 15,767 restricted units to certain executives of which 1,229 shares were repurchased by the Company. On April 28, 2020, certain executives surrendered 1,250 restricted units, which reduced the 2018 LTIP common units available for issuances to 146,283. See further discussion in Note 13 – Unit-Based Compensation.

For the years ended September 30, 2020 and 2019, the Company authorized and declared quarterly cash dividends totaling approximately $15 million and $10 million, respectively. The cash dividends were declared for all issued and outstanding common units including the vested and unvested 2018 LTIP units of the Company. The portion of the cash dividend attributable to the unvested restricted units was accrued and will be paid in cash once the unvested restricted units fully vest. Cash dividends are approved at the sole discretion of the Board of Managers. As of August 13, 2020, the Company entered into the Fourth Amended and Restated Limited Liability Agreement (the “Fourth LLC Agreement”) which restricts the declaration and payment of any distribution or dividend to the discretion of the Board of Managers. The credit agreement restricts the payment of any dividend or distribution on any of the Company's class of capital stock from the revolving credit facility. See further discussion in Note 10 – Revolving Credit Facility regarding restricted payments.

12.
Preferred Units

In March of 2017, the Company closed a private offering of convertible preferred securities (the “Series A Preferred Units”) to Yorktown XI, Bluescape Riley Exploration Holdings, LLC (“BREH”) and Boomer Petroleum LLC (“Boomer”) that resulted in proceeds of approximately $40 million, net of issuance costs, to fund general business purposes and resulted in the issuance of 333,334 Series A Preferred Units. Series A Preferred Units are entitled to distributions at the rate of 6% per annum of the Series A outstanding principal amount and shall accrue from day to day, whether or not declared, and shall be cumulative. Dividends on Series A Preferred Units shall be payable in kind by the issuance of additional Series A Preferred Units, however, the Board of Managers may determine in its sole discretion to pay Series A Preferred dividends in cash. The Fourth LLC Agreement declared the end date of the Series A Preferred Dividends to be on December 31, 2022.

On September 7, 2017, the Company closed a follow-on offering of the Series A Preferred Units to Yorktown XI, BREH and Boomer that resulted in proceeds of approximately $10 million, net of issuance costs, to fund general business purposes and resulted in the subsequent issuance of an additional 83,333 Series A Preferred Units.

Under the Third LLC Agreement, the mandatory redemption date for all outstanding Series A Preferred Units in cash was December 31, 2022. The Fourth LLC Agreement extended the mandatory redemption date for all outstanding Series A Preferred Units in cash to one year following the expiration of the credit agreement (as may be further amended, restated, supplemented, modified or replaced from time to time) which is currently set to mature on September 28, 2023. At any time prior to an IPO or Listing Transaction and at such holder’s sole discretion, a holder of Series A Preferred Units may elect to convert such Series A Preferred Units to a number of common units in an amount equal to the quotient of (i) the product of the number of Series A Preferred Units to be converted by the Series A preferred liquidation preference, divided by (ii) the Series A conversion price then in effect by the delivery of written notice to the Company. Immediately prior to any conversion, all accrued

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Notes to the Consolidated Financial Statements— (Continued)

and undeclared but unpaid dividends on the Series A Preferred Units shall be paid in kind to such holder of Series A Preferred Units electing to convert its units. The Series A Preferred conversion price is $120 per unit for the periods presented, as adjusted to reflect any subdivision, stock split, recapitalization, reclassification or consolidation of the common units.

Immediately following the execution of an underwriting agreement, but prior to the closing of an IPO or Listing Transaction, all outstanding Series A Preferred Units shall be automatically converted into Listed Shares at a conversion rate equal to the quotient of (i) the product of the number of Series A Preferred Units to be converted multiplied by the Series A Preferred Liquidation Preference, divided by (ii) the lesser of the Series A Conversion Price or the IPO Conversion Price. The conversion will result in a deemed preferred distribution to the Series A Preferred Unit holders, which will reduce income attributable to common units in the period in which the conversion occurs.

The holders of the Series A Preferred Units have the same voting rights as if such Series A Preferred Units were converted into common units in accordance with the Series A Conversion Price then in effect and shall vote with the common units as a single class. Under the Fourth LLC Agreement, the affirmative vote or consent of at least an 85% Supermajority Interest of the members of the then-outstanding common units on an as-converted basis, voting together as a single class, shall be necessary for effecting or validating any amendment, alteration or repeal of the certificate of formation or the Fourth LLC Agreement, which materially and adversely affects the rights or preferences of the holders of the Series A Preferred Units, issuance or reclassification of membership interests ranking pari passu or senior to the Series A Preferred Units, any transaction between the Company and any of its officers, holders of its units, directors of Affiliates, any increase in indebtedness for money borrowed by the Company, a call for capital contributions from holders of the Series A Preferred Units and any Company Event (as defined in the Fourth LLC Agreement) in which the holders of the Series A Preferred Units do not receive, upon the consummation of the Company Event of an amount in cash equal to the Series A Preferred issue amount with respect to each outstanding Series A Preferred Unit, plus any accrued but unpaid dividends on the Series A Preferred Units as of such date. In the event an 85% Supermajority Interest of the outstanding Series A Preferred Units, voting together as a single class with the common units, do not approve a Company Event (as defined in the Fourth LLC Agreement), the Company may elect to redeem the outstanding Series A Preferred Units in cash.

The table below summarize the changes in preferred units during the years ended September 30, 2020, 2019 and 2018:

	Units	Amount
	($ in thousands)
Balance, September 30, 2017	416,667	$49,793
Dividends paid in kind	31,142	3,736
Balance, September 30, 2018	447,809	53,529
Dividends paid in kind	27,343	3,281
Balance, September 30, 2019	475,152	56,810
Dividends paid in kind	29,016	3,482
Balance, September 30, 2020	504,168	$60,292

During the year ended September 30, 2020, the Company issued 29,016 units of Series A Preferred Units as paid in kind dividends. As of September 30, 2020 and September 30, 2019, the Company had accrued dividends payable on the Series A Preferred Units of $903 thousand and $851 thousand, respectively, which are included in accrued liabilities on the consolidated balance sheets.

In accordance with ASC 480-10-S99 Distinguishing Liabilities From Equity, equity securities are required to be classified outside of permanent equity in temporary equity if they are redeemable or may become redeemable for cash or other assets. As the Company is not considered to have sole control over the contractually mandated redemption which is currently set for redemption in 2024, the Series A Preferred Units have been classified as mezzanine equity.

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Notes to the Consolidated Financial Statements— (Continued)

13.
Unit-Based Compensation

Long-Term Incentive Plan

Unrestricted Units: Pursuant to the terms of the employment letters for certain executives, the Company was obligated to pay an incentive compensation award of $4 million that was fully earned on June 26, 2018, with payment due at the earlier of either a successful IPO or January 2, 2019. The method of payment was at the full discretion of the Board and in the event the obligation was not settled in IPO shares, the Board could elect to settle the obligation in the form of cash or common units of the Company. On December 31, 2018, the Board elected to issue 40,000 common units under the Company’s 2018 LTIP valued at $4.644 million or $116.10 per unit in settlement of this obligation. The Company determined the fair value of the common units in accordance with FASB ASC 718 using an options pricing model. Upon issuance of the 40,000 common units, the Company also repurchased 12,540 shares from these executives for payment of their employee tax withholding obligations, resulting in a net issuance of 27,460 common units. On October 15, 2019, the Company repurchased an additional 1,669 shares from these executives for final payment of their employee tax withholding obligations. As of September 30, 2018, the Company accrued for the obligation and recorded general and administrative costs of $4 million pending the finalization of the settlement terms. Given that the fair value of the shares granted was greater than the initial amount accrued as of September 30, 2018, which constituted a modification of the award, the Company recorded additional unit-based compensation expense in the amount of $644 thousand during the year ended September 30, 2019.

Restricted Units: The Company granted 14,766 restricted units to certain executives on April 29, 2019. Restricted units vest over a two- to three-year period and the holder receives dividends, in arrears, once the units vest. The Company has accrued for these dividends in accrued liabilities and other non-current liabilities. The Company determined the fair value of the restricted units at $113.25 per unit for the units granted on April 29, 2019, in accordance with FASB ASC 718, using market comparisons and an option pricing model. The total expense is amortized on a straight-line basis, over the vesting period. The Company recorded $676 thousand and $254 thousand, respectively, of unit-based compensation expense for the years ended September 30, 2020 and 2019 related to this issuance. Approximately $767 thousand of additional unit- based compensation expense will be recognized associated with this grant over the next 17 months.

On January 23, 2020, the Company modified the initial vesting date for the restricted units granted on April 29, 2019 to February 1, 2020 and set each subsequent vesting date on the modified vesting date anniversary, which 5,374 restricted units vested on February 1, 2020. The Company simultaneously granted an additional 15,767 restricted units to certain executives which vest over a three-year period and the Company repurchased 1,229 shares from these executives for payment of their employee tax withholding obligations, resulting in a net issuance of 14,538. On April 24, 2020, 1,250 shares were surrendered from the departure of an executive from the Company. The Company determined the fair value of the restricted units at $100.69 per unit for the units granted on February 1, 2020, in accordance with FASB ASC 718, using market comparisons and an option pricing model. The total expense is amortized on a straight-line basis, over the vesting period. The Company recorded $287 thousand of unit-based compensation expense for the year ended September 30, 2020 related to this issuance. Approximately $1.2 million of additional unit-based compensation expense will be recognized associated with this grant over the next 29 months.

Total unit-based compensation expense of $963 thousand and $898 thousand, respectively, is included in general and administrative costs on the Company's consolidated statement of operations for all of the issuances outstanding at September 30, 2020 and 2019. The Company will recognize any forfeited units, and any unpaid dividends for those units, as they occur as a reduction to accrued liabilities and members' equity on the consolidated balance sheet.

14.
Net Income (Loss) Per Unit

Basic net income (loss) per unit is computed by dividing net income (loss) attributable to common unitholders by the weighted average number of units outstanding during each period.

Diluted net income (loss) per unit reflects the potential impact of dilutive securities. In periods of net loss, potentially dilutive units are excluded from the calculation because they are anti-dilutive.

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Notes to the Consolidated Financial Statements— (Continued)

The table below sets forth the computation of basic and diluted net income (loss) per unit for the years ended September 30, 2020, 2019 and 2018:

	Years Ended September 30,
	2020	2019	2018
Net income (loss) attributable to common unitholders (in thousands) − Basic	$31,609	$48,536	$(3,852)
Plus: Dividends on preferred units	3,535	3,330	3,129
Net income (loss) (in thousands) − Diluted	$35,144	$51,866	$(723)
Basic weighted-average common units outstanding	1,528,555	1,522,883	1,500,000
Effecting of dilutive securities:
Series A preferred units	490,735	462,493	—
Restricted units	18,663	6,822	—
Diluted weighted-average common units outstanding	2,037,953	1,992,198	1,500,000
Net income (loss per unit):
Basic	$20.67	$31.87	$(2.57)
Diluted	$17.24	$26.03	$(2.57)

As of September 30, 2020 and 2019, 6,496 and 12,527 restricted stock units, respectively, were excluded from the calculation of diluted net income per unit due to their anti-dilutive effect. The Company did not have any restricted stock units issued or outstanding during the year ended September 30, 2018.

15.
Commitments and Contingencies

Legal Matters

On December 10, 2020 a purported shareholder of TGC filed a lawsuit against TGC, the members of the TGC board of directors, Merger Sub (as defined below), and the Company in the United States District Court, District of Delaware, captioned Lewis D. Baker v. Tengasco, Inc. (the “Baker complaint”). The plaintiffs in the Baker complaint generally claim that the defendants disseminated a false or misleading registration statement regarding the proposed merger in violation of Section 14(a) and Section 20(a) of the Exchange Act and/or Rule 14a-9 promulgated under the Exchange Act. The plaintiffs seek, among other things, injunctive relief to prevent consummation of the merger until the alleged disclosure violations are cured, damages in the event the merger is consummated, and an award of attorney's fees and costs. The Company is evaluating such litigation and an estimate of loss, if any, cannot be made. Refer to Note 16 – Subsequent Events for a more detailed discussion regarding the merger agreement.

In addition to the matter disclosed above, the Company is party to certain lawsuits arising in the ordinary course of the Company’s business. The Company cannot predict the outcome of any such lawsuits with certainty, but management believes it is remote that pending or threatened legal matters will have a material adverse impact on the Company’s financial condition.

Due to the nature of the Company's business, the Company may at times be subject to claims and legal actions. The Company accrues liabilities when it is probable that future costs will be incurred, and such costs can be reasonably estimated. Such accruals are based on developments to date and the Company’s estimates of the outcomes of these matters. The Company did not recognize any material liability as of September 30, 2020 and 2019. Management believes it is remote that the impact of such matters will have a materially adverse effect on the Company’s financial position, results of operations, or cash flows.

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Notes to the Consolidated Financial Statements— (Continued)

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws, which are often changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. The Company recorded no environmental liabilities as of September 30, 2020 and 2019.

16.
Subsequent Events

Events that could materially affect our financial position and results of operations after the year ended September 30, 2020, have been reviewed and evaluated by the Company as of December 23, 2020, the date the financial statements were issued.

Tengasco Merger

On October 21, 2020, TGC and the Company entered into a definitive merger agreement under which TGC plans to acquire the Company and all its subsidiaries in exchange for approximately 203 million shares of TGC common stock (the “Transaction”). TGC formed Antman Sub LLC (“Merger Sub”) as a direct wholly-owned subsidiary that will merge into the Company. The merger between the Company and Merger Sub will result in the Company's common units being exchanged for TGC stock. As part of the Transaction, TGC will be renamed Riley Exploration Permian, Inc. (“REPX”) and the Company will become a wholly-owned subsidiary of REPX.

Immediately prior to the merger, the Company will convert all of the issued and outstanding Series A Preferred Units into common units of the Company. In connection with the merger, unit holdings of the Company will be entitled to receive, in exchange for each common unit, shares of TGC (to be renamed REPX) par value $0.001 per share (“TGC common stock”) based on an exchange ratio set forth in the merger agreement (the “Exchange Ratio”), with cash paid in lieu of the issuance of any fractional shares, which we refer to as the “merger consideration.” The Exchange Ratio will be 97.796467 shares of TGC common stock for each common unit of the Company.

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Supplemental Oil And Gas Information

(unaudited)

17.
Supplemental Oil and Gas Information (Unaudited)

Capitalized Costs

Capitalized costs include the cost of properties, equipment and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress.

Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. For a summary of these costs, please refer to Note 4 – Oil and Natural Gas Properties.

Costs Incurred for Property Acquisition, Exploration and Development

Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and natural gas property acquisition, exploration and development activities. Costs incurred also include new AROs established in the current year as well as increases or decreases to ARO resulting from changes to cost estimates during the year.

Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells and construction of related production facilities.

The following summarizes the costs incurred for oil and natural gas property acquisition, exploration and development activities for the years ended September 30, 2020, 2019 and 2018:

	Years Ended September 30,
	2020	2019	2018
	($ in thousands)
Acquisition of properties
Proved	$1,187	$1,962	$5,887
Unproved	5,331	8,604	14,002
Exploration costs	8,039	5,074	5,992
Development costs	43,684	64,127	68,765
Total costs incurred	$58,241	$79,767	$94,646

Results of Operations

The following table includes revenues and expenses associated with the Company's oil and natural gas producing activities. They do not include any allocation of the Company's interest costs or general corporate overhead. They also do not include estimated corporate taxes since the Company is not a taxpaying entity for federal income tax purposes. Therefore, the following schedule is not necessarily indicative of the contribution of net earnings of the Company's oil and natural gas operations.

	Years Ended September 30,
	2020	2019	2018
	($ in thousands)
Oil, natural gas and NGL sales	$73,133	$101,096	$69,872
Lease operating expenses	20,997	23,808	11,044
Gathering, processing & transportation	—	—	735
Production taxes	3,526	4,804	3,207
Exploration costs	9,923	5,074	5,992
Depreciation, depletion, amortization, impairment and accretion	21,479	20,182	15,714
Results of operations	$17,208	$47,228	$33,180

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Supplemental Oil And Gas Information— (Continued)

(unaudited)

Oil, Natural Gas and NGL Quantities

Our reserve reports, as of September 30, 2020, 2019 and 2018, were prepared by Netherland Sewell & Associates and are presented below. All reserves are located within the continental United States. Proved oil, natural gas and NGL reserves are the estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimate is made. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are decline curve analysis, advance production type curve matching, petrophysics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

The following table sets forth information for the years ended September 30, 2020, 2019 and 2018 with respect to changes in the Company’s proved (i.e. proved developed and undeveloped) reserves:

	Crude Oil	Natural Gas	NGLs	Total
	(Mbbl)	(MMcf)	(Mbbl)	(Mboe)
September 30, 2017	12,025.9	4,820.5	1,179.3	14,008.6
Extensions, discoveries and other additions	9,829.0	4,721.0	990.6	11,606.4
Acquisitions	1,361.1	379.6	81.3	1,505.7
Revisions	1,613.9	2,355.4	235.0	2,241.5
Production	(1,187.5)	(198.1)	(40.5)	(1,261.0)
September 30, 2018	23,642.4	12,078.4	2,445.7	28,101.2
Extensions, discoveries and other additions	13,669.5	13,658.2	3,633.5	19,579.4
Acquisitions	258.5	127.6	34.2	314.0
Revisions	1,563.5	16,013.4	4,833.8	9,066.2
Production	(1,975.0)	(886.2)	(135.0)	(2,257.7)
September 30, 2019	37,158.9	40,991.4	10,812.2	54,803.1
Extensions, discoveries and other additions	2,265.1	3,029.8	642.4	3,412.5
Revisions	(205.9)	11,290.2	(513.3)	1,162.5
Production	(2,060.4)	(1,627.9)	(259.8)	(2,591.5)
September 30, 2020	37,157.7	53,683.5	10,681.5	56,786.6
Proved Developed Reserves, Included Above
September 30, 2017	7,064.4	2,814.3	692.1	8,225.5
September 30, 2018	13,764.0	7,481.0	1,485.8	16,496.6
September 30, 2019	19,197.6	23,096.0	6,044.9	29,091.8
September 30, 2020	19,149.0	31,137.6	5,847.1	30,185.7
Proved Undeveloped Reserves, Included Above
September 30, 2017	4,961.5	2,006.2	487.2	5,783.1
September 30, 2018	9,878.4	4,597.4	959.9	11,604.6
September 30, 2019	17,961.3	17,895.4	4,767.3	25,711.3
September 30, 2020	18,008.7	22,545.9	4,834.4	26,600.9

As of September 30, 2020, reserves were comprised of 65.4% crude oil, 15.8% natural gas, and 18.8% NGL. 2020 proved reserves were derived based on prices of $41.91 per Bbl of crude oil, $(0.06) per Mcf of natural gas and $(1.96) per Bbl of NGL. Prices used in the 2020 reserve report are based on the 12-month unweighted

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Supplemental Oil And Gas Information— (Continued)

(unaudited)

arithmetic average of the first-day-of- the-month price for each month in the period October 2019 through September 2020. For oil and NGL volumes, the average West Texas Intermediate (WTI) spot price of $43.63 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub spot price of $1.967 per MMbtu is adjusted for energy content, transportation fees, and market differentials. As a reference, the average NYMEX WTI and NYMEX Henry Hub prices for the same period were $43.40 per Bbl and $2.020 per MMbtu, respectively.

As of September 30, 2019, reserves were comprised of 67.8% crude oil, 12.5% natural gas, and 19.7% NGL. 2019 proved reserves were derived based on prices of $54.38 per Bbl of crude oil, $(0.32) per Mcf of natural gas, and $(5.19) per Bbl of NGL. Prices used in the 2019 reserve report are based on the 12-month unweighted arithmetic average of the first-day-of- the-month price for each month in the period October 2018 through September 2019. For oil and NGL volumes, the average WTI spot price of $57.69 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub spot price of $2.870 per MMbtu is adjusted for energy content, transportation fees, and market differentials. As a reference, the average NYMEX WTI and NYMEX Henry Hub prices for the same period were $57.77 per Bbl and $2.834 per MMbtu, respectively.

As of September 30, 2018, reserves were comprised of 84.1% crude oil, 7.2% natural gas, and 8.7% NGL. 2018 proved reserves were derived based on prices of $57.92 per Bbl of crude oil, $1.62 per Mcf of natural gas and $10.25 per Bbl of NGL. Prices used in the 2018 reserve report are based on the 12-month unweighted arithmetic average of the first-day-of- the-month price for each month in the period October 2017 through September 2018. For oil and NGL volumes, the average WTI spot price of $63.43 per Bbl is adjusted for quality, transportation fees, and market differentials. The fees associated with the transportation contract are included as a deduction to oil revenue. For gas volumes, the average Henry Hub spot price of $2.914 per MMbtu is adjusted for energy content, transportation fees, and market differentials. As a reference, the average NYMEX WTI and NYMEX Henry Hub prices for the same period were $63.43 per Bbl and $2.880 per MMbtu, respectively.

For the year ended September 30, 2020, the Company had upward revisions of previous estimates of 1,162.5 Mboe. These revisions consisted of a positive revision of 1,839.6 Mboe due to pricing and differentials, a downward revision of 1,952.1 Mboe due to lease operating expenses and a positive revision of 1,275.0 Mboe which was the result of better well performance that exceeded previous estimates. The Company had extensions, discoveries and other additions to proved developed and proved non-developed reserves of 3,412.5 Mboe which consisted of 1,404.4 Mboe as a result of drilling successful wells that were previously classified as unproved locations, and the addition to proved undeveloped of 2,008.1 Mboe as a result of drilling successful wells offsetting locations that were previously unproven locations. During the fiscal year in 2020, the Company did not purchase any additional reserves.

For the year ended September 30, 2019, the Company had upward revisions of previous estimates of 9,066.2 Mboe. These revisions consisted of a positive revision of 8.0 Mboe due to pricing and differentials, a positive revision of 9.1 Mboe due to lease operating expenses and a positive revision of 9,049.1 Mboe which was the result of better well performance that exceeded previous estimates. As a result of ongoing drilling and completion activities during the fiscal year in 2019, the Company reported extensions, discoveries, and other additions of 19,579.4 Mboe. The extensions, discoveries and other additions to proved developed and proved non-developed reserves consisted of 3,833.9 Mboe as a result of drilling successful wells that were previously classified as unproved locations, and the addition to proved undeveloped of 15,745.5 Mboe as a result of drilling successful wells offsetting locations that were previously unproven locations. Additionally, during the fiscal year in 2019, the Company purchased reserves of 314.0 Mboe.

For the year ended September 30, 2018, the Company had upward revisions of previous estimates of 2,241.5 Mboe. These revisions consisted of a positive revision of 34.2 Mboe due to pricing and differentials, a positive revision of 1.6 Mboe due to lease operating expenses and a positive revision of 2,205.7 Mboe which was the result of better well performance that exceeded previous estimates. As a result of ongoing drilling and completion activities during the fiscal year in 2018, the Company reported extensions, discoveries, and other additions of 11,606.4 Mboe. The extensions, discoveries and other additions to proved developed and proved non-developed reserves consisted of 3,973.4 Mboe as a result of drilling successful wells that were previously

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(unaudited)

classified as unproved locations, and the addition to proved undeveloped of 7,633.0 Mboe as a result of drilling successful wells offsetting locations that were previously unproven locations. Additionally, during the fiscal year in 2018, the Company purchased reserves of 1,505.7 Mboe.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The Company follows the guidelines prescribed in ASC Topic 932 Extractive Activities – Oil and Gas for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The following summarizes the policies used in the preparation of the accompanying oil, natural gas and NGL reserve disclosures, standardized measures of discounted future net cash flows from proved oil, natural gas and NGL reserves and the reconciliations of standardized measures from year to year.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: (i) estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions; (ii) estimated future cash flows are compiled by applying the twelve month average of the first of the month prices of crude oil and natural gas relating to the Company’s proved reserves to the year-end quantities of those reserves for reserves; (iii) future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions, plus Company overhead incurred; (iv) future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Company’s proved oil and natural gas reserves; and, (v) future net cash flows are discounted to present value by applying a discount rate of 10%.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the Securities and Exchange Commission. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations, since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company’s oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

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(unaudited)

The following summary sets forth the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure prescribed in ASC Topic 932:

	September 30,
	2020	2019	2018
	($ in thousands)
Future crude oil, natural gas and NGLs sales(1)(2)(3)	$1,533,286	$1,951,657	$1,413,978
Future production costs	(550,427)	(555,124)	(342,782)
Future development costs	(144,912)	(164,036)	(90,357)
Future income tax expense(4)	(3,167)	(4,059)	(7,423)
Future net cash flows	834,780	1,228,438	973,416
10% annual discount	(532,442)	(786,226)	(591,393)
Standardized measure of discounted future net cash flows	$302,338	$442,212	$382,023

(1)
2020 proved reserves were derived based on prices of $41.91 per Bbl of crude oil, $(0.06) per Mcf of natural gas and $(1.96) per Bbl of NGL.

(2)
2019 proved reserves were derived based on prices of $54.38 per Bbl of crude oil, $(0.32) per Mcf of natural gas and $(5.19) per Bbl of NGL.

(3)
2018 proved reserves were derived based on prices of $57.92 per Bbl of crude oil, $1.62 per Mcf of natural gas and $10.25 per Bbl of NGL.

(4)
The Company's calculations of the standardized measure of discounted future net cash flows as of September 30, 2020, 2019 and 2018, includes the Company’s obligation for Texas Margin Tax but excludes the effect of estimated future income tax expenses as the Company is a limited liability company and not subject to income taxes.

Principal sources of change in the Standardized Measure are shown below:

	Years Ended September 30,
	2020	2019	2018
	($ in thousands)
Balance, beginning of period	$442,212	$382,023	$143,187
Sales of crude oil, natural gas and NGLs, net	7,328	(85,921)	(58,093)
Net change in prices and production costs	(162,571)	(133,615)	64,892
Net changes in future development costs	(12,348)	(1,226)	(137)
Extensions, discoveries and other additions	17,490	135,350	143,389
Acquisition of reserves	—	1,294	16,505
Revisions of previous quantity estimates	(48,611)	85,381	36,093
Previously estimated development costs incurred	10,448	20,769	20,621
Net change in income taxes	891	(987)	(1,863)
Accretion of discount	44,627	38,509	14,439
Other	2,872	635	2,990
Balance, end of period	$302,338	$442,212	$382,023

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(unaudited)

18.
Quarterly Financial Data – Unaudited

	2020 First Quarter	2020 Second Quarter	2020 Third Quarter	2020 Fourth Quarter
	($ in thousands except per share data)
Total revenues	$29,549	$25,406	$6,019	$15,959
Income from operations	$12,560	$7,232	$(12,158)	$(349)
Net income (loss)	$(6,841)	$75,053	$(27,984)	$(5,084)
Net income (loss) attributable to common unitholders	$(7,705)	$74,176	$(28,874)	$(5,988)
Net income (loss) per common unit:
Basic	$(5.04)	$48.51	$(18.87)	$(3.92)
Diluted	$(5.04)	$36.94	$(18.87)	$(3.92)

	2019 First Quarter	2019 Second Quarter	2019 Third Quarter	2019 Fourth Quarter
	($ in thousands except per share data)
Total revenues	$21,979	$23,527	$26,207	$29,383
Income from operations	$3,941	$9,016	$9,223	$9,308
Net income (loss)	$21,735	$(4,990)	$13,587	$21,534
Net income (loss) attributable to common unitholders	$20,921	$(5,816)	$12,748	$20,683
Net income (loss) per common unit:
Basic	$13.86	$(3.81)	$8.35	$13.54
Diluted	$11.07	$(3.81)	$6.80	$10.74

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